Air Pollution: Allowance Trading Offers an Opportunity to Reduce
Emissions at Less Cost (Chapter Report, 12/16/94, GAO/RCED-95-30).

In 1990, Congress adopted a new regulatory approach to reduce acid rain,
allowing electric utilities to trade allowances to emit sulfur dioxide,
a major cause of acid rain.  Utilities that reduce their emissions below
their required levels can sell their extra allowances to other utilities
to help them meet their requirements.  The Environmental Protection
Agency estimates that this flexible approach to curbing acid rain could
reduce costs significantly because trading allowances can be less costly
than other methods of controlling pollution.  This report discusses the
(1) extent to which trading is expected to cut sulfur dioxide emissions
and compliance costs, and the status of the allowance trading market;
(2) impediments to increased trading of allowances; and (3) implications
of designing a similar approach to curb carbon dioxide emissions.

--------------------------- Indexing Terms -----------------------------

 REPORTNUM:  RCED-95-30
     TITLE:  Air Pollution: Allowance Trading Offers an Opportunity to 
             Reduce Emissions at Less Cost
      DATE:  12/16/94
   SUBJECT:  Air pollution control
             Cost control
             Compliance
             Environmental law
             Environmental policies
             Independent regulatory commissions
             Electric utilities
             Industrial pollution
             Precipitation (weather)
IDENTIFIER:  California Regional Clean Air Incentives Market Program
             DOE Utility Commission Proceedings Participation Program
             EPA National Acid Precipitation Assessment Program
             
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Cover
================================================================ COVER


Report to the Chairman, Environment, Energy, and Natural Resources
Subcommittee, Committee on Government Operations, House of
Representatives

December 1994

AIR POLLUTION - ALLOWANCE TRADING
OFFERS AN OPPORTUNITY TO REDUCE
EMISSIONS AT LESS COST

GAO/RCED-95-30

SO2 Allowance Trading


Abbreviations
=============================================================== ABBREV

  CEM - continuous emissions monitors
  CO2 - carbon dioxide
  DOE - Department of Energy
  EPA - Environmental Protection Agency
  FERC - Federal Energy Regulatory Commission
  GAO - General Accounting Office
  IRS - Internal Revenue Service
  NRRI - National Regulatory Research Institute
  SO2 - sulfur dioxide

Letter
=============================================================== LETTER


B-258437

December 16, 1994

The Honorable Mike Synar
Chairman, Environment, Energy,
 and Natural Resources Subcommittee
Committee on Government Operations
House of Representatives

Dear Mr.  Chairman: 

As you requested, this report examines the emissions trading program
created by the Clean Air Act Amendments of 1990 to control acid rain. 
To increase the effectiveness of this program, we are making several
recommendations to the Administrator of the Environmental Protection
Agency (EPA) and the Chair of the Federal Energy Regulatory
Commission (FERC). 

As arranged with your office, unless you publicly release its
contents earlier, we will make no further distribution of this report
until 30 days after the date of this letter.  At that time, we will
send copies to appropriate congressional committees, the
Administrator of EPA, the Chair of FERC, the Secretary of Energy, and
other interested parties.  We will also provide copies to others on
request. 

Please call me at (202) 512-6111 if you or your staff have any
questions.  Major contributors to this report are listed in appendix
II. 

Sincerely yours,

Peter F.  Guerrero
Director, Environmental
 Protection Issues


EXECUTIVE SUMMARY
============================================================ Chapter 0


   PURPOSE
---------------------------------------------------------- Chapter 0:1

In 1990, the Congress adopted a new regulatory approach to reduce
acid rain, allowing electric utilities to trade allowances to emit
sulfur dioxide (SO2), a major cause of acid rain.  Utilities that
reduce their emissions below the required levels can sell their extra
allowances to other utilities to help them meet their requirements. 
EPA estimates that this flexible approach to curbing acid rain could
reduce costs significantly because trading allowances can be less
costly than other methods of controlling pollution. 

Interested in the potential of such trading, the Chairman of the
Environment, Energy, and Natural Resources Subcommittee, House
Committee on Government Operations, asked GAO to determine (1) the
extent to which trading is expected to reduce SO2 emissions and
compliance costs, and the status of the allowance trading market; (2)
impediments to increased trading of allowances; and (3) the
implications for designing a similar approach to curb carbon dioxide
(CO2) emissions. 


   BACKGROUND
---------------------------------------------------------- Chapter 0:2

Title IV of the Clean Air Act is designed to achieve a 10-million-ton
annual reduction in SO2 emissions from 1980 levels by the year 2010. 
Of this reduction, 8.5 million tons is to come from electric
utilities, the nation's major source of SO2 emissions.  The reduction
is to be implemented in two phases.  In Phase 1, the 110 utility
plants with the highest levels of emissions must reduce their annual
emissions by 3.5 million tons beginning January 1, 1995.  In Phase 2,
beginning January 1, 2000, almost all utilities must reduce their
annual emissions by another 5 million tons.  Unlike the traditional
command-and-control approach, in which the regulator specifies how to
reduce pollution or what pollution control technology to use, title
IV gives utilities flexibility in choosing how to achieve these
reductions.  For example, utilities may reduce emissions by switching
to low-sulfur coal, installing a pollution control device called a
scrubber, or shutting down a plant.  Title IV also allows trading in
emission allowances.  Based on formulas in the law, each utility
receives a fixed number of allowances.  Specifically, an allowance is
an authorization to emit 1 ton of SO2.  Once the allowances are
allocated, the act requires that annual SO2 emissions not exceed the
number of allowances held by each utility plant.  To meet this
requirement, a utility can buy allowances, in effect paying other
utilities to reduce SO2 emissions below their allowed levels.  For
some utilities, buying allowances costs less than other approaches. 


   RESULTS IN BRIEF
---------------------------------------------------------- Chapter 0:3

Reductions in SO2 emissions and compliance costs as a result of
allowance trading between utilities have been limited because little
such trading has occurred to date.  Rather, most utilities are
selecting cost-saving opportunities within their own power plants
first, such as switching from high- to low-sulfur coal, and are
projecting sizable reductions in their SO2 emissions.  These
opportunities, while substantial, do not exhaust the potential for
utilities to reduce their current compliance costs.  For instance,
many utilities could have saved even more by purchasing allowances,
but to date, most of the limited purchases that have occurred were
made at two EPA-sponsored auctions at prices lower than many analysts
predicted.  In the future, substantial cost savings can be realized
if more allowance trading occurs. 

The low level of allowance trading to date is due to several factors. 
First, phasing in emissions reductions over several years reduces the
urgency to buy and sell allowances.  Many potential buyers, for
instance, do not have to reduce emissions until much later, even
though they could save costs by purchasing allowances now.  A second
barrier to more trading results from economic regulation of the
electric power industry.  State public utility commissions and the
Federal Energy Regulatory Commission (FERC) regulate electric
utilities' profits.  To date, these commissions have provided limited
regulatory guidance on trading allowances, even though trading can
lower the costs of electric power by reducing the costs of complying
with requirements.  Another factor impeding trading is the design of
EPA's allowance auction, which produces more than one winning price
and has resulted in prices lower than many analysts expected, causing
confusion among buyers and sellers about the price at which to buy or
sell allowances.  For instance, potential sellers of allowances have
been reluctant to trade at these unexpectedly low prices. 

Some features of the SO2 program would be helpful in designing a
similar approach to reduce CO2.  These features include an overall
requirement for emissions reductions and a monitoring system and
fines high enough to ensure compliance.  Modifying other features,
by, for example, requiring everyone to achieve the same emissions
reductions simultaneously, would provide more incentive to trade and
achieve cost savings.  Also, designing an auction that results in a
single price for allowances could make it clearer what price to
expect, thus encouraging more trading. 


   PRINCIPAL FINDINGS
---------------------------------------------------------- Chapter 0:4


      EMISSIONS AND COMPLIANCE
      COSTS ARE FALLING DESPITE
      LITTLE TRADING
-------------------------------------------------------- Chapter 0:4.1

Reductions in SO2 emissions are projected to exceed Phase 1
requirements, and most utilities plan, for now, to save the resulting
surplus allowances to meet their higher Phase 2 requirements.  At the
same time, utilities are discovering cheaper ways to reduce SO2
emissions within their own plants as a result of title IV's flexible
regulatory approach, thus resulting in falling compliance costs. 
However, not much allowance trading has occurred despite the large
savings reported.  For example, one southeastern utility estimates
saving $300 million by trading. 

Utilities have scant information about allowance prices, and prices
have been lower than expected.  The average price of an allowance at
EPA's last auction was $159, about 33 percent less than forecast. 
Many utilities are retaining their extra allowances rather than
selling them at current prices. 

Given the estimated differences in the costs of reducing SO2 at
electric power plants, more trading between utilities could result in
substantial cost savings and reduce differences in compliance costs
among states.  Western and midwestern utilities typically have lower
costs per ton of SO2 reduced.  Trading should result in allowances
moving from these utilities to those in eastern and southeastern
states, where the costs of reducing emissions are higher. 


      VARIOUS FACTORS HAVE CAUSED
      RELUCTANCE TO TRADE
-------------------------------------------------------- Chapter 0:4.2

Phasing in the allowance market has slowed trading because likely
sellers and buyers of allowances do not have to reduce emissions at
the same time.  In Phase 1, about 14 percent of all affected power
plants must reduce emissions, excluding hundreds of plants that are
not affected until Phase 2.  Plants in Phase 1 generally have lower
costs to reduce emissions per ton of SO2 than plants subject only to
Phase 2, making Phase 1 plants more likely sellers and Phase 2 plants
more likely buyers of allowances.  However, because Phase 2 plants
have more time to reduce emissions, there has been less urgency to
trade and, as a result, lower cost savings. 

Economic regulation of electric utilities has not encouraged trading. 
State public utility commissions and FERC regulate utilities' profits
and recovery of costs, but many commissions have offered little
guidance on whether utilities can share with ratepayers any cost
savings resulting from allowance trading.  Therefore, utilities
hesitate to trade and instead may choose compliance options whose
costs are traditionally recouped in utility rates.  Also, despite the
growing number of wholesale power transactions under its
jurisdiction, FERC has not issued guidance clarifying how it will
treat the cost of allowances in these transactions.  However,
competition in the industry is increasing, and some utilities and
utility commissions, in their desire to lower costs and remain
competitive, are becoming more disposed to trading. 

Other factors have been cited as impeding trading.  The design of
EPA's auction has produced prices that are lower than expected,
causing uncertainty among utilities about the price at which to trade
allowances.  The possibility that EPA will issue regulations on other
air pollutants has added to this uncertainty.  Concern that some
trades might increase SO2 emissions upwind of sensitive areas and
damage those regions has also deterred trading.  In addition, certain
states require utilities to use in-state coal reserves or particular
SO2 control options, which can mean less trading.  Finally, the tax
treatment of allowances may discourage some utilities from trading. 


      CERTAIN FEATURES MAY BE
      APPROPRIATE FOR A CO2
      PROGRAM
-------------------------------------------------------- Chapter 0:4.3

Because of possible environmental and economic benefits, trading
could be part of a regulatory approach to curb CO2 emissions.  In
designing such an approach, some features of the SO2 program would be
helpful, including an overall emissions cap combined with monitoring
of CO2 emissions and the levying of penalties to ensure compliance. 
Like SO2 emissions, CO2 emissions can be monitored for many sources. 

Modifications to make in adapting the SO2 program to CO2 include
eliminating the phased approach, thus requiring all sources to reduce
emissions at the start of the program.  This change would bring all
prospective traders to the table at the same time, increasing the
likelihood of trading and cost savings.  In addition, an auction that
generates a single winning price would provide more accurate prices
and reduce uncertainty about prices. 


   RECOMMENDATIONS
---------------------------------------------------------- Chapter 0:5

GAO recommends that the EPA Administrator and the Chair of FERC take
several actions to encourage trading in SO2 emission allowances and
achieve additional cost savings.  EPA should change the design of the
auction so that it is a single-price auction, and FERC should provide
more guidance on how it will treat allowances in its ratemaking
decisions.  These and other recommendations for improving the SO2
trading market are detailed in chapter 3. 


   AGENCY COMMENTS
---------------------------------------------------------- Chapter 0:6

GAO discussed the findings in this report with the Director and staff
of EPA's Acid Rain Division and the Deputy Director and staff of
FERC's Office of Electric Power Regulation.  Their comments were
incorporated where appropriate.  EPA generally agreed with the facts
presented.  FERC officials believe that it would have been
counterproductive to issue generic guidance in advance of specific
requests from utilities and before the trading program could develop. 
However, they agreed that utility cases currently before FERC may now
offer a vehicle for providing guidance and encouraging trading.  As
requested, GAO did not obtain written agency comments on a draft of
this report. 


INTRODUCTION
============================================================ Chapter 1

Controlling acid rain was a major environmental issue during the
1980s from the standpoint of both air quality and the cost of
regulation.  In 1990, the Clean Air Act was reauthorized; it included
a program to control acid rain. 

Title IV of the 1990 act limits electric utilities' emissions of
sulfur dioxide (SO2)--a major cause of acid rain.\1 It includes a
regulatory system to reduce the costs of meeting these emissions
limits by allowing utilities to choose cost-effective pollution
controls.  In title IV, the Congress combined a regulatory approach
known as emissions trading with compliance measures to ensure that
emissions limits are met.  Figure 1.1 shows substantially lower SO2
emissions expected over the coming decades as a result of title IV. 

   Figure 1.1:  Estimated U.S. 
   Sulfur Dioxide Emissions With
   and Without Title IV

   (See figure in printed
   edition.)

Source:  GAO's illustration based on EPA's data. 

Under this program, utilities receive emissions "allowances" from EPA
that allow them to emit SO2 during or after a specified year.  Each
utility is allotted a specific number of allowances annually; at
year's end, each must have one allowance for each ton of SO2 emitted. 
By the year 2010, the program limits annual SO2 emissions to 8.95
million tons by granting only the corresponding number of allowances
to utilities.\2

To help utilities reduce their costs of complying with lower SO2
limits, they are given flexibility to choose how they will meet the
overall reduction requirements of title IV.  For example, they can
switch to fuel with a lower sulfur content or install pollution
control devices.  They can also buy and sell SO2 allowances.  That
is, if a utility's cost to reduce SO2 emissions is higher than the
market price of allowances, the utility can save money for itself and
its customers by purchasing the necessary number of allowances to
comply with the requirements, instead of fully reducing its
emissions.  For these extra allowances to be available, however,
another utility generally must reduce emissions below its
requirement.  This utility can sell its surplus allowances to
utilities with higher costs at a likely profit for the selling
utility and its customers. 


--------------------
\1 It also limits utilities' emissions of nitrogen oxide, which also
contributes to acid rain. 

\2 No matter how many allowances a utility holds, it will not be
allowed to emit SO2 levels that violate the national or state
health-protection standards for SO2. 


   SULFUR DIOXIDE ALLOWANCE
   TRADING MARKS A DEPARTURE FROM
   TRADITIONAL REGULATION
---------------------------------------------------------- Chapter 1:1

Title IV is regarded as a major turning point because it uses
market-based incentives to implement environmental mandates.  In
particular, the marketable allowance system for controlling acid rain
presumes that cost-effectiveness will be the driving factor in
utilities' decisions.  The new program seeks to reduce the costs of
controlling pollution by providing more flexibility in how emissions
reduction goals are achieved. 

Acid rain is created when the SO2 and nitrogen oxides given off in
the combustion of fossil fuels react in the atmosphere to form
sulfuric and nitric acids.  These acids then fall to the earth,
sometimes hundreds of miles downwind from their source, in wet form,
such as rain or snow, or in dry form, such as small particles or
gases.  Many U.S.  and international scientists have linked acid rain
with damage to sensitive aquatic and forest ecosystems.  The dominant
precursor of acid rain in the United States is SO2 from coal-fueled
power plants.  For example, damage to aquatic systems in New York and
New England are attributed to SO2 emissions from older coal-burning
power plants in the Midwest.  Electric utility plants account for
about 70 percent of the nation's annual SO2 emissions. 

During the 1980s, the Congress considered various proposals to reduce
SO2 emissions.  As part of the debate, some midwestern states sought
to ensure continued use of their high-sulfur coal by wanting to
require and subsidize the use of pollution control
technology--commonly referred to as a "scrubber" since it "scrubs"
out pollution in the power plant's stacks.  As shown in figure 1.2, a
scrubber is a large addition to a power plant.  On the other hand,
some western states saw acid-rain control as a new market opportunity
for low-sulfur coal.  They wanted utilities to use their low-sulfur
coal to reduce acid rain and opposed the required use of scrubbers. 
In response to these competing interests, in 1989 the Bush
administration proposed using an allowance trading system to control
acid rain, and the result was title IV. 



(See figure in printed edition.)Figure 1.2:  Example of a Scrubber

Photo used by permission of Air Products and Chemicals, Inc. 

The allowance trading program differs from the traditional approach
to environmental protection, commonly referred to as "command and
control." Under a command-and-control approach, sources of pollution
were required to install certain control technology or meet
plant-specific emissions reductions across all affected sources. 
According to critics of this regulatory approach, command-and-control
is needlessly costly because it imposes similar reduction
requirements on sources that sometimes have very different control
costs, rather than concentrating reductions at the sources with the
lowest control costs.  In addition, sources can comply with the
regulation without achieving the actual emissions reductions needed
to meet the overall environmental objectives.  For example, in some
cities that have not attained the standard for ozone emissions at
ground level, economic growth can lead to an increased number of
sources of ozone.  Even if all these sources comply with the
regulation and emit relatively low levels of ozone, the overall
emissions can be too high. 

Title IV offers a different approach for controlling pollution. 
After setting the overall reductions in emissions to be achieved, the
Congress defined each source's individual emissions limit.  These
allocations added up to meet a total emissions cap.  Sources must
install continuous emissions monitors (CEM) and regularly report
their actual emissions to EPA.  If they violate their emissions
limits, they forfeit allowances to cover the excess emissions and pay
automatic fines set at several times the estimated average cost of
compliance.  However, the allowance trading system also rewards
utilities that go beyond the law's requirements by enabling them to
earn profits from the sale of their extra allowances.  Sources that
reduce emissions below their allocations can sell their extra
allowances to others that face higher costs to reduce emissions. 

According to the legislative history of title IV as described in a
Senate Committee report,\3 the allowance trading system presented
several benefits.  First, the flexibility of the allowance system was
expected to minimize the overall cost of the program and
significantly reduce regional costs of compliance.  Second, the
allowance system was expected to result in emissions reductions
greater than those required or reductions earlier than anticipated,
or both.  Third, the allowance system would allow cost-effective
compliance while accommodating growth in the demand for energy. 
Fourth, the incentives provided by the market in allowances were
expected to stimulate innovations in technologies that would reduce
emissions and conserve energy. 


--------------------
\3 Three Years Later:  Report Card on the 1990 Clean Air Act
Amendments, U.S.  Senate Committee on Environment and Public Works
(Nov.  15, 1993), pp.  71-72. 


   PROGRAM'S FEATURES ENSURE THAT
   ENVIRONMENTAL GOALS WILL BE MET
---------------------------------------------------------- Chapter 1:2

Given the program's design, title IV virtually ensures that the
desired amount of emissions reductions will occur, whether or not the
emissions trading system functions as expected.  The Congress
expected the system of marketable allowances to reduce the overall
costs of compliance and accommodate growth in the demand for
electricity.  However, the emissions limits must be met even if the
trading system does not function as expected. 


      NATIONWIDE EMISSIONS CAP
-------------------------------------------------------- Chapter 1:2.1

The acid rain control program imposes a nationwide emissions cap,
reducing annual SO2 emissions from utilities by an estimated 8.5
million tons from 1980 levels, beginning January 1, 2000.  This
reduction is implemented in two phases.  Phase 1, beginning January
1, 1995, applies to the 110 highest-emitting utility plants and
mandates that annual emissions be reduced by about 3.5 million tons. 
This phase primarily affects large midwestern coal-fired plants. 
Phase 2, beginning January 1, 2000, requires an additional annual
reduction of about 5 million tons, imposing a nationwide annual
emissions cap of 8.95 million tons of SO2.  Phase 2 applies to the
Phase 1 plants and virtually all of the approximately 700 remaining
utility plants throughout the nation, which are generally cleaner and
smaller.  Figure 1.3 shows the geographic distribution of the
utilities affected in these two phases. 

   Figure 1.3:  Geographic
   Distribution of Utility Plants
   Under Phases 1 and 2

   (See figure in printed
   edition.)

   Source:  GAO's illustration
   based on EPA's data.

   (See figure in printed
   edition.)


      EMISSIONS ALLOWANCE SYSTEM
-------------------------------------------------------- Chapter 1:2.2

The program's mechanism for allocating each utility's emissions
reductions is an extensive system of permits and emissions
allowances.  An allowance is a limited authorization to emit a ton of
SO2.  Allowances are allocated on the basis of specific formulas
contained in the law.\4 The allowances may be traded or banked for
future sale or use.  Utilities generally must either reduce emissions
or acquire allowances from another utility to make up the shortfall. 
With certain exceptions, new power plants--those that began operation
after title IV's enactment--have to obtain allowances from those
already holding allowances.  Within the allowance system, incentives
are provided for the use of conservation and renewable energy sources
and the early use of scrubbers.  For example, Phase 1 units that
installed scrubbers could have obtained bonus allowances from a
reserve of 3.5 million held by EPA.  Anyone may trade in
allowances--including brokers, environmental groups, and private
citizens--and trading can be conducted nationwide with no geographic
restrictions.  No matter how many allowances a utility holds, it will
not be allowed to emit SO2 levels that violate the national or state
health-
protection standards for SO2. 


--------------------
\4 Allowances are allocated to each utility according to its
generating capacity and historical emissions during the base period
1985-87.  Each combustion unit, or boiler, in a power plant is
allocated allowances.  A utility can have multiple power plants, and
plants can have one or more combustion units. 


      CONTINUOUS EMISSIONS
      MONITORING EQUIPMENT
-------------------------------------------------------- Chapter 1:2.3

Each utility must install EPA-certified CEM equipment and regularly
report its emissions to EPA.  This monitoring and reporting
requirement ensures that actual emissions are accurately tracked.  At
the end of the year, EPA grants utilities 30 days to obtain the
allowances necessary to cover their actual emissions during the
previous year.  After this grace period, EPA deducts allowances from
a utility's allowance holdings in an amount equal to its recorded
emissions.  The deduction of allowances, as well as the issuance,
transfer, and tracking of allowances, is conducted through EPA's
automated allowance tracking system.  Operating like a bank, this
system tracks the allowances held by utilities and any other
companies, organizations, or individuals possessing allowances.  The
tracking system provides EPA with a way to determine compliance by
ensuring that actual emissions do not exceed the available
allowances. 


      AUTOMATIC PENALTY
-------------------------------------------------------- Chapter 1:2.4

Title IV provides that if a utility does not have enough allowances
to cover its emissions, it is subject to an automatic penalty of
$2,000 per ton of excess SO2, indexed yearly to inflation.  This
amount is several times more than the estimated average cost per ton
of reducing SO2 emissions.  A utility that does not comply also has
its allowance holdings reduced in the next year by one allowance for
each excess ton of SO2 emitted. 


      PERMITS AND COMPLIANCE PLANS
-------------------------------------------------------- Chapter 1:2.5

Finally, each utility must file a permit and compliance plan with EPA
describing how it will meet its emissions limits.  In Phase 1, EPA is
responsible for issuing permits and reviewing the utilities'
compliance plans; in Phase 2, EPA-approved state or local agencies
will issue permits and review the plans.  Permit applications and
compliance plans for Phase 1 were due on February 15, 1993, and
permits and compliance plans for Phase 2 will be required by January
1, 1996.  Utilities can reduce emissions by purchasing allowances
from other utilities, banking extra allowances for future use,
switching from high-sulfur coal to low-sulfur coal or natural gas,
installing scrubbers, shifting some electricity production from
dirtier plants to cleaner ones, and encouraging more efficient
electricity use by customers.  Title IV also maintains the authority
of state public utility commissions and the Federal Energy Regulatory
Commission (FERC) to regulate utilities' electric rates.  Generally,
state utility commissions regulate all retail transactions of
electric power, while FERC has authority over most wholesale
transactions, which account for about 10 percent of all the
electricity generated. 


   TRADING OF ALLOWANCES HAS
   ALREADY BEGUN
---------------------------------------------------------- Chapter 1:3

Since the passage of the 1990 amendments, EPA has issued rules to
implement the program.  It also held two allowance auctions intended
to stimulate trading. 

Many of these rules were required within 18 months of enactment of
the legislation.  This deadline was tight because the utilities
needed time to develop and implement strategies to meet the January
1, 1995, date for complying with Phase 1 requirements.  Within 24
months of the statute's enactment, EPA had promulgated all of the
major rules governing the SO2 allowance system, including allowance
allocations for over 2,000 Phase 2 utility units, requirements for
CEMs, and penalties for noncompliance.  Since Phase 1 allowance
allocations were listed in title IV, trading was permitted upon
passage of the 1990 amendments in November 1990.  Figure 1.4 depicts
the timetable for trading allowances up through the year 2000. 

   Figure 1.4:  Timetable for
   Trading Sulfur Dioxide
   Allowances Through Beginning of
   Phase 2

   (See figure in printed
   edition.)

To stimulate trading early in the program and ensure the availability
of allowances for utilities needing them, title IV required EPA to
hold allowance auctions once a year.  As mandated by title IV, in
both Phase 1 and Phase 2, 2.8 percent of the allowances are withheld
from utilities each year for direct sale by EPA and for sale at this
auction.\5 At the auction, EPA initially offers 150,000 allowances
for sale; from 1996 to 1999, it will offer 250,000 allowances;
thereafter, it will offer 200,000 annually.  The first two auctions
occurred in March 1993 and 1994. 

Anyone can participate in these auctions as a buyer or seller, and
private parties selling allowances may specify a minimum sale
price.\6 Under the Clean Air Act, EPA has the authority to delegate
the administration of these auctions, and EPA chose the Chicago Board
of Trade to administer the auctions until 1996. 


--------------------
\5 Proceeds from the auction are subsequently returned on a pro rata
basis to the utilities from which they are withheld.  In addition, a
separate direct sale of 25,000 allowances is held at a fixed price of
$1,500 each, indexed yearly to inflation.  Beginning in Phase 2,
50,000 allowances will be offered annually in this sale.  Independent
power producers have guaranteed rights to these allowances under
certain conditions.  To date, no allowances have been sold at these
sales; unsold allowances are subsequently offered at the EPA auction. 

\6 By statute, EPA does not set a minimum price for its allowances. 


   OTHER EMISSIONS TRADING
   PROGRAMS HAVE BEEN TRIED
---------------------------------------------------------- Chapter 1:4

The use of market approaches to environmental problems is not new.\7
The concept of the SO2 allowance trading program grew out of EPA's
trading programs for air emissions and lead rights.  In addition,
after years of failing to meet national air quality goals, several
cities and states are considering emissions trading as a way to deal
with problems of ground-level ozone, or smog. 

EPA introduced limited forms of flexibility in trading emissions into
its regulations under the Clean Air Act in the late 1970s.  It
established certain mechanisms--so-called "bubbles," offsetting,
banking, and netting--for trading air emissions between sources in
order to allow flexible or lower-cost compliance with requirements. 
Under EPA's regulatory scheme, bubbles were created so that adjacent
point sources of emissions--for example, several emissions stacks
within a single facility--could be managed for compliance purposes as
if they were one source.  The offset mechanism permitted the siting
of new polluting sources or increased pollution at existing sources
in areas that did not comply with the ambient air quality standards. 
Under this mechanism, owners or operators of those sources could
offset increased pollution by obtaining reductions in emissions of
the same pollutant from other existing sources in the area--usually
at a greater than one-to-one ratio.  Sources could also "bank"
reductions in emissions for later sale or use.  Finally,
modifications to existing facilities were exempted from requirements
for new sources if total emissions did not increase significantly
("netting"). 

EPA's lead trading program helped cut down petroleum refiners' costs
of compliance with tighter lead standards for gasoline.  This program
existed from 1982 through 1987.  Refiners producing gasoline with
less lead than mandated by the stricter standards could sell or bank
lead rights.  Refiners that incurred higher costs as a result of the
tighter standards were able to ease the transition by purchasing lead
rights that would allow them to produce gasoline with more lead than
they could otherwise have done. 

To clean the air while limiting compliance costs, several states and
localities are currently considering or implementing market-based
approaches to pollution control.  For example, Illinois has proposed
trading as a way to curb smog in Chicago, and the Northeast Ozone
Transport Commission, comprising 12 northeastern and mid-Atlantic
states and the District of Columbia, is considering trading for
pollutants that cause smog.  In addition, the South Coast Air Quality
Management District, responsible for the city of Los Angeles and the
surrounding counties, plans to control smog through a trading
program, known as the Regional Clean Air Incentives Market. 

After several decades of trying to control its smog, Los Angeles
still suffers from the dirtiest air of any urban area in the United
States, and pollution must be cut in half to meet federal and state
laws on air quality.  The Regional Incentives Market program, which
the management district adopted in October 1993, requires that
overall emissions of two main industrial pollutants, nitrogen oxides
and sulfur oxides, be reduced gradually every year.  However,
facilities may buy and sell emissions rights among themselves, rather
than conforming to command-and-control regulation.  Nearly 400
businesses in the Los Angeles area are included in this program, and
trading has begun, although slowly.  Market observers say that
trading will probably remain limited until 1996, when tighter
emissions limits that are more expensive to achieve increase the
demand for emissions rights. 


--------------------
\7 See A Market Approach To Air Pollution Control Could Reduce
Compliance Costs Without Jeopardizing Clean Air Goals (GAO/PAD-82-15,
Mar.  23, 1982). 


   OBJECTIVES, SCOPE, AND
   METHODOLOGY
---------------------------------------------------------- Chapter 1:5

In May 1992, the Chairman of the Environment, Energy, and Natural
Resources Subcommittee, House Committee on Government Operations,
requested that we review the SO2 allowance trading program and its
potential to curb acid rain at less cost to the nation.  On the basis
of subsequent discussions with the Chairman's office, we agreed to
focus on the following questions: 

What is the extent to which trading is expected to reduce SO2
emissions and compliance costs, and what is the status of the
allowance trading market? 

What are the impediments to increased allowance trading? 

What are the implications for designing a similar approach to curtail
carbon dioxide (CO2) emissions? 

To examine the extent to which trading is expected to reduce SO2
emissions and compliance costs, we contracted with Van Horn
Consulting, an economic consulting firm.  We did not verify the
consultant's calculations because of the confidential nature of the
utilities' cost data that the contractor used.  However, we discussed
the requisite quality control procedures with the team that conducted
the analysis.  Additional details on the consultant's methodology and
results are presented in appendix I. 

To evaluate the extent to which trading is expected to reduce SO2
emissions, the consultant projected annual emissions for power plants
located in each state with Phase 1 utilities, using the most recent
information available on these utilities' compliance strategies and
costs.  In addition, we reviewed existing studies by the National
Acid Precipitation Assessment Program, ICF Resources, Inc., and the
Congressional Research Service to evaluate the probable impact of
allowance trading on sensitive regions.  We interviewed environmental
groups such as the Adirondack Council, the National Resources Defense
Council, the Environmental Defense Fund, and the Sierra Club to
obtain their views on the program.  Using the data on completed
trades described below, we mapped the geographic distribution of the
trades made to date by state. 

To assess the extent to which trading is expected to reduce
compliance costs, we examined, based on the results of the
contractor's work, the cost reductions resulting from potential
trading scenarios at the national, state, and utility levels.  We
examined data on compliance costs for all the regulated utilities to
determine whether sufficient variation in costs exists to warrant
trading.  After finding that most trading is occurring within
utilities rather than between them, the consultant estimated the
potential reductions in total costs that would result from increased
trading between nonaffiliated utilities.  To determine whether
trading is reducing the burden in those states where utilities face
higher costs of compliance, we estimated the potential cost
reductions from trading for each state in the program.  Finally, we
conducted case studies at utilities that have been trading to
evaluate how completed trades have affected their costs. 

To determine the status of the allowance trading market, we reviewed
all known allowance trades made between utilities through September
1994 and all allowance transactions at the EPA auctions.  We
monitored EPA's allowance tracking system for trades on the system. 
For trades not on the system, we interviewed allowance brokers,
traders, and market analysts and monitored the electric utility trade
press for reports of completed transactions.  We analyzed studies on
trading prepared by the Electric Power Research Institute, the
Department of Energy (DOE), EPA, the National Regulatory Research
Institute (NRRI), consulting firms, and environmental groups.  We
attended industry and regulatory conferences on allowance trading and
contacted all utilities believed to have traded allowances to confirm
the dates and volume of the transactions. 

To learn what factors have impeded trading and identify the
implications for designing a similar approach to control CO2, we
conducted case studies with market participants.  For these case
studies, we conducted interviews with officials of nine utilities in
Illinois, Wisconsin, New York, Georgia, and North Carolina and with
each of these states' public utility commission and environmental
agencies.  In addition, we interviewed officials of EPA, FERC, DOE,
and the Internal Revenue Service (IRS).  We supplemented the case
studies with literature reviews and discussions with emissions
trading experts and allowance market observers such as NRRI.  We also
held extensive discussions with electric utility groups,
representatives of the scrubber and coal industries, environmental
organizations, market analysts, allowance brokers, and university
economists.  In addition, we discussed the new Regional Clean Air
Incentives Market in Los Angeles, California, with regulatory
officials, market observers, and program participants. 

We conducted our review between October 1993 and October 1994 in
Washington, D.C.; Los Angeles, California; and the five states
included in the case studies described above.  We performed our work
in accordance with generally accepted government auditing standards. 
We discussed the factual information in the report with the Director
and staff of EPA's Acid Rain Division and the Deputy Director and
staff of FERC's Office of Electric Power Regulation.  Their comments
were incorporated where appropriate.  As requested, we did not obtain
written agency comments on a draft of this report. 


UTILITIES ARE REDUCING SULFUR
DIOXIDE EMISSIONS AT LOWER COSTS
BUT HAVE BEEN RELUCTANT TO TRADE
ALLOWANCES
============================================================ Chapter 2

Many utilities are taking advantage of falling compliance costs to
reduce SO2 emissions below the mandated Phase 1 limits.  Costs are
falling as a result of competition between compliance options spurred
by title IV's flexible regulatory approach.  Many Phase 1 utilities
plan to reduce emissions below allowed levels and, for now, save the
surplus allowances for future compliance.  Some utilities could
reduce their compliance costs even further by purchasing allowances,
but few have done so.  As a result, the allowance trading market is
struggling to develop.  Uncertainty among utilities about the price
at which they should buy or sell allowances has compounded their
reluctance to trade.  On the basis of the estimated differences in
the costs of reducing SO2 at electric power plants, trading between
utilities could result in substantial cost savings in the future.  In
addition, these estimates suggest that many states facing higher
compliance costs could benefit from the cost reductions possible from
more trading. 


   SULFUR DIOXIDE EMISSIONS ARE
   EXPECTED TO FALL BELOW CLEAN
   AIR ACT'S LIMITS IN PHASE 1
---------------------------------------------------------- Chapter 2:1

According to our consultant's estimates, by 1997 annual SO2 emissions
will be nearly 30 percent less than the Phase 1 annual allowance
allocations set by the Clean Air Act.  As noted in chapter 1, Phase 1
begins January 1, 1995, and applies to 110 power plants.  Many
utilities currently plan to save most of these extra emissions
reductions as "surplus" allowances for use during Phase 2, beginning
January 1, 2000.  Figure 2.1 compares the projected annual emissions
in Phase 1 with the emissions that would have occurred in the absence
of title IV and with the mandated limits. 

   Figure 2.1:  Projected Annual
   Emissions in Phase 1

   (See figure in printed
   edition.)

Note:  Data are 1997 projections for Phase 1 units only. 

Title IV allows utilities to save surplus allowances for future use
or sale.  Utilities' decisions to reduce SO2 more than required in
Phase 1 are based on estimates that curtailing SO2 emissions is less
costly in Phase 1 than it will be in Phase 2.\1 "Banking" the surplus
provides firms with further flexibility.  Firms that expect to
install costly scrubbers in Phase 2 can delay installation a few
years by using their surplus allowances from Phase 1 to comply. 
Others expect to sell their surplus at higher allowance prices in
Phase 2 than in Phase 1.  Utilities will use most of the allowances
freed up by these extra emissions reductions early in Phase 2,
according to an industry projection. 


--------------------
\1 Phase 1 limits utilities' emissions to 2.5 pounds of SO2 per
million BTUs (British thermal units) of heat consumption.  Phase 2
cuts the emissions rate to 1.2 pounds of SO2.  Because the costs of
reducing emissions tend to rise for each extra pound of SO2 abated at
a facility, meeting Phase 1 limits is less expensive per pound than
meeting Phase 2 limits. 


   COSTS ARE FALLING AS UTILITIES
   TAKE ADVANTAGE OF MORE
   COMPLIANCE CHOICES
---------------------------------------------------------- Chapter 2:2

Utilities are taking advantage of their flexibility under title IV of
the Clean Air Act to choose less costly ways to reduce emissions.  As
described in chapter 1, utilities may now switch to low-sulfur coal,
retire an old plant, purchase allowances from other utilities, or
install a scrubber, among other options.  This gives utilities the
flexibility to choose the cheapest measure.  A utility system may
also lower costs through internal trading, cutting back emissions in
one power plant and using the resulting allowances to cover emissions
in another plant.  The utilities' ability to choose among various
compliance measures is resulting in lower prices for low-sulfur coal,
scrubbers, and allowances as vendors compete to fulfill utilities'
compliance needs. 

Phase 1 utilities are selecting a variety of measures to reduce SO2. 
However, few are purchasing allowances as their primary means of
compliance despite evidence that purchasing allowances could reduce
their compliance costs.  For instance, on the basis of the estimated
costs of reducing SO2 at their electric power plants, many Phase 1
utilities face costs significantly higher than current allowance
prices.  (See app.  I, fig.  I.1.) As shown in figure 2.2, 55 percent
of Phase 1 plants plan to switch to low-sulfur coal and 16 percent
intend to install scrubbers, but only 3 percent expect to purchase
allowances.  Only one utility has bought allowances as its primary
means of compliance.  Others plan to transfer allowances internally;
that is, they will use surplus allowances generated by their units
with lower costs of reducing emissions to offset emissions from their
units with higher costs of pollution abatement. 

   Figure 2.2:  Options Selected
   for Phase 1 Compliance

   (See figure in printed
   edition.)

\a Four plants are both switching coals and building scrubbers. 

\b Compliance is achieved by overcompliance in another unit, or the
plant was already in compliance before Phase 1 began. 

Source:  NRRI's analysis of data from the Electric Power Research
Institute. 

The flexibility to choose different measures to reduce pollution is
leading to greater competition among the options.  For instance,
according to ICF Resources, Inc., in 1990 most analysts projected
prices for low-sulfur coal to reach $40 per ton by 1995.\2 Currently,
prices are less than $25.  Scrubber vendors also report falling
prices, up to 50 percent since 1990.  Allowance prices, which reflect
the falling costs of using low-sulfur coal and scrubbers, are also
much lower than predicted.  As discussed below, additional factors
may be affecting allowance prices. 

Before the passage of the Clean Air Act Amendments of 1990, scrubber
vendors expected 35 to 40 scrubber contracts in Phase 1.  With
utilities' newly acquired flexibility to choose from among competing
options, vendors now expect only 13 to 14 scrubber contracts.\3 For
example, Illinois Power canceled scrubber construction in progress
and purchased allowances to meet the lower SO2 limits.  Industry
officials also expect fewer scrubbers in Phase 2 because of surplus
allowances carried over from Phase 1.  Two southeastern utilities,
Carolina Power and Light and Duke Power, are purchasing allowances to
postpone or eliminate the need for scrubbers in Phase 2.  State
public utility commissions and utilities we visited stated that other
firms have purchased allowances and switched to low-sulfur coal to
avoid the added cost of building and operating scrubbers.  In
response to this decreasing demand for their product, scrubber
vendors have introduced innovations to reduce costs, such as larger
absorbers, new anticorrosive materials, and processes to eliminate
waste streams from scrubbers by converting them into marketable
products.  The higher SO2 removal rates of some scrubbers will result
in overcompliance and extra allowances for sale, further reducing net
costs.  To lower utilities' costs, one company is offering to operate
and maintain the scrubbers that it sells to utilities, charging a
specified fee per ton of SO2 removed. 

The market for low-sulfur coal is getting larger as a result of title
IV.  Low-sulfur western coal is penetrating midwestern and eastern
markets in large quantities.  For instance, Georgia Power is
purchasing Powder River Basin coal from Wyoming.  Railroads have
increased their capacity to meet the resulting increased demand for
transportation of western coal.  In addition, eastern low-sulfur coal
is being supplied at lower prices than anticipated as a result of
increased mining productivity, lower rail rates, and competition from
western coals. 


--------------------
\2 This estimate is for central Appalachian compliance coal, an
industry benchmark.  ICF Resources, Inc., is a consulting firm. 

\3 A contract may include one or more scrubber units. 


   MOST UTILITIES HAVE YET TO
   TRADE WITH OTHER FIRMS
---------------------------------------------------------- Chapter 2:3

Although reducing SO2 emissions costs much more at some utilities
than at others, few of the utilities with higher abatement costs have
purchased allowances from those with a surplus to avoid incurring
these higher costs.  Utilities are uncertain about the price at which
to buy or sell allowances because of limited and conflicting price
information.  Few trades have occurred, and most trades are now
occurring around the time of the annual EPA auctions.  While these
auctions are providing some information about allowance prices, these
prices have been much lower than most analysts predicted and
generally lower than the prices of the allowances traded between
utilities. 


      FEW UTILITIES ARE BUYING
      ALLOWANCES DESPITE POTENTIAL
      COST SAVINGS
-------------------------------------------------------- Chapter 2:3.1

Few utilities are purchasing allowances from other utilities as a
compliance strategy, even though potentially large savings are
possible.  Most of the utilities that can avoid higher abatement
costs by purchasing allowances from other firms have not done so.  Of
269 utilities that could be trading, only 12 have bought more than
5,000 allowances from another utility.  Two firms--Illinois Power and
Carolina Power and Light--are responsible for 61 percent of the
allowances purchased by utilities from other firms. 

Figure 2.3 suggests that many utilities could avoid higher compliance
costs by buying allowances from other firms.  This figure presents
the estimated incremental costs per ton of SO2 abated for each of the
269 utilities planning compliance strategies for Phase 2.\4 For
instance, approximately 80 utilities--30 percent of the total--have
estimated incremental compliance costs above the current allowance
price.\5

   Figure 2.3:  Estimated Costs of
   Abatement Compared With
   Allowance Price for Utilities
   in Phase 2



   (See figure in printed
   edition.)

Note:  170 potential sellers have incremental costs at or near zero. 
Costs are estimated for the year 2002, assuming no interutility
trading, and are in 1992 dollars per ton. 

Figure 2.4 shows the dates and sizes of trades that have occurred
since trading began.  Utilities and brokers we interviewed stated
that expectations of lower prices at EPA auctions cause more trading
near the auctions and few otherwise.  For instance, in the period
surrounding the last auction, seven trades occurred for approximately
312,000 allowances.  Since that time, only one trade has occurred. 
In total, only 21 trades of 5,000 allowances or more have occurred
between utilities. 

   Figure 2.4:  Allowance Trading
   to Date

   (See figure in printed
   edition.)

Note:  Includes interutility trades and sales to brokers and
nonutilities.  Does not include utilities' internal trades. 

In trades that we analyzed in our case studies, utilities projected
large cost savings.  For example, Central Illinois Public Service
stated that it will save $225 million as a result of allowance
trading combined with title IV's flexibility to choose other control
options.  Illinois Power has reported saving $91 million by
purchasing allowances instead of installing scrubbers.  Similarly,
Duke Power projects saving $300 million, and Wisconsin Electric Power
Company estimates saving almost $90 million by avoiding the
installation of scrubbers.  Carolina Power and Light expects to
reduce its future compliance costs by two-thirds as a result of
purchasing allowances. 


--------------------
\4 The incremental cost is the cost of reducing a ton of SO2 using
the last abatement option required to attain compliance. 

\5 Since utilities have already largely determined which compliance
measures they will use to meet Phase 1 emissions limits, additional
trading is likely to take place to meet Phase 2 limits. 


      SCARCE PRICE INFORMATION AND
      LOWER-THAN-EXPECTED AUCTION
      PRICES CREATE MARKET
      UNCERTAINTY
-------------------------------------------------------- Chapter 2:3.2

Because few trades have occurred, the amount of reliable information
on allowance prices has been limited.\6 Compounding this problem is
the fact that prices on trades completed outside of EPA's auctions
have often been withheld from the public.  EPA's auctions are
intended to accelerate the transition to a "liquid" market--one in
which there are many transactions.  Such a market provides the most
reliable data on the market price of a commodity.  However, the two
EPA auctions held to date have resulted in allowance prices that were
lower than most analysts predicted and lower than the prices of
trades between utilities.  The result is continuing uncertainty among
utilities as to what the allowance price should be.\7

Prices are determined by trades between firms and by the results of
the EPA auctions.  As figure 2.5 shows, allowance prices have varied
considerably thus far.  Higher prices set by trades between firms
have been followed by lower prices at each of the two EPA auctions. 
Prices have also been lower than EPA projected in 1990.  As figure
2.6 indicates, EPA auction prices are lower than utilities might have
expected on the basis of price information available earlier in the
program. 

   Figure 2.5:  Trading Price of
   Allowances

   (See figure in printed
   edition.)

Source:  GAO's illustration based on data from the TERRA Group,
Washington, D.C. 

   Figure 2.6:  Allowance Prices
   and Estimates

   (See figure in printed
   edition.)

\a As noted in chapter 1, the Clean Air Act requires EPA to offer
allowances for direct sale at $1,500, indexed to inflation. 

\b EPA estimated the incremental cost of allowances to be
approximately one-half of the direct sale price when trading began. 

\c AERX Survey of Utilities. 

\d Integrated Analysis of Fuel, Technology, and Allowance Markets: 
Electric Utility Responses to the Clean Air Act Amendments of 1990,
Electric Power Research Institute (EPRI), TR-102510 (Aug.  1993), pp. 
5-11, 5-13. 

\e The average winning bids at EPA's two auctions were $156 (1993)
and $159 (1994). 

Our discussions with utility officials and market analysts revealed
that buyers and sellers differ widely on what the market price should
be.  Many believe this difference is largely the result of the design
of EPA's auction, which is discussed in chapter 3 of this report. 
Apparently, many potential buyers are reluctant to pay more than the
auction price, while most potential sellers are unwilling to accept
the auction price.  In fact, less than one-half of 1 percent of
allowances offered by private sellers at EPA's two auctions were
sold, as shown in table 2.1.  Private sellers--mostly
utilities--expect higher prices. 



                          Table 2.1
           
            Allowances Sold by Private Sellers and
                   EPA at the Two Auctions

                                   Private
                                   sellers               EPA
----------------------------  ------------  ----------------
Allowances offered                 280,511           325,000
Price range of offers          $10 -$1,900  No minimum price
Number sold                          1,210           325,000
Percentage of total sold              0.43               100
------------------------------------------------------------

--------------------
\6 This lack of price information is typical for a "thin" market--one
with few transactions. 

\7 In contrast, utilities can readily obtain the current market price
of a scrubber or a ton of low-sulfur coal. 


   MORE TRADING COULD REDUCE THE
   COSTS OF MEETING SULFUR DIOXIDE
   MANDATES
---------------------------------------------------------- Chapter 2:4

Projected cost savings depend on the level of trading.  In 1992, EPA
estimated that the costs of achieving compliance would be up to 50
percent lower than the costs under command and control, depending on
how much trading occurred between utilities.  Since then, the
Electric Power Research Institute has estimated that compliance costs
could fall by up to 57 percent.  More recent modeling estimates made
by our consultant suggest similar possible savings in Phase 2. 
According to these estimates, for the year 2002, Phase 2 emissions
reductions would cost as much as $4.5 billion per year if utilities
were forced to use the types of controls typically prescribed under
more traditional regulation.  Instead, under title IV's more flexible
approach, utilities are estimated to spend about $2.6 billion per
year if they restrict themselves to internal trading.  Costs are
estimated to fall as low as $1.4 billion per year if utilities trade
with one another until all cost savings opportunities are realized. 

Most utilities are planning to trade their allowances internally to
reduce compliance costs, and it seems likely that title IV's
regulatory flexibility will lead to substantial cost savings. 
However, as shown in figure 2.7, based on estimates for the year
2002, another $1.2 billion per year in estimated savings could be
possible if maximum interutility trading occurs.\8

   Figure 2.7:  Estimated Annual
   Cost of Compliance Under Three
   Trading Scenarios

   (See figure in printed
   edition.)

Note:  Costs are estimated for 2002. 


--------------------
\8 Similarly, our consultant estimated annual cost savings of nearly
$1.1 billion for the year 2009 if utilities move from internal
trading to maximum interutility trading. 


      MORE TRADING COULD RESULT IN
      GREATER COST SAVINGS FOR
      STATES
-------------------------------------------------------- Chapter 2:4.1

Modeling done for GAO suggests that utilities in some states could
reduce compliance costs through greater interutility trading.  For
example, with interutility trading, estimated Phase 2 compliance
costs of Pennsylvania plants could be as much as $135 million lower
in the year 2002 than if these plants relied on internal trading
alone.  Similarly, estimated costs for utility plants in Indiana and
New York could be reduced by over $75 million.  Table 2.2 shows which
states could benefit most from interutility trading in the year 2002. 
The estimated cost savings in table 2.2 can occur if utilities with
higher estimated costs of reducing SO2 purchase allowances from
utilities with lower estimated costs.\9 A complete list of the
states' costs and potential savings from trading appears in appendix
I. 



                          Table 2.2
           
            States' Estimated Costs and Potential
            Savings From Trading in the Year 2002

                  (Millions of 1992 dollars)

                            Costs with  Costs with  Potentia
                              internal  interutili         l
State                          trading  ty trading   savings
--------------------------  ----------  ----------  --------
Pennsylvania                      $270        $135      $135
Indiana                            319         235        84
New York                            32      (46)\a        78
Florida                            135          75        60
Delaware, New Jersey,              114          56        58
 Maryland, District of
 Columbia\b
Illinois                           182         132        50
Wisconsin                            2      (48)\a        50
Alabama                            127          78        49
North Carolina                     107          62        45
Louisiana, Mississippi\b            59          14        45
------------------------------------------------------------
Note:  Electricity rates in each state may not necessarily be
affected as shown because utility service territories cross state
boundaries. 

\a Parentheses indicate opportunities for states to sell enough
allowances to offset their costs and make a net profit. 

\b States with few utilities have been aggregated. 


--------------------
\9 These state estimates assume a national market-clearing price of
$317 per ton. 


   EXTRA EMISSIONS REDUCTIONS IN
   PHASE 1 MAY BENEFIT
   ENVIRONMENTALLY SENSITIVE AREAS
---------------------------------------------------------- Chapter 2:5

Our modeling for Phase 1 and analysis of the trades to date suggest
that utilities' responses to trading could benefit environmentally
sensitive areas in the Northeast.  Our projections show that
utilities in Phase 1 will reduce SO2 emissions approximately 2
million tons below annual allowance allocations.  In addition,
utilities in Ohio, which has the highest emissions of all Phase 1
states, are projected to emit 31 percent less SO2 than their Phase 1
allocations.\10 Figure 2.8 shows the 10 states with the largest
projected extra reductions in tons per year.  (See app.  I, table
I.3, for a complete list of the states' expected reductions in Phase
1.)

   Figure 2.8:  States With
   Largest Projected Extra
   Emissions Reductions in Phase 1

   (See figure in printed
   edition.)

Studies on the environmental impact of trading by ICF Resources,
Inc., the National Acid Precipitation Assessment Program, and the
Congressional Research Service suggest that interutility trading
should encourage some midwestern states to be net sellers of
allowances.\11 Midwestern utilities were considered the most likely
to install scrubbers because of their low cost per ton of SO2
removal.\12 Utilities we contacted believe that regions with higher
per-ton scrubbing costs and higher projected growth in electricity
demand, such as the Southeast, would be net buyers of allowances. 
This is consistent with EPA's 1993 base case forecast of emissions by
state through the year 2010.\13

In most cases, as shown in figure 2.9, trades to date appear to
support projections that midwestern states will be net sellers and
southeastern states net buyers of allowances.  Although too few
trades have occurred for these data to be conclusive, net sellers
have been western, midwestern, and northeastern states.  Net buyers
have been mostly southeastern states, with the exceptions of Indiana
and Illinois.  However, allowances are financial assets as well as
compliance tools.  Purchases may be occurring for various reasons,
and current purchases will not necessarily result in future emissions
by the buyer.  For example, coal suppliers and allowance brokers will
probably sell or trade their allowances in the future, and some
utilities buying at current low prices may sell them in the future at
projected higher prices. 

   Figure 2.9:  Net Sellers and
   Buyers to Date by State

   (See figure in printed
   edition.)


--------------------
\10 Power plants in the Ohio Valley, Appalachia, and the Midwest are
major sources of SO2 emissions that may contribute to acid rain in
the Northeast. 

\11 1990 Integrated Assessment Report, NAPAP (Washington, D.C.:  Jan. 
1990); Economic Analysis of Title V (Acid Rain Provisions) of the
Administration's Proposed Clean Air Act Amendments (H.R.  3030/S. 
1490), Prepared for EPA by ICF Resources, Inc.  (Fairfax, Va.:  Sept. 
1989); Acid Rain Control:  An Analysis of Title IV of S.  1630, CRS
(Washington, D.C.:  Jan.  31, 1990). 

\12 This occurs because the cost per ton of removing SO2 is lower for
a plant burning high-sulfur coal than for a plant burning low-sulfur
coal.  Midwestern utilities typically burn high-sulfur coal. 

\13 Economic Analysis of The Title IV Requirements of The 1990 Clean
Air Act Amendments, prepared for EPA by ICF Resources, Inc. 
(Fairfax, Va.:  Feb.  1994), p.  A-3. 


RELUCTANCE TO TRADE HAS BEEN DUE
TO VARIOUS REGULATORY, INDUSTRY,
AND MARKET FACTORS
============================================================ Chapter 3

Several factors are causing the low level of allowance trading cited
in chapter 2.  First, phasing in the trading program separated two
groups of utilities that might have traded sooner.  A second barrier
to more trading results from the economic regulation of electric
utilities.  State public utility commissions and FERC regulate
utilities' profitability and recovery of costs, but to date, the
commissions have provided limited regulatory guidance on allowances. 
Without this guidance, many utilities may avoid trading and instead
install scrubbers or fuel-switching equipment because the costs for
such items are traditionally recouped in utility rates, while the
question of whether utilities can recover allowance trading costs
remains unresolved.  As a result of increased competition in the
electric power industry, some utilities and regulators are disposed
to trading, but for many others, trading represents a major change
from traditional regulation to a more flexible market approach. 

In addition to the trading program's structure and the regulatory
system, five other factors have been cited by market participants as
impeding trading, although the magnitudes of the effects of these
factors are unknown.  They include problems with the program's
auction design, uncertainty regarding EPA's future regulations,
possible state restrictions on trading because of lingering
environmental concerns, state mandates on coal use, and the Internal
Revenue Service's (IRS) tax treatment of allowances. 


   PHASING IN THE NEW PROGRAM HAS
   SLOWED MARKET DEVELOPMENT
---------------------------------------------------------- Chapter 3:1

The structure of the allowance market has slowed trading.  As noted,
in Phase 1 only about 14 percent of the affected power plants in the
country are required to reduce emissions; hundreds of other plants
are not added to the program until Phase 2, beginning in the year
2000.  With limited participation required in Phase 1, the market has
not developed rapidly.  According to some environmental groups and
market participants, the decision to include such a small percentage
of the nation's utility plants in Phase 1 meant that trading would
begin quite slowly.  In addition, 3.5 million allowances were awarded
to certain utilities in Phase 1, reducing their need to trade now. 

As noted in chapter 1, Phase 1 only applies to the 110 utility plants
with the highest levels of emissions, while Phase 2 broadens the
program to include over 700 of the cleaner, usually smaller plants. 
The utilities in Phase 1 generally have lower emissions reduction
costs per ton of SO2 reduced than those added in Phase 2, making them
more likely sellers and the Phase 2 utilities more likely buyers.  As
discussed in chapter 2, many Phase 1 utilities are projected to
surpass their reduction requirements and will have extra allowances
for potential sale.  On the other hand, the cleaner, smaller
utilities added in Phase 2 must reduce emissions by a relatively
small amount to be in compliance.  Nevertheless, many of these plants
are already burning low-sulfur fuel, and additional pollution
controls could be costly for the amount of emissions to be reduced. 
Thus, a cost-effective compliance strategy for many utilities only
subject to Phase 2 may be to purchase allowances from Phase 1
utilities that surpassed their reduction requirements and generated
extra allowances. 

However, the two-step phase-in of emissions reductions created a
multiyear gulf between the time that these probable sellers and
buyers had to make decisions on compliance strategies.  Utilities
might have traded allowances sooner if they had all been required to
meet a uniform emissions reduction at the same time.  Instead,
compliance plans for utilities in Phase 1 had to be submitted to EPA
by February 15, 1993--less than 4 months after most rules for the
program were finalized.  Phase 2 utilities do not have to submit
their compliance plans until January 1, 1996, and compliance does not
begin until 2000.  Few Phase 2 utilities, the market's "buyers," have
traded allowances; this low level of trading may be due in part to
the fact that their deadlines are far in the future.  According to
EPA and some market observers, the effectiveness of trading cannot be
judged until Phase 2, when all affected utilities must comply with
the requirements. 

One allowance broker noted that a related market development problem
has arisen because Phase 1 utilities submitted their compliance plans
on the basis of sparse information on allowance prices:  In the
absence of an active SO2 allowance market, only price projections
were available.  As noted in chapter 2, the actual market price of
allowances has been considerably less than projections indicated
earlier in the program.  As a result, some utilities may have adopted
compliance strategies in Phase 1 that avoided the use of allowances
but were more expensive than necessary. 

The 3.5 million extra allowances awarded to certain Phase 1 utilities
that installed scrubbers may also explain why many of these utilities
have an allowance surplus and are under little pressure to trade. 
Worth over $500 million, these extra allowances in essence subsidized
scrubbers--regardless of whether they were the least-cost compliance
strategy.  For example, one midwestern utility originally planned to
switch one of its plants to lower-sulfur coals but then decided to
install a scrubber under pressure from the state public utility
commission and because of the availability of 750,000 free
allowances. 


   REGULATION OF ELECTRIC
   UTILITIES HAS NOT ENCOURAGED
   TRADING
---------------------------------------------------------- Chapter 3:2

A number of market analysts have also suggested that the market's
slow development is inherent in the nature of the electric utility
industry.  That is, market-based compliance is new for utilities,
requiring them to adjust to a different culture and regulatory
approach.  For example, a former public utility commission chairman
said the following: 

     The allowance trading system imposed a market-based
     environmental compliance mechanism on an industry which has long
     been tightly regulated, strongly averse to risk-taking, for the
     most part very conservative, and which has long experienced
     environmental compliance as simply a matter of unit-by-unit
     command-and-control.\1

State public utility commissions influence a utility's investment
decisions through regulations governing, among other things,
acceptable rates of return, recoverable costs, and the distribution
of financial risks and returns between ratepayers and shareholders. 
In the absence of regulatory guidance on SO2 allowance trading, this
system of economic regulation reduces a utility's financial incentive
to trade.  Another aspect of this economic regulation is the
risk-averse nature of the industry, which utilities and market
observers say discourages electric power companies from trading
allowances with one another. 


--------------------
\1 Hearing on Implementation of Title IV of the Clean Air Act Before
the Subcommittee on Air and Nuclear Regulation of the Senate
Committee on Environment and Public Works, 103rd Cong., 1st Sess.,
Oct.  21, 1993, statement of Ashley Brown, Harvard Electricity Policy
Group, John F.  Kennedy School of Government, Harvard University, p. 
2. 


      REGULATORY TREATMENT OF SO2
      ALLOWANCES IS UNCERTAIN
-------------------------------------------------------- Chapter 3:2.1

Most state utility commissions lack regulations on allowance trading
and the distribution of any resulting gains or losses between
ratepayers and shareholders.  Under traditional regulation, utilities
are allowed a rate of return on capital investments and recovery of
their operating expenses.  Ratepayers--consumers--pay for these costs
through electricity rates.  Since passage of the Clean Air Act
Amendments of 1990, according to data compiled by the National
Regulatory Research Institute (NRRI) and EPA, only 8 of 21 states
with utilities subject to Phase 1 have issued rules on the regulatory
treatment of allowance transactions, and two states with only Phase 2
utilities have issued guidance.  In general, states have addressed
utilities' compliance costs and allowance trades on a case-by-case
basis.  According to a former chairman of a public utility
commission, many utilities have waited for signals from their
commissions as to how to proceed.  But as he noted, the commissions,
more accustomed to a role of passive ratemaking, have usually not
signaled their intentions. 

Without regulatory direction on allowance trading, many utilities may
continue to use other compliance options, such as investments in
scrubbers or other fuels, whose costs historically have been approved
by state commissions, even though allowances might cost less.  Given
that issues of cost recovery and rate of return are well established
for the costs of scrubbers or switching fuels, many utilities may opt
for those choices rather than risk incurring the full cost of an
allowance transaction before knowing how commissions will act.  As
noted in chapter 2, 71 percent of the utilities subject to Phase 1
are complying by switching fuels or scrubbing, while only 3 percent
are purchasing allowances.  In addition, many Phase 1 utilities are
banking allowances for their needs in Phase 2 rather than trading
with others. 

In most states with guidelines on allowances, according to NRRI,
gains from trading are to be distributed to the ratepayer only, which
may reduce the utility's incentive to trade.  In order to sell extra
allowances for a profit, utilities generally must reduce emissions
more than they are required to.  The state commissions will generally
distribute any utility profits from trading to the ratepayer. 
Similarly, if trading turns out to be less cost-effective than other
compliance choices, the commissions may make the shareholders pay. 
In short, any risk remains with the shareholders and any profits
remain with the ratepayers.  This asymmetric treatment of risks and
rewards may reduce any incentive that utilities might have to reduce
emissions more than required and offer the resulting allowances for
sale. 


      TRADITIONAL REGULATION
      ENCOURAGES UTILITIES'
      AVERSION TO RISK
-------------------------------------------------------- Chapter 3:2.2

Historically, public utility commissions have insulated utilities
from competition, discouraging them from activities perceived as
risky.  Electric utilities have been provided with a rate of return
without the challenges faced in a competitive market like the SO2
allowance market, where a company's choices, initiative, and
flexibility determine profits and losses.  According to several
utility officials, a utility may avoid the risk of the SO2 allowance
market in favor of compliance options customarily accepted by
commissions and incorporated into rates. 

While ratepayers pay for a utility's capital investments and
operating costs under traditional rate-of-return regulation, most
commissions also apply a "prudent investment" test, which holds that
a utility's dishonest, wasteful, or imprudent costs may not be
included in rate calculations.  Over the past two decades, utilities'
efforts to include certain costs in the rate base have been
increasingly denied or delayed.  As a result, utilities traditionally
avoid novel and untried activities--such as allowance trading--that
risk being denied recovery in rates.  According to an Argonne
National Laboratory study of Phase 1 compliance choices,\2 utilities
will tend to avoid compliance options that do not earn a rate of
return, even though such options may be less costly.  Electric
utilities have been referred to as "risk averse," prone to take
least-risk approaches rather than least-cost approaches to problems. 

In exchange for the flexibility of allowance trading, utilities are
exposed to risks they did not face when specific technologies or
emissions standards were mandated.  For example, a utility may
purchase allowances when they are the least-cost strategy and then
see the price of allowances rise, making them more expensive than
other options.  In that case, a public utility commission might
question whether this purchase was prudent and who should bear the
cost of the decision.  As a result, utilities may be reluctant to
trade without regulatory clarification on these matters.  According
to an official of a Phase 1 utility that needs allowances for
compliance in Phase 2, the company decided to forgo buying allowances
now because it perceived doing so as too risky. 


--------------------
\2 Examination of Utility Phase 1 Compliance Choices and State
Reactions to Title IV of the Clean Air Act Amendments of 1990,
Argonne National Laboratory, ANL/DIS/TM-2 (Nov.  1993). 


   THREAT OF COMPETITION IS MAKING
   UTILITIES AND STATE REGULATORS
   MORE DISPOSED TO TRADING
---------------------------------------------------------- Chapter 3:3

Despite their traditional risk aversion, some utilities are trading
allowances.  A couple of these utilities note that increasing
competition in their industry provided the catalyst for them to
trade.  With support available from the Department of Energy (DOE),
many state utility commissions are also orienting their regulatory
approaches to this new competition by requiring utilities to conduct
least-cost planning.  Least-cost planning can encourage trading by
requiring utilities to consider a wider range of compliance options
than is traditionally the case.  Even so, utilities are still likely
to be reluctant to trade if the risk of trading remains with the
utility and the profits with the ratepayer.  Several market observers
believe that utilities will need to be compensated for taking such
risks. 


      COMPETITION PUTS PRESSURE ON
      UTILITIES TO REDUCE COSTS
      AND RATES
-------------------------------------------------------- Chapter 3:3.1

Increasing competition in the utility industry is providing an
impetus for some firms to enter the allowance market.  These
utilities are trading allowances to avoid the higher costs for
scrubbers or maintain lower rates for their customers.  For example,
even in a state where the utility commission has ruled that all cost
savings resulting from trading accrue to the ratepayers, utilities
were still in the allowance market to maintain low rates. 

As a result of legislative and economic changes over the past decade,
increasing amounts of wholesale electricity are being generated by
power producers that are independent of regulated utilities,
resulting in more industry competition.  In a March 1993 report,\3
DOE's Energy Information Administration noted that utilities'
purchases of electric power from nonutilities have been increasing at
an "astonishing" average annual rate of 31 percent since 1986 and
that electricity in wholesale transactions now accounts for more than
half of the electricity sold to retail customers.  According to
utilities active in the SO2 allowances market, allowances provide a
major opportunity to remain competitive as a result of lower
compliance costs and rates. 

For example, one midwestern utility's officials noted that they
stopped building a scrubber, after spending about $30 million,
because purchasing allowances was cheaper.  Despite a state law
guaranteeing recovery of the reasonable costs for the scrubber,
officials of this utility explained that purchasing allowances
offered compliance without raising rates and that maintaining low
rates was necessary to remain competitive. 


--------------------
\3 The Changing Structure of the Electric Power Industry 1970-1991,
Energy Information Administration, DOE/EIA-0562 (Mar.  1993). 


      STATE COMMISSIONS ARE
      ADAPTING THEIR APPROACHES,
      WHICH COULD ENCOURAGE
      TRADING
-------------------------------------------------------- Chapter 3:3.2

Like utilities, state utility commissions are adapting their
regulatory approaches to the new competition, with DOE's support. 
The most visible change is the adoption of least-cost planning, which
could encourage more trading.  Of the 21 states with utilities
subject to Phase 1, 18 have requirements for least-cost planning,
according to Argonne National Laboratory.  Least-cost planning is a
way of ensuring beforehand that a utility's decisions are prudent,
rather than awaiting completion of a scrubber, for example. 
According to some of the commissions we met with, least-cost planning
encourages utilities to consider a wider range of compliance options
than they do under traditional regulatory reviews.  By including
decisions on allowances in least-cost planning, regulators could also
consider how to treat allowances in rates, along with other utility
investments. 

For commissions considering least-cost planning, DOE offers support
in developing regulations.  In October 1993, DOE created the Utility
Commission Proceedings Participation Program, made up of technical
and policy offices in DOE and EPA.  This team participates in
commissions' regulatory proceedings on such issues as least-cost
planning, energy conservation, and environmental protection.  DOE
also has an Integrated Resource Planning team, which assists
commissions on the technical aspects of least-cost planning. 
According to DOE officials, both of these teams have provided
information to or intervened in proceedings before state commissions
to help establish rules on least-cost planning, but to date, they
have not addressed allowance trading.  However, DOE and EPA officials
agreed that in the future, these teams should offer to assist utility
commissions in developing rules on trading because both utilities and
ratepayers benefit from the lower compliance costs that trading
offers. 

The effect of incorporating decisions on allowances into least-cost
planning is unclear at this point.  If a state's least-cost plan
specifies how excess allowances owned by the utility will be treated
in ratemaking, least-cost planning could reduce this element of
uncertainty and encourage trading.  Yet most states, as noted
earlier, have not specified how allowances will be treated in the
ratemaking process.  Although the least-cost planning process may
focus utilities on least-cost options such as allowances, several
utilities stated that they may not actively trade allowances as long
as commissions follow traditional ratemaking, in which the risk of
trading allowances remains with the utility and the profits remain
with the ratepayers. 


      INCENTIVE REGULATION FOR
      ALLOWANCES HAS BEEN PROPOSED
-------------------------------------------------------- Chapter 3:3.3

Some market observers, such as the Edison Electric Institute and
NRRI, have proposed incentive regulation as a means of offsetting the
effects of traditional utility regulation.  They believe that
utilities may forgo cost-effective opportunities in the allowance
market as long as all profits flow to the ratepayer and all
investment risk to the utility.  These groups suggest that utilities
will need to be compensated for their risks in the allowance market. 

Under such an incentive approach, the commission could set an
allowance price cap.  If the utility outperforms this benchmark
price, either by selling allowances at higher prices or by complying
at lower costs, the utility keeps the difference.  Conversely, if the
compliance costs exceed the preestablished price cap, the utility is
able to recover only the benchmark price.  According to proponents of
incentives, shareholders would obtain returns from cost-effective
trades and consumers would pay lower rates.  Because risks and
rewards would be more balanced than they are under traditional
ratemaking, proponents also believe that incentive regulation would
more efficiently encourage least-cost compliance than a lengthy
least-cost planning process. 

Although, according to NRRI data, no utility commissions have adopted
such incentive regulation for their state's utilities, some are
taking steps to encourage trading.\4 One of the five utility
commissions we talked with was considering this incentive approach. 
For many state commission officials, allowance trading is still a new
concept.  However, NRRI has advocated incentive regulation in
numerous workshops for state commissions, and in fact, some are now
considering ways to encourage utilities to recognize the potential
benefits of trading. 

For example, the Georgia Public Service Commission has directed its
utilities to monitor the SO2 market and buy allowances when they cost
less than other compliance options.  The New York State Public
Service Commission is piloting a ratemaking scheme in which a
utility's rate of return depends on how well the utility controls
various production costs relative to similar utilities.  New York
officials suggested that allowances could be included as one measure
of production costs. 


--------------------
\4 Public utility commissions in both Connecticut and Indiana have
adopted an incentive mechanism for one utility in their state. 


   FERC'S REGULATORY TREATMENT OF
   ALLOWANCES IS UNCERTAIN
---------------------------------------------------------- Chapter 3:4

Utilities have no guidance from FERC on incorporating allowance costs
in the wholesale rates they charge for interstate transactions of
electricity.  FERC has jurisdiction over these transactions--growing
in number--
because it regulates interstate commerce in electricity.  The
importance of guidance from FERC is also underscored by the
projection that the nine multistate registered holding companies,\5
which are subject to FERC's jurisdiction, will hold almost 25 percent
of all SO2 emissions allowances by the year 2000.  Some utilities
have already asked FERC to address the issues of ratemaking and
allowance transactions and of the multistate holding companies'
compliance.  While these requests are currently pending, FERC has
issued no official guidance to date because it does not want to set a
precedent before reviewing these specific utility cases and allowing
time for the program to develop.  FERC has limited itself to revising
utilities' accounting rules to include data on allowances.\6 FERC
decided not to require frequent reporting of allowance trades and
prices as part of these revised accounting rules--as some state
commissions suggested--although it recognized the usefulness of such
data to market participants and expressed a willingness to revisit
the issue. 

The Clean Air Act does not prescribe how allowances should be treated
in ratemaking, leaving state commissions and FERC free to determine
their own approach.  As discussed previously, traditional ratemaking
does not encourage allowance trading.  Moreover, states may treat
allowances differently in ratemaking, and this variation can make
compliance planning difficult for multistate utility systems.  One
multistate holding company official told us that his company would
rather trade allowances through a private allowance broker than trade
between two of the firm's utilities, which would require getting
approval of proposed plans and costs from two state commissions. 

Some market participants and analysts have urged FERC to be more
active in setting a ratemaking framework for allowances.  In the
absence of direction from FERC, multistate holding companies and
wholesale electricity buyers and sellers cannot be certain how
allowances will be treated in their transactions and compliance
plans.  According to several utility officials and other market
analysts we talked with, policy guidance from FERC could help to
remove this uncertainty. 

Issues of how to assign a value to allowances in wholesale
transactions and how multistate holding companies can manage
allowances among their individual utilities are currently pending
before FERC.  For example, the Allegheny Power System has submitted
an allowance management plan dealing with these issues for FERC's
review.  The plan describes how Allegheny Power's subsidiary
utilities will manage their allowances in the wholesale electricity
market.  FERC officials have stated that earlier action on their part
would have set a precedent for the trading program before FERC could
review utilities' specific requests.  FERC officials noted that they
preferred to allow utilities to come forward with their particular
cases rather than issue guidance and establish a precedent that must
generally be followed by all utilities.  They also wanted to provide
EPA, state commissions, and utilities with time to make the program
work as efficiently as possible. 

Despite its intentions not to do so, FERC has influenced how
allowances are treated in ratemaking by issuing accounting rules for
allowances.  Several market analysts suggest that ratemaking issues
should have been addressed first, followed by accounting rules
consistent with this ratemaking framework.  Although FERC stressed
that its accounting rules did not prescribe how allowances should be
treated in ratemaking, NRRI notes that some states have incorporated
aspects of these rules into their ratemaking.  For example, because
FERC's accounting rules value allowances at their historical cost,
several state commissions have also chosen to use the historical cost
of allowances for ratemaking purposes.  As a result, the allowances
originally allocated by EPA are valued at zero by these commissions,
since the utility is not charged anything for them.  However, NRRI
cautions that allowances are valuable assets and should not be valued
at zero for ratemaking purposes.\7

In adopting its accounting rules, FERC decided to collect data on
allowance transactions in the annual reports that electric utilities
file with FERC on, among other things, their income, earnings, and
production costs.  However, several state commissions suggested in
public comments on the rules that more frequent reporting of
allowance trades could reduce uncertainty about prices.  Some
utilities proposed making the collection of allowance data conform to
FERC Form 423's reporting requirement.  Form 423 is a monthly report
filed by electric utilities on the cost and quality of their fuels. 
Data from Form 423 are published monthly and serve as the primary
source of information on prices and the availability of utility
fuels.  However, FERC believed that more frequent reporting was
unnecessary, stating that data on allowances available from EPA
auctions and other sources might fill the need for price information. 
In adopting the annual reporting requirement, FERC noted that this
issue might need to be revisited, depending on how information on the
market developed.  As noted in chapter 2, allowance price data are
currently scarce and conflicting, and according to EPA officials, a
more frequent reporting requirement by FERC on the number and prices
of allowances traded would be helpful. 

Although FERC is more accustomed to a role of passive ratemaking,
responding to utility cases as a judicial body, FERC has taken active
positions on some emerging issues.  In 1988, according to FERC
officials, FERC issued notices of proposed rulemaking describing its
position on a more competitive wholesale electricity market.  The
officials noted that in subsequent decisions on rate cases, FERC
carried out some of the ideas in the notices to encourage this
market.  Similarly, FERC recently issued a policy statement allowing
electric utilities to submit rate proposals based on incentive
regulation.  Although states had used such regulation to cut costs,
FERC did not have a history of using incentives to do so.  Some of
FERC's commissioners noted that the policy statement would provide a
framework for FERC's review of incentive proposals. 


--------------------
\5 These nine companies are corporations comprising utilities which
operate in different states.  For example, the Southern Company, one
of the largest holding companies, includes five utilities supplying
energy in most of Alabama and Georgia, portions of Florida and
Mississippi, as well as in three other states. 

\6 FERC's Order No.  552 (Mar.  31, 1993); 58 Fed.  Reg.  17982,
18007 (Apr.  7, 1993). 

\7 Regulatory Treatment of Electric Utility Clean Air Act Compliance
Strategies, Costs, and Emission Allowances, The National Regulatory
Research Institute, NRRI/93-16 (Dec.  1993). 


   OTHER FACTORS HAVE BEEN CITED
   AS ADDITIONAL IMPEDIMENTS TO
   TRADING
---------------------------------------------------------- Chapter 3:5

Five other market and regulatory factors have been cited by market
participants as impeding trading.  These other factors include
problems with the design of EPA's auction, uncertainty about EPA's
future regulations, lingering environmental concerns, state mandates
on coal use, and the tax treatment of allowances. 


      AUCTION DESIGN CONTRIBUTES
      TO LOWER PRICES AND
      UNCERTAINTY
-------------------------------------------------------- Chapter 3:5.1

Certain features of EPA's auction are contributing to a range of
unexpectedly low allowance prices and creating confusion about what
the market price should be.  This confusion, in turn, may discourage
trading.  EPA officials have indicated a willingness to reconsider
aspects of the current auction design consistent with language in the
Clean Air Act Amendments of 1990. 

EPA designed the auction as a "price-discriminating" auction, meaning
that bidders pay what they bid.  EPA's auction is distinguished by
three features.  First, as directed by the Clean Air Act, EPA, the
largest seller of allowances in the auctions to date, has no minimum
asking price.  In essence, EPA must offer its allowances at $0.\8

Second, since winning bidders in the EPA auction pay the amount that
they actually bid, the auction generates a range of winning prices. 
In contrast, many other auctions, such as trading on the New York
Stock Exchange or auctions for securities, have a single,
market-clearing price paid by all winning bidders and received by all
sellers.\9

Third, allowances are auctioned off by matching the lowest-priced
offers to the highest-priced bids.  For example, since EPA offers
allowances at $0, these allowances are matched with the highest bids
submitted. 

These features, in combination, encourage certain strategic behaviors
on the part of both sellers and bidders, resulting in lower prices
for the allowances.  Sellers have an incentive to place offers as low
as possible in order to obtain the highest price.  Meanwhile, buyers
bid lower, knowing that most allowances offered will be very cheap,
particularly EPA's zero-priced allowances.  At the two auctions held
so far, allowance prices have been up to a third below the prices
reported for trades taking place outside the auction.  According to
utilities active in the market, the prices paid at the auction
discourage potential trades or unnecessarily delay allowance
transactions because buyers want to obtain allowances at the low
prices reflected in the auction, while sellers find those prices
unrealistic and below their costs of reducing emissions. 

In addition, since the auction does not produce only one winning
price, utilities find the range of winning prices confusing as an
indicator of the actual market price.  Officials of state utility
commissions told us that they expect utilities to compare the price
of allowances with the price of other options when developing
compliance plans.  Some noted that EPA's auction could be an
indicator of price, but they believe that auction prices have been
confusing and artificially low.  According to several utilities,
market analysts, and some economic research, an auction resulting in
a single, market-clearing price, such as the one that occurs on the
New York Stock Exchange, would provide more accurate prices. 

According to EPA officials, language in the Clean Air Act Amendments
of 1990 and discussions during debate on the 1990 Amendments suggest
that the Congress believed a price-discriminating auction would
maximize the proceeds paid to utilities for their allowances, since
successful bidders pay what they bid.  Although the Clean Air Act
does not specifically mandate a price-discriminating auction, the
statute requires that the auction allocate and sell allowances on the
basis of the prices bid.  When EPA designed the auction, some market
analysts suggested in comments to EPA that while a discriminative
auction met the statutory requirement, a single-price auction also
met this test because the bidders' prices determine the price at
which allowances are sold. 

When EPA adopted the current auction design, it said it would monitor
the auctions and identify any necessary changes to the design "that
may be required to assure an orderly and competitive market."\10 In
addition, several EPA officials told us that EPA is willing to
reconsider the issue, and the Deputy Assistant Administrator for
Policy, Planning, and Evaluation noted that it would be useful for
EPA to have the flexibility to choose an auction design.  We believe
that an auction at which allowances are sold at a single price is
consistent with the Clean Air Act's statutory language and the
congressional goals for the auction expressed in the legislative
history.  A single-price auction could result in at least the same,
if not higher, total proceeds to the extent that the incentive to
submit lower bids present in the price-discriminating design would be
removed. 


--------------------
\8 As noted in ch.  1, EPA offered a total of 325,000 allowances for
sale in the two auctions held to date; these allowances come from a
reserve of allowances established by reducing utilities' allocations
by 2.8 percent.  Proceeds are returned to each utility on a pro rata
basis.  Other entities can offer allowances at any specified price,
and these allowances are sold after those held by EPA. 

\9 T.  N.  Cason, "Seller Incentive Properties of EPA's Emission
Trading Auction," Journal of Environmental Economics and Management,
No.  25 (1993), pp.  177-195. 

\10 56 Fed.  Reg.  65592, 65596 (Dec.  17, 1991). 


      UNRESOLVED EPA RULES CREATE
      UNCERTAINTY IN THE ALLOWANCE
      MARKET
-------------------------------------------------------- Chapter 3:5.2

Utilities, state officials, and market analysts praised EPA's efforts
to get broad input and build consensus on rulemaking without trying
to direct the allowance market's development.  Many also commended
EPA's attempts to educate commissions and utilities about allowance
trading and encourage trading through visits and workshops.  However,
they did cite several problems that have added to uncertainty in the
market and may hinder trading. 

Most problematic is EPA's future regulation of other pollutants, such
as toxic air emissions and nitrogen oxides.  For example, a utility
might choose an option to control SO2 that precludes using the
least-cost way of controlling these other pollutants.  Alternatively,
a utility might choose the least-cost option to control SO2 as well
as the other pollutants, but the public utility commission may not
allow a utility to recover from ratepayers the costs of controlling
other pollutants that are not currently regulated.  EPA hopes to
resolve many of these regulatory uncertainties before Phase 2
compliance plans are due in 1996.  However, some utilities doubt that
EPA will do so, given its history of missing deadlines.  As noted in
chapter 2, many utilities are simply banking allowances and not
trading. 

In July 1993, EPA announced that one of its rules could result in up
to 1 million more allowances being available than intended.  Under a
plant substitution rule in Phase 1, utilities could substitute a unit
slated for emissions reductions during Phase 2 for a unit slated for
reductions during Phase 1, as long as equivalent emissions reductions
were achieved.  However, EPA subsequently found that this rule could
permit the substitution of Phase 2 units for Phase 1 units with few
resulting reductions--instead creating extra allowances.  The
allowances were considered extra because they were tied to emissions
reductions that occurred before passage of the Clean Air Act
Amendments of 1990.  As a stop-gap measure, while EPA rewrote the
rule, it approved--for one year only--compliance plans that the
utilities had already submitted.  Some utilities worried that further
changes in rules could ensue, causing uncertainty and discouraging
trades.  Other market analysts viewed this rule change as an isolated
action, with little impact on trading.  In May 1994, EPA signed a
settlement agreement with utilities and environmental groups to close
the loophole but allow a transition into the new rules. 

EPA may have also impeded trading by deploying behind schedule the
system it uses to track allowances.  Although EPA issued a rule in
January 1993 describing how the allowance tracking system would work,
the computer software to run the system was not finished until March
1994.  EPA officials stated that the delay occurred because of budget
constraints and the complexity of developing a sophisticated
automated system with adequate internal controls.  According to
utilities and allowance brokers, the delay impeded trading because
the system was essential for establishing ownership of the
allowances, recording trades, and conveying this information to the
market.  However, trading activity has not markedly changed since the
creation of the tracking system, and other market participants stated
that its delay was only a minor deterrent to trading. 


      LINGERING ENVIRONMENTAL
      CONCERNS MAY HINDER TRADING
-------------------------------------------------------- Chapter 3:5.3

The trading program targets SO2 emissions rather than the deposition
of acid rain.  While overall emissions will decline in the United
States, New York State officials and the Adirondack Council, an
environmental group, are concerned that trading does not ensure
significantly less deposition in New York's Adirondack Mountains, an
area seriously damaged by acid rain.  Accordingly, they want to place
restrictions on the sales of allowances to emissions sources located
in the Midwest, upwind of New York. 

Others believe, however, that talk of restrictions on trading is
unnecessary and dampens market activity.  The Environmental Defense
Fund states that many of the dirtiest utilities upwind of New York
are reducing emissions more than required in Phase 1 because of the
economic incentives offered by trading.  As noted in chapter 2, many
utilities plan to attain significant extra emissions reductions in
Phase 1.  According to EPA, restrictions are not needed for
environmental protection because most individual trades will not be
large enough to cause measurable impacts on the environment.  EPA
also notes that New York's restrictions on utilities' allowance
trades would not prevent emissions in upwind states.  If a New York
utility sold allowances to a downwind utility not affecting the
Adirondacks, the downwind utility could, in turn, sell these
allowances to an upwind utility.  According to some midwestern and
New York utilities, New York State's discussion of trading
restrictions has dissuaded them from trades with one another.  They
fear that such trades could be overturned by future restrictions. 

The Clean Air Act required EPA to study the environmental impact of
trading on sensitive areas such as the Adirondacks and to assess the
need for corrective action.  EPA has not completed this study, which
was due November 15, 1993.  Responding to a lawsuit filed by New York
State and the Adirondack Council, EPA said that the report will be
done by January 1995.  Scientists at EPA and state environmental
agencies note that long-term monitoring of acid rain--well into Phase
2--will be necessary to determine whether conditions improve in
sensitive areas.  According to the Deputy Director of EPA's Office of
Modeling, Monitoring Systems and Quality Assurance, EPA's budget
projections anticipate continued funding for such monitoring. 


      STATE ACTIONS TO CONTINUE
      USE OF LOCAL COAL LIMIT
      TRADING
-------------------------------------------------------- Chapter 3:5.4

Several states have passed laws to encourage their utilities to
continue using coal mined within the state.  These laws include
incentives and mandates to use scrubbers and tax credits for local
coal use.  By limiting compliance choices, the laws discourage
utilities from buying and selling allowances in some cases, even when
doing so might be less costly.  None of the state mandates refer to
allowance trading as a compliance option. 

As noted in chapter 2, over half of all Phase 1 compliance plans
involve switching to lower-sulfur coal.  Illinois, Indiana, Kentucky,
Ohio, and Pennsylvania, with large high-sulfur coal reserves, have
passed laws to protect coal mining jobs and prevent such switching. 
Ohio and Pennsylvania provided tax credits for the use of in-state
coal, and Illinois required two of its utilities to use scrubbers. 
However, federal courts struck down the Illinois law and a similar
one in Oklahoma as unconstitutional restrictions on interstate
commerce.  A similar court challenge is currently pending in Indiana. 


      IRS'S TAX TREATMENT OF
      ALLOWANCES MAY DISCOURAGE
      TRADING
-------------------------------------------------------- Chapter 3:5.5

In 1992, the IRS issued guidance requiring the use of the historical
cost of SO2 allowances for purposes of tax calculation.\11 The IRS
also said that EPA's allocations of allowances to utilities would not
be taxable.  In effect, these allocated allowances would be treated
as having no value.  If the allowances are sold by the utility
receiving them, almost one-third of their sale price would be taxed
as a capital gain.  According to some industry officials, this
approach results in more favorable tax treatment of allowances not
sold because internal uses of allowances are not subject to taxation. 
They say that utilities will be reluctant to sell their allocated
allowances when almost one-third of the sale price is taxed. 

However, other utilities and market analysts do not believe that this
tax treatment is a major impediment to trading.  They think that
allowance sellers will consider these tax consequences and simply ask
higher prices.  In addition, they note that generating excess
allowances for sale entails investing in scrubbers or fuel-switching
equipment that can be capitalized and depreciated to yield tax
benefits.  According to one utility official, public utility
commissions adjust electricity rates to allow utilities to recoup the
taxes they pay.  Thus, any taxes paid on the sale of allowances could
be recovered in rates. 


--------------------
\11 Revenue Ruling 92-16 and Revenue Procedure 92-91, IRS. 


   CONCLUSIONS
---------------------------------------------------------- Chapter 3:6

EPA's acid rain program is projected to reduce emissions and save
billions of dollars a year over traditional approaches to pollution
control, but the program could achieve substantial additional cost
savings if utilities were trading allowances more actively.  However,
various obstacles are deterring more allowance trading.  Some, such
as the way the program was phased in and lingering environmental
concerns, may become less significant as compliance deadlines
approach and reductions in emissions occur.  Others, such as the
influence of EPA's auction or the way public utility commissions
treat allowances in rates, may prove less tractable.  Although it is
unlikely that removing one particular obstacle could dramatically
increase trading, federal action could lessen the effects of some of
these impediments. 

Reliable allowance prices would make trading easier by providing
potential buyers and sellers better data on the price at which to
trade.  Although EPA's auction provides price information, it has
resulted in multiple prices rather than a single price and lower
prices than expected.  Under the Clean Air Act, EPA can change this
auction design to one that produces a single and more accurate price
for all the allowances auctioned.  In addition, FERC, which requires
utilities to report allowance prices only once a year, has expressed
a willingness to consider more frequent reporting.  FERC currently
collects data monthly from utilities on their fuel costs, and these
data serve as a public source of information. 

FERC, EPA, and DOE can also help resolve the impediment to trading
created by the current lack of guidance on how allowances will be
treated in ratemaking.  FERC has been reluctant to issue guidance for
fear of prematurely setting a precedent, but recent requests from
utilities pending before FERC may now offer a vehicle for providing
guidance.  FERC also has taken positions on some previous emerging
issues through policy statements or notices of proposed rulemaking. 
Moreover, through DOE's Utility Commission Proceedings Participation
Program and Integrated Resource Planning team, EPA and DOE believe
that they could help public utility commissions craft ratemaking that
encourages the cost-effective use of allowance trading. 

Many of the obstacles discussed in this chapter are not unique to SO2
trading.  As we discuss in chapter 4, similar or closely related
issues are likely to confront a trading program to control CO2
emissions. 


   RECOMMENDATIONS
---------------------------------------------------------- Chapter 3:7

To improve price information from EPA auctions and help clarify the
regulatory treatment of allowances, the EPA Administrator should

change the design of the auction so that it is a single-price auction
and

work with DOE's Utility Commission Proceedings Participation Program
and Integrated Resource Planning teams to help state utility
commissions and FERC decide how to treat allowances in ratemaking. 

In addition, the Chair of FERC should

require more frequent reporting of the number and prices of
allowances traded and

issue guidance on how FERC will treat allowances in ratemaking
through a policy statement, notice of proposed rulemaking, or a
ruling in one of the multistate utility cases on allowances currently
before the Commission. 


   AGENCY COMMENTS
---------------------------------------------------------- Chapter 3:8

As requested, we did not obtain written agency comments on a draft of
this report.  However, we discussed the factual information in the
report with the Director and staff of EPA's Acid Rain Division and
the Deputy Director and staff of FERC's Office of Electric Power
Regulation.  EPA generally agreed with the facts presented.  FERC
officials believe that it would have been counterproductive to issue
generic guidance in advance of specific utility requests and before
the trading program could develop.  However, they agreed that utility
cases currently before FERC may now offer a vehicle for providing
guidance and encouraging trading.  In addition, although FERC
officials felt that other market entities might fill the need for
price information, they indicated a willingness to consider more
frequent reporting of allowance prices and transactions. 


EXPERIENCE WITH SULFUR DIOXIDE
TRADING IS RELEVANT IN DESIGNING A
DOMESTIC TRADING PROGRAM IN CARBON
DIOXIDE ALLOWANCES
============================================================ Chapter 4

Experience with the SO2 allowance trading program indicates that some
of the program's features would be effective components in a trading
program for the United States to reduce CO2 emissions that may
contribute to global climate change.  Other features would be useful
only if modified.  For example, the SO2 trading program ensures
environmental protection by mandating an overall reduction in
emissions, tracking compliance with emissions monitors, and imposing
high enough penalties to deter noncompliance.  A CO2 program could be
designed to include these features.  However, as noted in chapters 2
and 3, certain features in the SO2 program, by impeding trading, have
prevented utilities from achieving the fullest potential cost savings
in selecting options for complying with the required reductions in
emissions.  These features bear modification in any new program. 

Under the two-phased approach of the SO2 program, many potential
sellers of allowances had to achieve emissions reductions before
potential buyers of any allowances needed them.  In the absence of
this time gap in the requirements for emissions reductions, potential
buyers and sellers of allowances would be more disposed to trade at
the same time.  In addition, having an allowance auction that results
in a single, market-clearing price would send clearer price signals
than the current SO2 auction design allows for, making it easier for
all buyers and sellers to agree on price. 

A number of other issues are relevant in designing a CO2 trading
program.  For example, how state public utility commissions and FERC
carry out their mandates can encourage or discourage trading. 
Deciding what sources of CO2 emissions to include in an allowance
trading program is a more important consideration than it is for SO2
because the sources of CO2 are more varied.  Finally, allowing
trading across national boundaries, while going beyond the scope of a
domestic trading program, offers potentially greater cost savings,
but a program that included this component would also be much more
difficult to implement. 


   SEVERAL FEATURES OF THE SULFUR
   DIOXIDE TRADING PROGRAM WOULD
   BE EFFECTIVE IN A CARBON
   DIOXIDE TRADING PROGRAM
---------------------------------------------------------- Chapter 4:1

The SO2 trading program has built-in safeguards to ensure that
environmental protection is achieved regardless of how much or how
little allowance trading occurs.  These same features could serve as
environmental safeguards in a CO2 trading program for the United
States. 


      MANDATING AN OVERALL
      EMISSIONS REDUCTION HELPS
      ENSURE ENVIRONMENTAL
      PROTECTION
-------------------------------------------------------- Chapter 4:1.1

Stipulating a fixed amount of emissions to be reduced nationwide by a
specific date would help to make it clear that environmental
protection is the primary goal of a CO2 trading program.  Separating
the overriding environmental objective from the means of achieving it
helps address concerns about whether trading will ensure meeting the
environmental goal.  Thus, mandated emissions reductions will occur
regardless of how much trading takes place. 

In the SO2 program, choosing average 1985-87 emissions as the
baseline against which to measure the reductions required to begin in
1995 and 2000 reduced utilities' incentive to maintain higher
emissions for the express purpose of receiving larger initial
allocations of allowances.  It is more difficult for a utility to
attempt such a strategy when the span of time is long between the
baseline period and the date by which reductions have to be achieved. 
In addition, choosing an average of emissions over several years
rather than singling out one year reduces the chance that the
emissions baseline chosen does not represent normal economic
activity.\1


--------------------
\1 For instance, in an economic recession, emissions are typically
lower.  As a result, a smaller reduction is needed to meet a given
emissions level. 


      RELIABLE MONITORING
      FACILITATES COMPLIANCE
-------------------------------------------------------- Chapter 4:1.2

The ability to continuously monitor emissions as part of a CO2
trading program has both environmental and economic benefits that
facilitate trading.  For SO2, title IV requires all utilities to
install CEMs, which provide utilities and environmental regulators
with timely information on SO2 emissions.  This information makes it
easier for utilities to make sure they are complying with the law and
for EPA and state regulators to detect noncompliance.  CEMs help
ensure that the flexibility to choose among compliance measures in a
trading program does not jeopardize environmental goals. 

CEMs can also play an important role in certifying allowances, which
is critical to the smooth operation of a market.  In addition, the
continual flow of information on SO2 emissions can provide utilities
with an indicator of how well their production process is
functioning. 

The CEMs installed by utilities for the SO2 program can also be used
to measure CO2 emissions.  In fact, the Director of EPA's Acid Rain
Division told us that EPA is currently receiving measures of CO2
emissions from most sources of emissions covered by title IV.\2 He
also stated that this technology can apply to other large combustion
sources.  In addition, EPA can use available data on energy use and
type of fuel to estimate the CO2 emissions that result from the use
of fossil fuels.\3


--------------------
\2 Section 821 of the Clean Air Act requires all affected sources
subject to title IV to report either measured or estimated CO2
emissions to EPA. 

\3 CEMs may be too costly for some sources that might be controlled
under a CO2 trading program. 


      LARGE PENALTIES OFFSET THE
      BENEFITS OF NONCOMPLIANCE
-------------------------------------------------------- Chapter 4:1.3

Together with monitoring, large penalties can deter noncompliance. 
Under title IV, a utility can incur a penalty of $2,000, indexed to
inflation, for each ton of SO2 emitted in violation of the law, which
is far more costly than purchasing an allowance at today's prices. 
In addition, EPA reduces the noncomplying utility's allotment of SO2
allowances for the following year.  The purpose of these strictures
is to eliminate any benefit from violating the law.  These penalties
also encourage trading to the extent that they prevent any dilution
in the market value of allowances from trading or otherwise using
counterfeit allowances. 


   A CARBON DIOXIDE PROGRAM COULD
   ACHIEVE GREATER SAVINGS IF
   TRADING IS NOT IMPEDED
---------------------------------------------------------- Chapter 4:2

Some features of the SO2 program have impeded trading.  Modifying
these features in a CO2 program could result in greater savings by
stimulating more trading earlier in the program. 


      REQUIRING ALL SOURCES TO
      MEET EMISSIONS REDUCTIONS AT
      THE SAME TIME ENCOURAGES
      TRADING
-------------------------------------------------------- Chapter 4:2.1

If all regulated sources of CO2 must comply with common
emissions-reduction requirements at the same time, more potential
sellers and buyers are likely to consider trading opportunities with
the same urgency.  Including all sources at the trading table is also
likely to mean larger differences in compliance costs among the
prospective traders, simply because there are more firms.  In turn,
more opportunities would occur to realize greater cost savings from
trading. 

The two-phased approach of SO2 allowance trading under title IV has
not encouraged trading because it requires many potential sellers of
allowances to reduce emissions several years before many potential
buyers have to do so.  As a result, potential buyers have not felt
the same urgency to reduce compliance costs as have potential
sellers.\4

If phasing in CO2 emissions reductions is desirable to contain
compliance costs, all regulated sources could reduce their emissions
according to a predetermined time schedule.  This approach is likely
to stimulate more trading than the system used in the SO2 program, in
which many potential sellers are separated from buyers in terms of
when they have to decide about trading. 


--------------------
\4 Buyers subject to Phase 2 of the SO2 program can contract with
sellers subject to Phase 1 for future delivery of allowances. 


      SPECIAL ALLOWANCE POOLS
      AFFECT COST SAVINGS FROM
      TRADING
-------------------------------------------------------- Chapter 4:2.2

The way allowances are allocated at the beginning of a CO2 program
can also affect the cost-saving potential of trading.  Tying
allowance allocations to the use of a specific pollution control
measure or a specific activity such as energy conservation may result
in lower cost savings. 

In the SO2 program, special allowance allocations, especially the
bonus allowances awarded for using scrubbers in Phase 1, reduced the
incentive to choose the lowest-cost option.  Utilities were rewarded
for installing scrubbers regardless of whether that was the
least-cost compliance strategy. 


      SINGLE-PRICE AUCTION COULD
      RESULT IN MORE TRADING
-------------------------------------------------------- Chapter 4:2.3

An auction that results in a single, market-clearing price for all
sellers and buyers is likely to reduce price uncertainty and thereby
encourage trading.  In addition, EPA can offer any allowances it is
holding for sale at prices that reflect the best available
information on what they are worth.  EPA can determine the price at
which it offers its allowances with the assistance of market experts,
in much the same way that a privately held company arranges the price
for its initial offering of stock with a "market maker" or expert. 

The auction design in the SO2 program has resulted in allowances'
being sold at multiple prices, causing uncertainty about what
constitutes a fair market price for allowances.  This uncertainty is
likely to discourage trading because it makes it more difficult for
two trading parties to come to agreement about price.  By contrast, a
single-price auction results in one price that matches buyers' and
sellers' needs. 

If EPA were not constrained to offer allowances with no minimum
asking price, it could price them according to their estimated market
value.  A market maker, such as an allowance broker or other market
expert, could assist EPA.  The purpose would be to ensure that EPA's
asking prices were not so low as to encourage potential buyers to bid
less than they would in a competitive market. 


      FINANCING EPA'S ALLOWANCE
      TRACKING SYSTEM AND
      REPORTING PRICES COULD
      ASSIST PROGRAM DEVELOPMENT
-------------------------------------------------------- Chapter 4:2.4

If EPA could charge fees to help cover the costs of developing and
administering an allowance tracking system, recording of trades of
CO2 allowances would be more rapid.  In turn, faster tracking would
not only enhance EPA's ability to monitor environmental compliance
but would also reassure market participants, who view the tracking
system as the official means to record their emissions allowances. 
To the extent that better tracking protects an ownership claim, it
can facilitate trading. 

EPA has cited limited budget and staffing resources and the need to
add internal controls and auditing capability as reasons for delays
in developing the tracking system for the SO2 program.  Also because
of these constraints, the transactions must currently be entered in
the tracking computer system "by hand" rather than electronically. 
EPA allows itself up to 5 days to record trades in SO2 allowances. 
Although EPA has taken less than 5 days to record trades to date, it
set this time period to handle the heavy trades expected near the end
of each year. 

The SO2 allowance tracking system does not require utilities to
report allowance prices because, according to EPA officials, doing so
is not necessary to determine whether utilities are in compliance. 
Nor does EPA require utilities to report every allowance trade. 
However, to help reduce uncertainty about the price of CO2
allowances, EPA could require utilities to report such prices, along
with the number of allowances they traded to the tracking system. 
Alternatively, FERC could gather information on prices and volumes of
allowances traded and could report trends as it does now for other
commodities, such as coal, that utilities use to generate
electricity. 


   DESIGNING A CARBON DIOXIDE
   TRADING PROGRAM REQUIRES
   CONSIDERATION OF OTHER
   IMPORTANT ISSUES
---------------------------------------------------------- Chapter 4:3

Several other issues have implications for the effectiveness of a CO2
trading program.  As in the case of SO2, the way state public utility
commissions and FERC regulate public utilities can encourage or
discourage trading of CO2 allowances.  However, sources of CO2
emissions are much more varied than they are for SO2, so decisions
about what sources to include in a CO2 allowance trading program are
more critical.  Whether to allow and how to implement trading across
national boundaries are also important considerations. 


      ECONOMIC REGULATION OF
      PUBLIC UTILITIES IS
      IMPORTANT
-------------------------------------------------------- Chapter 4:3.1

A CO2 trading program, like the SO2 program, would involve the
nation's electric utilities.  As the SO2 program matures, state
public utility commissions and FERC may develop regulations that do
not discourage trading in SO2 allowances.  To the extent that this
happens, a CO2 trading program could also proceed more smoothly. 


      VARIED SOURCES OF EMISSIONS
      COULD MEAN EXTENDING CO2
      ALLOWANCE TRADING BEYOND
      ELECTRIC UTILITIES
-------------------------------------------------------- Chapter 4:3.2

Utilities account for 70 percent of SO2 emissions in the United
States but only 36 percent of CO2 emissions.  CO2 emissions from
sources besides utilities may thus have to be reduced.  As a logical
first step, CO2 allowance trading could be extended to industrial
plants suited to allowance allocation and monitoring in much the same
way as utilities are.  According to one study by an official of EPA's
Acid Rain Division,\5 possible candidates include manufacturers of
aluminum, cement, and lime.  However, mobile sources, such as
automobiles, trucks, and airplanes, which account for 32 percent of
CO2 emissions, might require another approach. 

One option for controlling CO2 emissions from mobile sources could be
to regulate the carbon content of fuels.  Instead of individually
monitoring the emissions of millions of automobiles, trucks, and
airplanes, refineries that produce these fuels would be allocated
allowances consistent with the desired reductions of CO2 emissions
from mobile sources.  Trading would determine the price of
allowances, and refineries would share the cost of allowances with
consumers through increased fuel prices. 

Designing a system that includes other activities that contribute to
overall CO2 levels is considerably more complex because it is
difficult to estimate and monitor the contribution of these
activities to CO2 emissions levels.  For example, several types of
land use lead to CO2 emissions, such as forest clearing for
agriculture or urban and industrial projects, and logging.  In
addition, soil and forest degradation lead to higher levels of CO2. 
Conversely, reforestation can lead to reductions in CO2.  However,
data on releases of CO2 by forest degradation through logging,
shifting cultivation, erosion, lowering of groundwater tables, and
desertification are of poor quality or unavailable.  In addition,
tracking the impact of industrial and residential development on CO2
emissions would be daunting.  For this reason, including these
sources of CO2 in a carbon trading program could make it unworkable. 


--------------------
\5 B.  D.  Solomon, Global CO2 Emissions Trading:  Early Lessons From
the U.S.  Acid Rain Program, EPA, Acid Rain Division (Aug.  1994), p. 
25. 


      INTERNATIONAL TRADING COULD
      INCREASE COST SAVINGS
-------------------------------------------------------- Chapter 4:3.3

Unlike SO2, which can lead to regional problems of acid rain, CO2
poses a global environmental threat.  Monitoring and enforcing
emissions reductions would be less difficult in a domestic CO2
trading program than in an international trading program, but the
potential cost savings from trading are much larger if CO2 trading is
extended across national borders. 

CO2's climate-warming potential is independent of where it is
emitted.  As a result, the geographic location where CO2 emissions
and reductions occur is not an issue in protecting against the threat
of climate warming.  This fact facilitates trading because it
enhances the fungibility of CO2 allowances; that is, an allowance to
emit CO2 in one place is equivalent to an allowance to emit in any
other place. 

Extending the trading of CO2 allowances across national borders
raises a number of important issues.  Developing nations might resist
an initial distribution of CO2 allowances based on historical
emissions levels because of concerns that such a distribution could
impede their economic growth.  On the other hand, industrialized
countries might regard requirements to reduce emissions from their
current levels as unfair, given past investments that they have made
to reduce pollution. 

Implementing effective monitoring and enforcement would also be a
problem.  Many countries have not invested as many resources in
environmental protection as the United States has.  As a result, the
quality of data on global emissions is often poor, or the data are
nonexistent.  Nonetheless, the potential cost savings are greater if
trading is extended across borders because many nations use older and
more polluting production technologies than the United States.  To
the extent that reducing CO2 is cheaper in these other countries,
they would be net sellers of CO2 allowances to the United States.  In
addition, a decision by the United States to reduce its CO2 emissions
unilaterally could result in exporting and increasing CO2 emissions
abroad.  This "slippage" in a domestic trading program might lead to
much smaller reductions in CO2 worldwide than expected. 

One way to extend the scope of a domestic CO2 trading program is
through bilateral trading between the United States and another
country.  An experiment in bilateral trading could make it easier to
determine how to make trading in CO2 allowances feasible across
national borders.  And, if successful, it could serve as a catalyst
for other bilateral or multilateral arrangements. 


      RESTRICTING CO2 EMISSIONS
      COULD AFFECT THE MARKET FOR
      SO2 ALLOWANCES
-------------------------------------------------------- Chapter 4:3.4

One of the challenges of developing a trading program to comply with
lower CO2 emissions limits is doing so without disrupting the ongoing
SO2 program.  A program to reduce CO2 emissions could reduce the
demand for SO2 allowances enough to derail the market in SO2
allowances.  For instance, depending on the size of the CO2 reduction
mandated, coal-fired utilities might have to switch to natural gas to
comply.  Because the combustion of natural gas produces no SO2,
utilities would no longer need SO2 allowances, thereby reducing their
value.  Utilities that bought large numbers of SO2 allowances to
comply with title IV could see the value of their allowances
diminish.  Similarly, large investments in scrubbers built to reduce
SO2 could be wasted if utilities switched to natural gas, because
scrubbers cannot remove CO2.  To the extent that companies
anticipated these investment losses, their enthusiasm for
participating in such trading programs could wane, possibly resulting
in squandered opportunities to protect the environment at less cost. 


MODELING ANALYSIS OF THREE
ALLOWANCE TRADING SCENARIOS
=========================================================== Appendix I

In this appendix, we present the results and methodology of our
consultant's modeling analysis.  Our consultant analyzed three
allowance trading scenarios for Phases 1 and 2.  The purpose of the
analysis was to use the most recent data available to estimate (1)
the economic potential for trading among affected utilities, (2) the
economic impact of reduced trading on the nation, and (3) the
economic impact of reduced trading on each state.  To do so, our
consultant estimated the costs of mandated SO2 reductions under three
trading scenarios: 

traditional "command-and-control" compliance with no trading,

trading within utilities only,\1 and

increased allowance trading between utilities. 

These estimates as well as projected impacts of trading for each
state are presented below.  In addition, the extra emissions
reductions expected in each state in Phase 1 are listed.  We
contracted with a consulting firm, Van Horn Consulting of Orinda,
California, to conduct this modeling analysis. 


--------------------
\1 This scenario also includes trades between utilities that have
already been announced. 


      DESCRIPTION OF THE MODELING
      EXERCISE
------------------------------------------------------- Appendix I:0.1

Utilities' strategies and costs for meeting the SO2 emissions
reductions set by the Clean Air Act Amendments of 1990 were projected
for Phase 1 (1997), early Phase 2 (2002), and later Phase 2 (2009). 
The decisions of utility systems on how they would comply were
simulated using data at the unit level and on utility systems'
requirements for over 200 utility systems.  Detailed information on
all existing and announced coal- and oil-fired generating units over
25 megawatts was used.  Projections of compliance costs under command
and control, internal trading, and interutility trading are based on
simulations of the operating characteristics of the plants and
utility systems. 


      MODELING APPROACH AND DATA
------------------------------------------------------- Appendix I:0.2

The analysis begins with data and calculations for each individual
generating unit and results in projections of emissions, generation,
operating characteristics, and costs for each unit and its utility
system.  The information describing each unit included on-line and
retirement dates; net generating capability; heat rates, generation
levels, and emissions; existing emissions control equipment;
emissions limits before the Clean Air Act Amendments of 1990 and the
number of allowances allocated under the act; and the composition and
costs of alternative fuels.  Fuel-related costs included
site-specific fuel transportation costs, projected fuel prices
excluding transportation, unit-specific costs, and penalties for fuel
switching.  Information characterizing historical and current unit
operations was derived largely from data provided by the North
American Reliability Council, the Federal Energy Regulatory
Commmission (FERC), and the Department of Energy (DOE).  Other data,
such as projected capacity factors for different time horizons, have
been developed through additional analyses and evaluation of
forecasts, such as those provided by the North American Reliability
Council regions, DOE's Energy Information Administration, and various
analysts. 


      ESTIMATION PROCEDURES
------------------------------------------------------- Appendix I:0.3

The objective of modeling each power plant unit in detail is to
characterize each unit--including its fuel, control technologies, and
costs--under each of several levels of potential emissions
reductions.  The model selects the most economical combination of
fuel and control technology meeting each progressive emissions
reduction, typically by examining different fuels and fuel blends
along with the retrofit of different emissions control technologies
required to achieve each emissions reduction.  The model then selects
each utility's overall compliance strategies from among the numerous
alternatives available at all of the utility's individual units.  A
wide variety of unit-specific and general constraints on what
compliance measures are required, allowed, or prohibited can be
specified, as can varied constraints on allowance trading among units
and among systems.  The model also assumes that compliance measures,
such as Phase 1 scrubber retrofits that utilities have already
announced, occur. 

Under the command-and-control scenario, the model assumes that each
unit selects the least-cost alternative for reducing emissions that
would comply with that unit's SO2 allowance allocation, without any
allowance trading.  Under the internal trading scenario, the model
assumes allowance trading only among units within each utility
system, and each utility selects the lowest marginal cost measures
among all the available alternatives at the different units within
its own system to meet its systemwide allocation of emission
allowances.  However, the model assumes that interutility trades and
allowance transfers that utilities have announced to date occur. 
Under maximum interutility trading, the model derives the lowest
marginal cost measures on a nationwide basis, regardless of who owned
the units, to meet the total allowance allocation or cap at the
lowest cost.  The model balances the resulting undercontrol and
overcontrol of emissions by different utility systems relative to
their individual total allowance allocations with the net allowance
purchases and sales, respectively, for those systems. 


      RESULTS OF THE MODELING
      EXERCISE
------------------------------------------------------- Appendix I:0.4

Our consultant's modeling results suggest that the economic basis for
more trading exists.  Estimated differences among utilities' marginal
compliance costs appear sufficient to warrant trading in both Phase 1
and Phase 2.\2 Figure I.1 shows a large variance in utilities'
estimated compliance costs during Phase 1.  Figure 2.3, in chapter 2,
shows a similar variation in marginal costs during Phase 2. 

   Figure I.1:  Estimated Costs of
   Reducing Emissions Compared
   With Allowance Price for Phase
   1 Utilities

   (See figure in printed
   edition.)

Note:  Nineteen potential sellers have incremental costs at or near
zero.  Costs are in 1992 dollars per ton. 


--------------------
\2 Marginal cost refers to incremental cost. 


      COSTS AND EMISSIONS UNDER
      THREE TRADING SCENARIOS
------------------------------------------------------- Appendix I:0.5

Our consultant used the most recent data available to estimate the
costs of attaining mandated SO2 reductions.  Annual costs were
estimated for 3 years in the program:  1997 (Phase 1), 2002 (Phase
2), and 2009 (late Phase 2).  For each trading scenario, table I.1
presents these cost estimates and projections of SO2 emissions as
utilities draw down the stock of allowances saved from Phase 1 and
use them for compliance in Phase 2. 



                          Table I.1
           
             Projected Annual Costs and Emissions

                  (Millions of 1992 dollars)


Year                      Cost   SO2  Cost   SO2  Cost   SO2
------------------------  ----  ----  ----  ----  ----  ----
1997                      $1,3  11,1  $1,0  11,4    \a    \a
                            10    85    80    71
2002                      4,49  7,49  2,59  8,93  $1,4  10,4
                             5     2     2     3    40    19
2009                      4,91  7,40  3,07  8,21  1,99  9,35
                             3     5     6     3     7     2
------------------------------------------------------------
Note:  SO2 emissions are in thousands of tons. 

\a The projection for internal trading in 1997 represents a likely
scenario given utilities' current compliance strategies.  The impacts
of interutility trading were not estimated for Phase 1 because most
utilities had already committed to other strategies. 


      ESTIMATED COST SAVINGS AMONG
      STATES FROM GREATER TRADING
------------------------------------------------------- Appendix I:0.6

Our consultant's modeling suggests that more trading could reduce
utility compliance costs in many states.  Table I.2 compares the
projected annual savings from greater trading with current levels of
internal trading. 



                          Table I.2
           
              States' Estimated Annual Costs and
                Potential Savings From Trading

                  (Millions of 1992 dollars)

                       Costs
                        with     Costs              Potentia
                     command      with  Costs with         l
State in which           and  internal  interutili  savings\
plant is located     control   trading  ty trading         a
------------------  --------  --------  ----------  --------
PA                       429       270         135       135
IN                       454       318         235        83
NY                        88        32      (46)\b        78
FL                       187       135          75        60
DE/NJ/MD/DC\c            191       114          56        58
IL                       254       182         132        50
WI                        61         2        (48)        50
AL                       196       127          78        49
NC                       209       107          62        45
LA/MS\                    57        59          14        45
TX                        71         4        (38)        42
KY                       187       140         101        39
OH                       648       399         360        39
SD/ND                     26        24        (11)        35
CA/NV                      1         1        (32)        33
AR                        28        28         (4)        32
AZ/NM                     13         1        (28)        29
UT/WY                     19         0        (29)        29
CT/MA                     28        22         (6)        28
MI                        37         0        (24)        24
MO                       151        64          41        23
OK                        47        18         (4)        22
SC                        95        46          24        22
MN                        13         0        (19)        19
TN                       214       192         175        17
VA                       114        39          22        17
KS                         0         0        (13)        13
IA                        56        25          15        10
GA                       155        31          21        10
NE                        12         0         (7)         7
CO                        41         0         (5)         5
WV                       361       204         201         3
ME/NH/RI                  35         6           5         1
OR/WA/MT                  17         2           2         0
============================================================
Total                  4,495     2,592       1,440     1,152
------------------------------------------------------------
Note:  Estimates for the year 2002. 

\a The column "potential savings" compares internal trading only with
maximum interutility trading. 

\b Parentheses indicate opportunities for states to sell enough
allowances to offset their costs and make a net profit. 

\c States with few utilities have been aggregated. 


      PROJECTED ANNUAL EMISSIONS
      IN PHASE 1
------------------------------------------------------- Appendix I:0.7

Based on the compliance strategies currently being chosen,
projections for Phase 1 suggest that utilities in many states will
attain extra reductions in emissions, as shown in table I.3. 



                          Table I.3
           
           Projected Extra Emissions Reductions in
                       Phase 1 by State

                      Lega  Projecte
                         l         d     Extra       Percent
                      limi  emission  reductio         extra
State                  t\a         s       n\b     reduction
--------------------  ----  --------  --------  ------------
OH                    1,53     1,063       471        30.70%
                         4
GA                     590       381       209         35.42
WV                     542       348       194         35.79
IN                     756       570       186         24.60
MO                     478       306       172         35.98
PA                     666       495       171         25.68
NY                     274       107       167         60.95
WI                     241       106       135         56.02
KY                     449       320       129         28.73
TN                     394       290       104         26.40
AL                     228       183        45         19.74
MI                     148       108        40         27.03
MN                      78        50        28         35.90
ME/NH/RI\c              52        35        17         32.69
IA                      52        46         6         11.54
CT/MA                   11         6         5         45.45
FL                     177       173         4          2.26
IL                     602       598         4          0.66
LA/MS                   66        62         4          6.06
DC/DE/MD/NJ            212       209         3          1.42
NC                       3         0         3        100.00
KS                       4         2         2         50.00
VA                      10         9         1         10.00
------------------------------------------------------------
Note:  Data are for 1997 and in thousands of tons per year.  Only
utilities affected by Phase 1 are included in state data, except for
utilities only affected by Phase 2 that have purchased allowances for
future use, like those in North Carolina. 

\a The category "legal limit" includes initial annual coal and oil
allowance allocations plus scrubber bonus pool allowances, projected
substitution unit allowances, auction purchases, internal utility
allocations across state lines, and net trades. 

\b Extra reduction below limits set by title IV. 

\c States with few utilities have been aggregated. 


MAJOR CONTRIBUTORS TO THIS REPORT
========================================================== Appendix II

RESOURCES, COMMUNITY, AND ECONOMIC
DEVELOPMENT DIVISION, WASHINGTON,
D.C. 

Bernice Steinhardt, Associate Director
Charles W.  Bausell, Jr., Project Director
Thomas H.  Black, Staff Member
Robert G.  Taub, Staff Member
Phyllis Turner, Communications Analyst

CHICAGO/DETROIT FIELD OFFICE

Melvin Rodriguez, Staff Member

SAN FRANCISCO FIELD OFFICE

Patricia Cazares, Staff Member

OFFICE OF THE GENERAL COUNSEL

Karen Keegan, Senior Attorney

