Co2 Trading Issues : Volume 2 : Choosing The Market Level For Trading : Final Report


C02 TRADING ISSUES
Volume 2:
Choosing the Market Level for Trading
Final Report
Prepared by
Anne E. Smith
Anders R. Gjerde
Lynn I. DeLain
Ray R. Zhang
DECISION FOCUS INCORPORATED
1155 Connecticut Avenue NW
Washington, DC 20036
Prepared for
Adaptation Branch, Climate Change Division
Economic Analysis & Research Branch, Economic Analysis & Innovation Division
Office of Policy, Planning and Evaluation
U.S. Environmental Protection Agency
Washington, DC 20460
Contract No. 68-CO-0021
Project Manager	Chief, Adaptation Branch
Neil A. Leary	Joel D. Scheraga
May 1992

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PREFACE
There has been increasing concern within the international community about rising
concentrations of carbon dioxide (C02) and other greenhouse gases in the atmosphere that may
contribute to global climate change. The United States and other nations have been, and will
continue, grappling with the question of whether or not to constrain the emissions of C02.
Should a decision be made to constrain greenhouse emissions, there exists a variety of policy
tools that could be employed to achieve this objective. Discussions of policy tools have recently
focused on approaches that rely upon the creation of market incentives that would induce
sources to reduce their emissions. The advantage of these market incentive approaches is that
they offer the possibility of controlling emissions at much lower costs than are likely to be
achieved through more traditional regulatory approaches.
This three volume report examines one market incentive approach to controlling
emissions of C02: tradeable permits. There are a number of points in the economy at which
a tradeable permit system might be implemented to control C02. For example, permits might
be required for supplying carbon-based energy. Alternatively, carbon permits might be required
of consumers of carbon-based energy. Potential performance of alternative permit market
designs and potential implementation problems are investigated in the report.
Recommendations are made for market designs that promise to be more cost-effective than other
market designs.
Volume 1 of the report examines emissions of C02 from industry, the largest source of
emissions from energy consumption. Volume 2 examines alternative carbon permit market
designs and evaluates the potential performance of the alternatives considered. Volume 3
examines the potential behavior of electric utilities in a carbon permit market and the
implications for the functioning of a permit market.
Designing a cost-effective C02 trading system that can be readily implemented and
enforced is a complex undertaking. This study illuminates these complexities and provides
insights useful to policymakers considering such a system.
Neil A. Leary Joel D. Scheraga
EPA Project Manager Chief, Adaptation Branch
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EXECUTIVE SUMMARY
Tradeable carbon permits and carbon taxes create market incentives for sources to reduce
their emissions of carbon dioxide (C02). The advantage of abatement policies that rely on
market incentives is that they offer the possibility of controlling emissions at much lower costs
than are likely to be achieved through more traditional regulatory approaches. There are,
however, a variety of ways in which tradeable carbon permits or carbon taxes might be
implemented and the choice of implementation can be important to the costs and performance
of the policy. This three volume report examines alternative ways of implementing a tradeable
carbon permit system for controlling emissions of C02.
The focus of the report is limited to the control of C02 emissions from fossil energy
production and consumption, which accounts for nearly all US C02 emissions. The quantity of
C02 generated by energy production and consumption is largely a function of the carbon content
of the fossil energy input to economic activity. Because capture and disposal of generated C02
is prohibitively costly, carbon content of fossil energy input also determines the quantity of C02
emissions. Thus a system of carbon permits for fossil energy is equivalent to a system of permits
for emissions of C02 from fossil energy use. This allows a great deal of flexibility for choosing
where in the energy system to implement a permit market for the control of C02. For example,
permits might be required of suppliers for the carbon content of fossil energy supplied to the
market. Alternatively, permits might be required of consumers for the carbon content of the
fossil energy consumed.
Although these alternative permit systems can be designed to achieve equivalent C02
abatement, the costs of the emission reductions and their distribution can vary significantly. This
report examines a number of key issues that will influence the costs of COz abatement and their
distribution for alternative carbon permit market designs. Volume 1 examines emissions of C02
from industry, the largest source of carbon emissions. Volume 2 examines alternative carbon
permit market designs and evaluates the potential performance of the alternatives considered.
Volume 3 examines the potential behavior of electric utilities in a carbon permit market and the
implications for the functioning of a permit market.
The alternative carbon permit market designs evaluated include both supplier and
consumer permit systems. There are a number of points in the supply chain at which a carbon
permit market might be implemented. Three alternative designs for a supplier permit market
are examined: (i) a market that requires primary energy extractors and importers to obtain
carbon permits, (ii) a market that requires energy processors to obtain carbon permits for the
products that they produce, and (iii) a market that requires energy distributors to obtain carbon
permits for the energy that they sell to final consumers. The consumer carbon permit market
designs examined include (i) a market that would require all carbon energy consumers to obtain
permits, and (ii) a market that would require only major industrial carbon energy consumers to
obtain permits.
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S-2 Executive Summary
It is the recommendation of the report that, if a carbon permit market approach is
adopted for C02 emission control, it should be implemented on the supply side of energy
markets. A supplier permit market for carbon is expected to be a more cost-effective C02 control
policy than a consumer permit market. However, it is not clear which point in the supply chain
is the most promising for implementation of a carbon permit market without further study.
A carbon permit market that requires all consumers of carbon energy to obtain permits
for the carbon content of the energy that they bum would include millions of participants in the
market. The administrative costs of monitoring, operating, and enforcing a permit market with
millions of participants is prohibitively high. These costs might be reduced by limiting a
consumer permit market to include only relatively large consumers of carbon energy.
One possibility that is examined is to limit coverage to industrial emitters of carbon.
Limiting a carbon permit market for consumers to industrial sources would reduce the number
of market participants from millions to tens of thousands. Limiting the market further to the six
industrial sectors that are the largest sources of C02 would reduce the number of market
participants to under twenty-thousand and still include 90% of industrial emissions in its
coverage.
However, limiting a consumer permit market to only industrial energy consumers would
exclude 40% of US C02 emissions from control. This eliminates many opportunities for
potentially low cost emission reductions from residential, commercial, and transportation sources
and promises to raise the control costs per ton of C02 abated. The control costs of achieving a
chosen C02 target might be reduced by complementing a permit market for industrial energy
consumers with additional policies that are targeted at other energy consuming sectors. But
implementation and operation of two or more separate programs for control of different sources
of C02 will add to administrative costs.
A further disadvantage of a consumer permit market for carbon are complexities that
arise from existing regulations of electric utilities. Rate of return regulations, restrictions on
capital gains and losses, and other regulations may lead electric utilities to make inefficient
choices. Inefficient behavior by utilities can potentially raise the costs of any C02 control policy,
but the problem may be particularly severe for a carbon permit market that includes electric
utilities as direct market participants.
In contrast, a supplier permit market for carbon energy would achieve almost complete
coverage of C02 emissions under a single, unified program, while including fewer market
participants than would a market for industrial energy consumers. The reduced number of
market participants would reduce the administrative costs of a permit market without
concentrating the market to a degree that would raise concerns regarding market power. The
broad coverage of emissions, the relatively small number of market participants, the lack of
significant market power, and the reliance on a single program for all sources suggest that a
supplier permit market is likely to be more cost-effective for C02 control than a consumer permit
market.
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Executive Summary S-3
Of the various points in the supply chain at which permit trading might be implemented,
none emerges as clearly superior. One factor that may influence the cost-effectiveness of C02
control is the potential for leakages of emissions that are unconstrained by a permit market. If
carbon permits are required at the point of distribution, upstream emissions from energy
extraction, refining and processing of energy, and transmission represent potential leakages.
These leakages could narrow the range of options for emission reductions and raise costs. In
contrast, if carbon permits are required at the point of extraction, these emissions would occur
downstream from the permit market and would not represent leakages.
Another factor that may influence the cost of C02 control is whether or not the policy
imposes constraints that have no emission reduction benefits. Energy used as feedstocks does
not contribute to C02 emissions and requiring permits for feedstocks would raise costs without
providing any emission abatement benefits. If carbon permits are required at the point of
extraction, identifying and exempting energy that will ultimately be used as feedstocks may be
administratively difficult and costly, while failure to exempt feedstocks will raise control costs.
Alternatively, if carbon permits are required at the point of distribution to consumers, identifying
and exempting feedstocks may be less costly.
A third factor that may influence the cost of COz control is the ease of monitoring and
enforcing compliance with permit requirements. Due to vertical integration of firms that supply
energy, monitoring and enforcing compliance may be costly at the levels of extraction and
processing. Because there is little vertical integration beyond the point of distribution of energy
to energy consumers, monitoring and enforcement costs may be lowest for a carbon permit
market at the point of distribution. The net effect of these various factors on the costs of C02
reductions for the alternative permit market designs is ambiguous at this time and warrants
further study.
The recommendations of the report are based on an evaluation of the cost-effectiveness
of alternative permit markets. Another factor that may also guide the selection and design of
a C02 abatement policy is the distribution of the costs of abatement. The report demonstrates
that a carbon permit market for suppliers can yield a very different distribution of costs than
would a carbon permit market for consumers. If permits are required of suppliers, the cost of
emission reductions may be borne more heavily by energy consumers than by suppliers. If,
alternatively, permits are required of consumers, some of these costs may be shifted from energy
consumers to energy suppliers. Of course most energy is consumed as an intermediate input
by firms, and the ultimate distribution of costs among different portions of the population have
not been investigated for this study.
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Volume 2: Choosing the Market Level for Trading
Table of Contents I
TABLE OF CONTENTS
—Volume 2: Choosing the Market Level for Trading—
Section	Page
1	INTRODUCTION AND OVERVIEW
Synopsis of the Issue and Analysis	1-1
What Would Trading Requirements Consist of at the Different
Market Levels?	1-6
Regulation of Industrial Sources of COz	1-7
Regulation of All End-Users of Fuel Services	1-7
What Are the Welfare Distribution Impacts from Trading at Different
Market Levels?	1-8
An Hypothetical Example	1-9
2	HOW MANY SOURCES ARE THERE AND WHERE?
Industry Structure at the Fossil Fuel Primary Production Level	2-1
Number of Sources	2-2
Size and Regional Distribution	2-4
Market Concentration	2-5
Interrelationships Among the Sub-levels	2-7
Downstream Price Signals	2-10
Industry Structure at the Industrial Combustion Level	2-11
Number of Sources	2-11
Size and Regional Distribution	2-12
Market Distortions	2-18
The End-Use Level of the Fossil Fuels Markets	2-19
Numbers of Sources	2-19
Regional Distribution	2-19
Implementing Permit Trading at the End-Use Level:	A Hybrid Approach 2-21
Summary	2-23
3	WHAT AMOUNT OF EMISSIONS WOULD BE SUBJECT TO CONTROL?
Permit Trading at the Primary Production Level	3-1
Permit Trading at the Industry Level	3-5
Permit Trading at the End-Use Level	3-7
Summary	3-8
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tl Table of Contents
Volume 2: Choosing the Market Level for Trading
TABLE OF CONTENTS (continued)
Section	Page
4	WHAT ARE THE MECHANISMS FOR MONITORING AND
ENFORCEMENT?
Number of Sources	4-1
Estimating and Reporting Emissions	4-2
Vertical Integration	4-4
Summary	4-4
5	CONCLUSIONS
Trading at the Primary Producer Level	5-2
Trading at the Industrial Level	5-3
Trading at the End-Use Level	5-3
Controlling End-Uses at the Manufacturer Level	5-4
Recommendations for Further Study	5-4
APPENDIX A: Detailed Industry Data	A-l
APPENDIX B: Top Twenty Producers in Supplier Markets	B-l
APPENDIX C: Car Manufacturers in a Permit Trading Program	C-l
REFERENCES	R-l

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Volume 2: Choosing the Market Level for Trading
Table of Contents lii
LIST OF FIGURES
Figure	Page
1-1	Illustration of Components of Market Surplus Concept	1-9
1-2	Hypothetical Market for Oil Products	1-10
1-3	Market Conditions After Permits Allocated to Primary
Producers: (A) No Permit Trading Is Allowed; (B)
Permit Trading Is Allowed	1-11
1-4	Market Conditions After Permits Allocated to Consumer
Level: (A) No Permit Trading Is Allowed; (B)
Permit Trading Is Allowed	1-15
2-1	Fossil Fuel Pathways to the End-User	2-2
2-2 Number of Sources at Primary Production Level	2-3
2-3 Major Fossil Fuel Extraction Regions in the U.S.	2-4
2-4 Histogram of Carbon Extracted, by State	2-5
2-5 Key Locations for Electric Units Using Different Fuels	2-13
2-6 Geographical Locations of Major COz Emitting Industries	2-13
2-7 Histogram of Carbon Emissions from Major Industrial
Sources, by State	2-14
2-8 Comparison of Top 15 States when Ranked (A) by Carbon Extraction
and (B) by Carbon Emissions from Major Industrial Sources	2-17
2-9 Geographical Concentrations of Various Types of Chemical
Industries	2-18
2-10	Histogram of Total End-user Carbon Emissions, by State	2-20
3-1	Considerations in Trading at Primary Production Level	3-2
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Iw Table of Contents
Volume 2: Choosing the Market Level for Trading
LIST OF TABLES
Table

Page
1-1
Evaluation of C02 Allowance Trading at Different Market Levels
1-4
1-2
Sample of Price Elasticities of Demand for Fossil Fuels
1-13
2-1
Market Concentration at Primary Production Level, 1989
2-6
2-2
Interrelationships Among Fossil Fuel Markets
2-8
2-3
Number of Sources at the Industry Level
2-11
2-4
Source Units at the End-Use Level, 1986
2-20
2-5
Producers of C02 Emitting Devices, 1986
2-21
3-1
U.S. Fossil Fuel Consumption, 1989
3-4
3-2
Total U.S. C02 Emissions Estimated from Fuel Production, 1989
3-4
3-3
Emissions Estimates in U.S. Industrial Sector, 1988
3-6
4-1
Options for Estimating Emissions
4-3
5-1
Evaluation of C02 Allowance Trading at Different Market Levels
5-1
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1
INTRODUCTION AND OVERVIEW
The current debate on appropriate methods for controlling emissions of greenhouse gases
frequently refers to the use of tradeable emissions permits. In fact, prominent Congressional
activity, in the form of the Cooper/Synar Bill, would introduce an offsets program for new
sources of CO^1 Despite the attention that emissions trading generates, relatively little has been
done to investigate the behavior of trading under different implementation options. This three
volume report covers several topics of interest for implementation planning:
Volume 1: Emissions from Industry
Volume 2: Choosing the Market Level for Trading
Volume 3: Effects of Utility Regulation
This volume (Volume 2) looks in some detail at the issue of implementing trading requirements
at different levels of the market. The topic is first defined and described, theoretical aspects are
summarized, and specific market data are presented in an effort to understand better the relative
advantages of the different options posed. Much of the data presented in Volume 1 is also used
in the analysis that follows.
SYNOPSIS OF THE ISSUE AND ANALYSIS
The issue of trading at different levels of the market is one that rarely gains attention in
the theoretical literature. It arises because many goods go through a series of manufacturing
stages before the point of final consumption. Unless these stages are fully integrated vertically,
there is a sequence of markets between the initial product development and the final purchase
by the consumer. Fossil fuels provide a good example of this type of market sequence. The
initial product may be crude oil. This is captured from a well, and may then be sold to a
company that will refine it into final consumer products. There may be additional intermediate
markets, such as companies that buy crude from small wells, and in turn sell their accumulated
crude to refiners. Distributors may purchase refined products from refiners before they reach
the point of sale to the final consumer. Vertical integration is present to some extent in these
markets, but intermediate markets do exist.
1. Offsets are very closely related to emissions allowances (which are used for S02 controls in the 1991 Clean
Air Act Amendments). The main differences between the two concepts are: (1) the supply of offsets is
created by market forces while allowances are created in a fixed quantity by regulators; and (2) offsets tend
to apply only to new sources, while allowances tend to apply to an entire set of sources.
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1-2 Introduction and Overview
Volume 2: Choosing the Market Level for Trading
Given that an estimate of the ultimate COz emissions resulting from a product's use can
be made at each market stage, it would be possible to impose a C02 emissions trading scheme
at any of the market levels. For instance, one might require that each oil well have sufficient
permits to cover the carbon contained in its total sales of crude. Or, one might instead allow
extraction processes to proceed freely, but require that permits be required for each unit of
carbon emitted when the petroleum-based fuel is burned. In the first case, the cost of the
permits will be passed through the market, ultimately affecting consumer demand. In the
second case, the cost of the permits will directly affect demand, which will in turn pass
incentives back to the initial producers. However, a variety of reasons may make one system
more functional than another. This study evaluates C02 permit trading at different market levels
subject to three basic criteria listed below. While we believe that each of these criteria should
be given considerable attention in evaluating policy options, the list is not intended to be
exhaustive. The criteria focused on in the study are:
1. Costs of monitoring and administering a trading program. This will
depend in part on the number of individual companies that make up each
of the market levels, which can vary substantially.
2. Effectiveness. We examine two aspects of market effectiveness: (a) There
may be some "leakage" in markets, meaning that some of the ultimate
emissions might not be accounted for. Similarly, some economic activities
may be penalized at a rate greater than their actual contribution to
emissions. The extent of this type of problem will vary at different levels
of the market, (b) Market power may exist in either the market for the
product, or in the market that will be created for allowances. Such market
power could alter the effectiveness of allowance trading at one market
level but not at others.
3. Distribution. The sharing of control costs (i.e., effects on welfare
distribution) will vary. This will include geographical as well as sectoral
distribution of the regulatory burden. Economic analysis does not itself
indicate what distribution is more desirable, but an understanding of
distributional implications is also an important element for the policy
making process.
In this volume, three generic market levels are considered as options for implementing
C02 trading:
¦ Regulation at the level of the primary producer of fossil fuels.
¦ Regulation of the key industrial points of fossil fuel combustion.
¦ Regulation of all end users of fossil fuel-based energy services.
There are many possible combinations of these three options that should be kept in mind when
devising an implementation plan. However, for purposes of understanding the relative
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Volume 2: Choosing the Market Level for Trading
Introduction and Overview 1-3
advantages of each, we focus on these three basic underlying options and note obviously
advantageous combinations where appropriate.
Initial analyses using EPA's GEMINI model for assessing national impacts of climate
change policies have indicated that there may well be some distinct differences in outcomes
when trading is implemented at the different market levels. In one example, the model found
that the social benefits of trading to reach stabilization were substantially greater when trading
occurred among producers of raw fossil fuels, compared to when trading occurred among those
who distribute refined fuels to fuel-using customers.2 GEMINI does not currently take account
of all of the issues mentioned above, and the cause of the differences captured by GEMINI
appears to be the leakage issue. GEMINI is also a very aggregate model with no detail on
numbers of firms in a given market or their locations. More investigation is needed of the
nature of these markets to develop an understanding of the best market level to implement
trading, should such regulations be desired. This study takes a first step in the direction of
collating the relevant information for such an assessment. The rest of this volume is organized
to cover the following general questions related to the three evaluation criteria:
¦ YJhat would trading requirements consist of at the different market levels? (next
part of Section 1) This is to provide a clear explanation of what is meant
by this issue, before moving to a more detailed analysis.
¦ What are the welfare distribution impacts from trading at different market levels?
(also in Section 1) Welfare distribution is a theoretical concept used in
economics to investigate the relative gains and burdens under different
market structures. Investigation of this effect is useful for motivating the
point that trading at different market levels can produce situations that
will affect various segments of the population quite differently, even if
results are equivalent in terms of their overall effectiveness in reducing
emissions and cost.
¦ How many sources are there in each market level, how are they distributed by
size, and where are they geographically located? (Section 2) Trading will
involve a larger or smaller number of affected entities at different market
levels. Also, the affected entities may be more or less geographically
concentrated under different market level trading schemes. Potential
market power problems are also important to identify. All of these
concerns are addressed by a better understanding of the number, location
and relative sizes of sources at each market level, and are important in
drawing conclusions regarding costs, effectiveness, and distributive effects.
2. Scheraga, J. D. and N. Leary, Improving the Efficiency of Environmental Policy: The Implementation of Strategies
to Reduce C02 Emissions, Paper Presented to Stanford University's Energy Modeling Forum #12, Boulder
Colorado, August 27-29, 1991, p. 14. Also, "Efficiency of Gimate Policy," Nature, Vol. 354, November 21,
1991, p. 193.
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1-4 Introduction and Overview
Volume 2: Choosing the Market Level for Trading
¦	Wfcjf amount of total emissions would be subject to controls? (Section 3)
Effectiveness of a control program depends on whether a significant
fraction of the emissions are covered by the regulation in question.
Building on the data developed in Section 2, the relative degree of control
at different market levels is discussed, and options for achieving a degree
of control are suggested.
¦	What are the mechanisms for monitoring and enforcement? (Section 4) As
noted above, the ability to effectively enforce a market is also important
in determining the relative desirability of regulating at different market
levels. Enforceability may affect the effectiveness of a program, its overall
costs, and even public perceptions of fairness.
Section 5 provides a summary and conclusion, centered around Table 1-1. The key
conclusion is that the most promising level appears to be the primary producer level. After
defining that sector more fully as a series of sub-levels (extraction, refining/processing, and
distribution), the distribution sub-level, where fuel distributors sell final fuel products to users
of energy services, appears to be the best option, although with qualifications. The other
primary producer sub-levels present less enforceability, greater regional concentrations, and
issues related to treatment of imports and feedstocks. The distribution level, however, would
not account for significant upstream emissions from extraction and refining.
Table 1-1
EVALUATION OF C02 ALLOWANCE TRADING AT DIFFERENT MARKET LEVELS

# Involved
Market
Dysfunction
Potential
Degree of
Geographical
Concentration
Enforce-
ability
Emissions
Coverage
Import
Issues?
Extraction
1,000s
None
High
Moderate
High
Yes
Refining
1,000s
None
High
Moderate
High
Yes
Distribution to Users
1,000s
None
Low
High
High
No
Industries
10,000s
Electric
utility rates
regulations
Moderate
High
Low
No
All End-Users
100,000.000s
None
Low
Low
High
No
Hybrid (Equipment
Manufacturers &
10,000s
Electric
utility rates
Moderate
High
Moderate
Yes
Industry)	regulations
The industry level provides less coverage of emissions than either other level, and is
faced with an important problem area in the case of utility incentives. As Volume 3 of this
report explains in detail, utilities may fail to participate fully in an emissions trading market
except with very careful design of the implementation. Even with such care, the areas of
jurisdiction over utility decisions are so complex that the problem may not be easily
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Volume 2: Choosing the Market Level for Trading
Introduction and Overview 1-5
circumvented. Because utilities would be such a large fraction of any industrially-based C02
emissions market, the potential for disruption is a serious concern.
The end-user level is too cumbersome to administer and enforce for the entire population
of end-users. An hybrid approach that expands an industrial-based system to try to capture
most other end-user emissions is a promising idea, but in our judgment appears have less
potential effectiveness than the fuels distribution level, with no offsetting advantages other than
a possible one of social welfare distribution. The latter issue is described at the end of this
section.
The industry data collected for this study come from standard sources such as the Energy
Information Agency, the Census of Manufacturers, and industry statistical reports. The data
from these sources can be disaggregated geographically only to the state level, making it difficult
to obtain reliable estimates of the size distribution of individual facilities. The only direct
information on size distributions is for companies, which may comprise many individual
facilities in many parts of the country. These caveats should be kept in mind in interpreting
some of the specific numbers presented in this report.
This report considers the case of C02 emissions trading only, rather than all greenhouse
gases. This is in part because manmade C02 emissions come almost entirely from combustion
of fossil fuels. (Cement production is the key exception, as described in Volume 1.) Comparison
of market levels is made more clear when limited to the fossil fuels. Further, many of the other
greenhouse gases are not as clearly tied to specific markets. For example, methane emissions
are largely by-products of a large variety of activities such as agriculture, landfilling, and mining.
In each case, the level of activity (e.g., the number of acres cultivated with rice or the tons of rice
sold) is less important in determining the emissions level than the nature of the activity (e.g., the
method of fertilization, tillage, or irrigation). While CFCs do have very clear markets, they are
of less interest in discussions of trading because they are being phased out of existence. Options
for including all greenhouse gas emissions in a trading scheme could be considered after a
system has been designed to address C02 only. Doing the analysis in this order does not mean
that regulations should be phased in this order.
For this analysis, fossil fuels considered include natural gas, coal, and petroleum-based
fuels (fuel oil, gasoline, etc.). Markets for wood and other biomass fuels are not analyzed
because they pose a question of how significantly they create net emissions, if at all. Similarly,
use of waste methane, such as that captured from landfills or farming, is also not considered
because of complications in determining whether its use adds to emissions, or whether it in fact
reduces total greenhouse forcing. This could happen because (1) the methane that is captured
is itself a powerful if short-lived greenhouse gas, and (2) its use as a new fuel source could
displace more carbon-intensive coal or oil, thus reducing net carbon emissions per energy unit.
Both of these energy sources require further analysis to determine whether they would be
considered fuels that require allowances, or whether use of them would be a basis for the award
of additional allowances.
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1-6 Introduction and Overview
Volume 2: Choosing the Market Level for Trading
WHAT WOULD TRADING REQUIREMENTS CONSIST OF AT THE DIFFERENT
MARKET LEVELS?
The following subsections describe how trading at each level would be implemented.
In addition to the mechanical details of implementation, we also note what the resulting system
might "look like" to the public. Such perceptions do not provide any economic basis for selecting
among the options. They are included to help the reader visualize trading at each market level.
They are also useful to understand when ultimately preparing an implementation plan that is
acceptable within a broader framework than the purely economic comparison that is the purpose
of this study.
Regulation of the Primary Producers
Primary producers are most typically thought of as those that are involved in the
extraction of oil, gas, and coal. As noted in Table 1-1, and as will be discussed in detail in
Section 2, this is an overly simplistic definition. In fact, primary production might also be
expanded to include refiners or fuels distributors. Regardless of this distinction at the primary
level, one could require permits according to the amount of carbon in fuel extracted, without
consideration of its end-user destination. Regulation is feasible at this level of the economic
chain because the carbon emissions of the ultimate products can be anticipated quite accurately
in terms of the carbon content of the extracted primary material. This level of the market may
not be as easily incorporated into other pollution-control regulations because emissions are
usually dependent on processes and control technologies used, and not on the properties of the
raw materials alone. For fossil fuels, however, carbon emissions are very closely tied to initial
carbon in the extracted raw material.
The way emissions trading would work at the primary producer level would be that each
primary producer would be required to have a sufficient number of units of allowances for
carbon extracted and sold. Allocating allowances to the agents in the market might seem at first
as if producers were being told that there was to be a specific reduction in the historical
extraction rate. This is because there is no alternative for fossil fuel extraction enterprises as a
group to reduce carbon sold than to simply extract less. Because allowances would be tradeable,
however, market forces would result in the lower cost producers being able to buy out the
marginal producers. Thus trading would allow the final form of the extraction reductions to
occur in the most cost-effective manner from society's point of view, and some producers may
be able to actually expand extraction (for example, of natural gas) while others would reduce
production even more than their allotted allowances would require (for example, coal). Thus
the ultimate effect of tradeable carbon permits would be a shift away from carbon-intensive
fuels, and there would be no actual limitation of supplies of individual fuels, nor of the total
supply of energy services.
The cost of the allowances would be passed on to purchasers, ultimately to those who
burn the fuels, thereby providing an economic incentive to energy consumers to reduce their use
of energy, and to switch to less polluting fuels. Even though the incentives for pollution
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Volume 2: Choosing the Market Level for Trading
Introduction and Overview 1*7
reduction would be passed on to the ultimate polluters, this type of implementation could
potentially be perceived as much as an intervention in energy markets as a controlling of
pollution levels. As will be discussed below, there are also distributional effects that could have
implications for this approach, regardless of its cost-effectiveness: producers may gain more
than consumers.
Regulation of Industrial Sources of C02
Tradeable allowances could also be required at the industrial combustion point. In this
case, allowances could be tracked in terms of measured carbon emissions, giving the impression
of a more direct link to the control of pollution. The system would work by allotting, or
requiring purchase of, allowances for each unit of carbon emissions from fossil fuels. Companies
that currently burn fossil fuels would have incentives to switch to low- or no-carbon energy, and
to conserve energy, exactly as in the case of trading at the primary production level. These
reactions would feed back to the fossil fuels market in the form of a shift in output to relatively
more low- and no-carbon energy sources.
Controls on industrial sources of pollution have a strong political heritage. Yet, as
Volume 1 of this report discusses, there are many more important sources of C02 than industry
alone. In particular, transportation is equally as important as electric utilities, or as all other
industry put together. Unfortunately, with millions of vehicles, transportation amounts to an
area source created by the independent decisions of millions of citizens. Unless the options of
individual citizens are also included in the trading scheme, direct control of COz emissions will
be less effective than their indirect control via requiring allowances per unit of fossil fuel
extracted. Similarly, consumers of electricity (i.e., virtually every household as well as industrial
and commercial users) can affect the effectiveness of emissions control in the electric sector.
However, without changes in the current system of rate setting, there are incomplete incentives
for such consumers to take actions that would be socially cost-effective.
Regulation of All End-Users of Fuel Services
A third level of the market in which emissions allowance trading might be required: all
end-users of energy services. In such a scheme, allowances would be required of consumers as
a function of energy used in a number of daily activities. These could be required (1) at the time
of purchase of the fuel or electricity, or (2) they could be estimated from records of annual
mileage or kWh consumption.
In the first case, the permits requirement could be more precise: annual transportation
usage would not have to be estimated, and in the case of electricity, time of day information
could allow the type of generating equipment being dispatched to be included in the emissions
estimate. However, the actual accounting of permits might be cumbersome on an as-used basis.
Consumers would have to have a continual supply of permits in small denominations, almost
like carrying around a second currency, or a second type of checking account. It is possible that
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1-8 Introduction and Overview
Volume 2: Choosing the Market Level foi Trading
the providers of the energy sources could start buying up allowances themselves, and then sell
them to consumers with the fuel or electricity. This would appear as a surcharge on fuel pump
prices, or on the electricity bill. Consumers might welcome the service of not having to obtain
their own allowances, but also might perceive the system as a large energy tax rather than a
market in which they actively participate.
In the second case, there would be problems of agreeing on a fair basis for estimating
total annual emissions, especially for the use of equipment such as automobiles where the fuel
usage rates can vary dramatically according to personal driving styles, even for a given brand
and model of equipment. Further, waiting until the end of a year before taking an accounting
may be more problematic at the individual citizen level than at the corporate level. Some form
of permits withholding might be necessary throughout the year, with the resulting system being
as cumbersome as a second income tax scheme, replete with forms and filing requirements.
WHAT ARE THE WELFARE DISTRIBUTION IMPACTS FROM TRADING AT
DIFFERENT MARKET LEVELS?
The previous discussion indicated how trading might proceed on different bases
depending on the market level at which it could be implemented. Before moving to a
comparison based on the cost-effectiveness criteria, it is useful to review welfare distributional
considerations that may enter into the debate, at least implicitly. These are considerations of
how the total social welfare would be shared by the market participants, depending on which
market level is required to have allowances for its economic activities. Section 2 then also
provides some information on the distributional impacts across regions of the country.
Total surplus is a term used in economics to describe how well off society is under specific
market conditions. It is used by economists primarily for comparing among market options,
rather than to determine if a specific market outcome is acceptable in some absolute sense. Total
surplus in a market has two components: consumer surplus and producer surplus. These concepts
indicate the benefits captured by producers and consumers from market transactions. They are
always greater than or equal to zero for both sides of the market, or else the market would cease
to exist.
A regulatory action will often reduce the total surplus in the market for a good that is
responsible for some externality, such as pollution. This is accepted as part of the decision to
regulate because surplus is believed to be increased elsewhere in the economy, such as through
enhanced environmental quality, and such increase is judged to outweigh the loss in surplus in
the regulated market. However, regulatory actions can also change the relative shares of total
surplus among economic sectors or regions. That is, the burden of meeting the regulation may
fall more on one party than another. Although these concepts come from the economics
literature, they have nothing to do with the economic optimality of an outcome. Instead,
decisions among these effects can only be decided on the basis of concepts of fairness, which is
inherently a political issue.
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Volume 2: Choosing the Market Level for Trading
Introduction and Overview 1*9
Consumer surplus is defined as the excess that consumers would be willing to pay for
the commodity over that which they have to pay as the market price. Producer surplus is the
excess over costs that producers can earn, given the market price they obtain for their product.
(Producer surplus is synonymous with economic profits.) These are best displayed graphically,
as in Figure 1-1. The market price is the point where the demand and supply curves intersect.
Since the demand curve traces out the marginal willingnesses of consumers to pay, each
consumer's individual marginal surplus is the difference between the market price and that
consumer's position on the demand curve. The total consumer surplus is thus the area labelled
CS. Since the supply curve traces out the marginal costs of producers, each producer's marginal
surplus is the difference between the supply curve and the market price, and total producer
surplus is the area labelled PS.
An Hypothetical Example
To compare the surplus outcomes of different trading schemes, a simple hypothetical
market case is presented. In this, there are only two market levels: the primary producer and
the consumer levels. The primary producers are represented by two oil extraction enterprises.
They sell fuel to a set of six industrial customers, which represent the consumer level of the
market. Hypothetical market information is presented to provide easily verified surplus
calculations, so that the example can concentrate on the comparative nature of market outcomes
under trading of permits instituted at each level of this market.
The two oil extraction enterprises have different costs of production: $10/barrel for
producer X and $100 for producer Y. Clearly producer X would always take the market from
Y, but cannot take the entire oil market because he cannot extract more than 6 barrels of oil per
Price
Supply (Marginal
Production Costs)
Demand
("Willingness to
Pay")
Quantity
Figure 1-1. Illustration of Components of Market Surplus Concept
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Volume 2: Choosing the Market Level for Trading
year. Producer Y can extract much larger amounts of oil. The market supply curve for oil under
these conditions is illustrated in Figure 1-2, labelled S.
Figure 1-2. Hypothetical Market for Oil Products
Demand for oil comes from six different industries, A through F. Other potential demand
for oil comes from industries G, H, and I, but these do not participate in the market because
their willingness to pay for the oil is less than current market prices. Industry A has the highest
willingness to pay, $600/barrel, for the oil, and wants 2 barrels/year at any price under that
value. This very high willingness to pay is because industry A depends on oil very strongly and
has few options for either substituting to other fuel sources or for conserving fuel consumption
in its production process. Other industries have more options, and thus lower willingnesses to
pay, as traced out by the declining demand curve, D.
Given these market assumptions, the market price for oil is $100. Producer X sells as
much as he can at that price, and producer Y produces the remaining 6 barrels/year. The total
surplus in this market of 12 barrels/year is $3540. Only $540 of that is producer surplus (note
that it goes entirely to producer X), and the remaining $3000 is "profit" to the six consuming
industries. This is the initial, pre-regulatory situation against which different trading schemes
are now to be compared. Regulations are suddenly implemented to cut C02 emissions from oil
by 50%. This means that consumption of oil must be cut by 50%, to six barrels/year.
Regulations Implemented at the Primary Producer Level. In the first trading scheme, assume
that the permits are assigned to the primary producer level. Producers X and Y each get 3
permits. If they are not allowed to trade these permits, each will continue to produce at the
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Introduction and Overview 1-11
maximum rate possible. The supply curve shifts to that labelled Si in Figure 1-3(A). Because
there is excess demand at the initial price, prices may rise to as high as $400/barrel, which is the
value above which there is still sufficient willingness to pay for up to the six barrels/year now
permitted. Under these new market conditions, total surplus has declined to $2670, but producer
surplus has actually risen to $2070 and both producers are now making larger profits.
Market
Price
200-
100"
10
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'fe''
jimiss:
—I-
12
Quantity
Market
PricaB400
300*
200-
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•I'll! 4?
.11 .js1- '¦¦¦".;!; =i'ijv'if
S2
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Quantity
Figure 1-3. Market Conditions After Permits Allocated to Primary Producers:
(A) No Permit Trading Is Allowed; (B) Permit Trading Is Allowed
If the two producers are allowed to trade allowances, producer X will have an incentive
to buy out producer Y at any price less than $390 (400-10). Producer Y may be making a profit
of $300/barrel now, but will sell out at any price above $300/permit. Thus the two can be
mutually happier by a trade of permits somewhere in the price range of $300 to $390. If we
assume that they roughly split the difference at a price of $350/barrel, producer X can now sell
at his full capacity, producer Y leaves the market a richer person, and society benefits from lower
costs of meeting the regulation (Figure 1-3(B)). That is, the total surplus increases from $2670
to $2940. This is not as high as the pre-regulation surplus in the oil market, but the rise in total
surplus represents a cheaper regulation for society as a whole than if permit trading were not
allowed. The trading of permits reallocates the burden of emissions reductions so as to minimize
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1-12 Introduction and Overview
Volume 2: Choosing the Market Level for Trading
losses of consumer plus producer surplus. In this example, the increase in surplus goes entirely
to the producers, while consumers take on the costs of the regulatory burden: their surplus falls
from $3000 pre-regulation to $600.
Figure 1-3 illustrates potential distributional impacts of a producer permit system.
However, the reader should be aware that the rise in producer surplus in the example due to
a permit system is the result of the assumed price elasticities of demand and supply. If demand
were more price elastic and supply were less price elastic, price would rise less and costs would
fall less when output is constrained by an emission allowance system. The net result could be
a fall in producer surplus as well as in consumer surplus. Estimates for fossil fuel price
elasticities of demand (Table 1-2) show them to be relatively price inelastic in the short-run, and
mostly borderline elastic in the long run. Elasticities of supply for fossil fuels have been observed
to be relatively more elastic, with substantial increases and declines in reserves following
historical price fluctuations. Thus, our expectation is that a producer permit system for carbon
content of fuels would be likely to raise producer surplus. Over time we would expect the
positive impact on producer surplus to diminish due to the fact that long-run price elasticities
of demand are greater than short-run elasticities.
This example is specific to emissions permits that affect only a single commodity that has
no substitutes that would also compete for the same permits. For instance, the example is
constructed so that only oil is required to have permits. In reality, for C02 controls, coal and
natural gas would also have to have permits, all drawn from the same pool of carbon permits.
These fuels are also substitutes in consumption. If we extend the example to account for carbon
permits, rather than oil permits, then the reduction in consumer surplus for oil may not be as
large as it appears in Figure 1-3(B). Oil producers might buy carbon allowances from coal
producers, which is a more carbon-intensive fuel, and increase oil supply above 6 units. The
price of oil would fall below $400 and consumer surplus would rise above $600 as a result of
extending the allowance trading to all fossil fuels. In turn, coal consumers would suffer a loss
as the market reallocates permits away from coal production, causing coal supply to decrease
further than under the original allocation of allowances and causing the price of coal to rise. The
net effect for total surplus (consumer plus producer) across all energy markets will be positive
as the market reallocates carbon emission allowances among energy resources of different carbon
intensities. Consumers as well as producers would share in the improvement from the position
of Figure 1-3(A). However, when comparing a no regulation case (Figure 1-2), and a carbon
permits market case (Figure 1-3(B)), consumers of fossil fuels, as a group, still would bear more
of the total impact of the regulation than would fossil fuel producers, as a group, when the
permits market is implemented at the producer level of the market.
The reason the hypothetical example where permits can only be traded among oil
producers causes consumers not to benefit from trading of producer permits is because a fixed
quantity of emission allowances also fixes the quantity of oil supplied. When extended to
include all carbon-based fuels, then a fixed supply of emission allowances does not fix the
quantity of any energy type, nor the aggregate quantity of energy services. Consumers also
stand to gain from trading in cases where emissions control technologies exist because, again,
a fixed supply of emission allowances does not fix the quantity of the commodity that can be
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Volume 2: Choosing the Market Level for Trading Introduction and Overview 1-13
supplied. However, this extension of the illustrative example does not apply to a carbon permits
market: reduction of carbon emissions can only be attained by reducing use of fuels.
Table 1-2
SAMPLE OF PRICE ELASTICITIES OF DEMAND FOR FOSSIL FUELS
Short-run Long-run
Industrial, heavy oil [1J N/A -0.30 to -1.17
Industrial, natural gas [1,3] -0.07 to -0.63 -0.12 to -2.53
Industrial, coal [1 ] N/A -1.00 to -1.12
Commercial/Residential, heating oil [1] N/A -1.10 to -1.38
Commercial/Residential, natural gas [1,3] -0.05 to-0.68 -0.39 to-4.60
Commercial/Residential, coal [1] N/A -1.29 to -2.24
Electricity [4] -0.16 to-0.29 -0.17 to-0.63
Transportation, gasoline [1,2] -0.13 to-0.29 -0.60 to-1.77
Transportation, diesel [1] N/A -0.61 to-1.10
(Sources: [1] Al-Sahlawi, M.A., "The Demand for Natural Gas: A Survey of Price and Income Elasticities," The
Energy Journal, Vol. 10, No. 1, January 1989, p. 77-90. (2] Moss, M. F., and J. L. Small, "Deriving Electricity Demand
Elasticities from a Simulation Model," The Energy Model, Vol. 10, No. 3, July 1989, p. 51-76. [3] Jacoby, Henry D.,
and J. L. Paddock, "World Oil Prices and Economic Growth in the 1980s," The Energy Journal, Vol. 4, No. 2, April 1983,
p. 31-47. [4] Dahl, Carol A., "Gasoline Demand Survey," The Energy Journal, Vol. 7, No. 1, January 1986, p. 67-82.
Taking the multi-fuels market extensions into account, we can summarize the general
effects of a market of producer emission allowances for carbon:
¦ Supplies of fossil energy will decrease.
¦ Marginal (e.g., high cost) carbon-intensive fuel producers will leave the
market with the benefit of a large "bribe."3
¦ Prices of fossil energy will rise.
¦ Economic profits in the energy supply industry will rise (given relatively
inelastic demands for fossil energy).
¦ Consumers of energy services will lose.
¦ Overall, there will be a fall in total social welfare related to fossil fuel
markets.
3. This "bribe" is the amount the marginal producer could obtain by selling his permits and leaving the
business. This transfer of wealth would not occur if permits were auctioned rather than allocated to the
existing producers in a market. However, the ability to give out such wealth is an inducement that makes
tradeable permits appear politically advantageous over taxes, which leave no such winners in the regulated
community.
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Volume 2: Choosing the Market Level for Trading
The last point should be qualified to acknowledge that we have focused solely on effects
in the energy sector, and have not attempted to account for environmental benefits associated
with these costs. The losses in social welfare in the energy sector are the costs of obtaining
environmental gains. Whether or not the environmental gains are sufficiently large to justify the
costs of carbon emission reductions is beyond the scope of this study.
Note that our discussion assumes that producers do not pay for the emission allowances
allocated to them. If producers were required to pay for the allowances, producer surplus would
decline correspondingly and be transferred to the authority collecting the payments.
Controls Implemented at the Consumer Level. What happens to the surplus if instead the oil
consumers are required to have permits to buy oil? In this case, assume that each of the six
industries are allocated 1 permit for each unit of carbon emissions, rather than the 2 units that
they are currently producing (assuming that 1 barrel of oil burned produces 1 unit of carbon
emissions). In tills case, the effect is to shift the demand curve rather than the supply curve, as
depicted in Figure 1-4(A). Without trading, all six consumers remain in the market, but the
market is halved. The reduction in oil consumption by half for each oil consumer reduces
consumer surplus from $3000 to $1500. Total surplus is reduced from $3540 to $2040. (Oil
prices may fall if a lower cost set of producers can now meet the full demand. In this example,
the price remains at $100, but this is an anomalous outcome specific to this special case.)4
If trading of emission allowances among primary energy consumers is permitted,
allowances will be sold by consumers who place relatively low value on carbon-based energy
to consumers who place a high value on carbon-based energy. These trades reallocate
allowances so that carbon energy goes to the uses for which it has the highest market value. In
the example, industries A, B, and C would buy allowances from industries D, E, and F.5 As
permits are transferred to industries that are willing to pay the most for oil, the demand curve
shifts out to the right as depicted in Figure 1-4(B). The result is to raise consumer surplus from
$1500 to $2400, substantially reducing the costs to consumers of emission reductions. The total
surplus rises from $2040 to $2940.
In the example provided, producers do not benefit from trading of allowances among
consumers (i.e., in the comparison of Figures 1-4(A) and 1-4(B)) because the trades do not alter
4. The lack of change in price is an artifact of the problem construction, where the oil market is split 50-50
between producers X and Y, and the regulation cuts demand exactly in half. If demand were cut more,
prices for oil could drop, particularly if the example were more realistic, to include more than just two
producers.
5. Industries D, E, and F would not necessarily go out of business, but would likely turn to other sources of
energy services that may be available to them at lower cost than the alternatives for A, B, and C.
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Regional Strategy Implementation Work Plan
Engage in Programmatic Outreach and Communication
•	Beyond supporting program travel to the annual User's conference, Network
governance could develop materials for Regional staff to use in marketing and
advocating the Network customers and programmatic counterparts.
o Leads: NOB/NPRG
•	Conference calls could be scheduled, perhaps 4 per year, with Network governance
and EPA Regional program staff to discuss outreach and communication,
programmatic updates, and future Network focus areas.
o Leads: Maryane Tremaine and Mitch West
Convene Network Partners
• Network governance could gather information on all the relevant meetings convened
by EPA Regional offices and identify opportunities where Exchange Network content
can be "piggybacked."
o Lead: Mitch West with NPRG
Leverage the Unique Role of OEI Lead Region ENLC Delegate
•	Network governance could create training or marketing information about the
Exchange Network to familiarize lead regional coordinators with the Network and
enable them to fulfill their role. The Network User's Guides are an excellent
example of the type of material that could be developed to disseminate Network use
and functionality.
o Lead: NPRG
Continue Supporting Exchange Network Grant Administration and
Leverage the Network for Other EPA Grant Programs
•	EPA Regional staff can consult with the Exchange Network Grant Program and the
Network governance to develop a tool that tracks how an Exchange Network was
used and the resulting product. EPA Grant Program could also require exit
interviews with grant recipients to identify observations, reflections, and challenges
encountered by grantees. Further, Network governance could assemble this
information into a database that could be used to inform future grant proposals and
disseminating ideas more broadly to the Network community.
o Lead: Andy Battin
Establish Regions as Centers of Leadership
•	Network governance and EPA Regional staff will work together to identify,
coordinate, and establish Centers of Leadership.
o Leads: Bill Rice and Maryane Tremaine
•	At the National User's meeting or other relevant conferences, Network governance
can give targeted presentations to the Center of Leadership on tools and resources
that could be implemented to develop solutions. For example, a presentation could
be given on how to adapt the HERE Tool to other regions. The States of Nebraska,
Kansas, Iowa and Missouri could also share their experiences using the Tool.
Draft | Rev. 25 March 2008 \ Page 1

-------
o Lead: Kurt Rakouskas
Coordinate with Tribes and Engage Network Tribal Participation
•	Network governance or EPA Regional Offices could convene a semiannual conference
calls for Regional Tribal Coordinators, Regional staff, and Network governance to
discuss tribal outreach and identify opportunities for Network participation. The
conference calls would also provide an opportunity for Regional Tribal Coordinators
and Regional staff to share what is going on in the ROC meetings and ensure that
the flow of communication between tribes and Network governance is further
enhanced.
o Lead: Mitch West and Robert Holden
Work with Network Governance to Implement the Regional Strategy
•	Network governance should convene data stewards for an annual "State of the
Flow" meeting. Not only will this keep the community of interest informed but it
also representing a prime marketing opportunity for the Network and individual
flows.
o Lead: NOB
•	The Network governance will work in conjunction with the Regions to identify,
recruit, and educate Program staff in each Region and in as many Programs as
possible to be voluntary Network advocates.
o Leads: Bill Rice (ENLC Regional Representative) with ENLC Co-Chairs, and
Mitch West
•	The NOB and Network Coordinator will work with the Regional Network advocates to
develop plans for engaging potential and existing Network customers on how the
Exchange Network might be leveraged to meet programmatic business needs and
priorities.
o Leads: Mitch West, Andy Battin, and Nancie Imler
•	The Network Coordinator and NPRG will continue to track national programmatic
meetings, and will also track significant Regional meetings, like Program Director
Meetings, and identify how to capitalize on those opportunities for outreach.
o Leads: Mitch West, Chris Simmers, Doreen Sterling
•	The ENLC will work with the Network Coordinator in determining how Network
Governance wants to manage its relationships with the EPA Regional staff working
on Network business.
o Lead: Mitch West
•	The Exchange Network Governance support will include preparation of materials that
outline where there are areas of convergence between EPA Grants and potential
uses of the Network.
o Lead: Andy Battin
•	The ENLC will discuss whether to recommend to the EPA that EPA Regions be given
sections in Appendix B of the Grants Guidance to identify projects of Regional
importance, or the ENLC could identify this information and make it available on the
Network website.
o Lead: Mitch West
Draft | Rev. 25 March 2008 \ Page 2

-------
•	The ENLC will work with the Network Coordinator in identifying how best define an
explicit role for the Regions in the Network financial strategy, especially in regards
to grant alignment. The ENLC will also collaborate with Regions in defining this role.
o Leads: Mitch West with ENLC Co-Chairs
•	The ENLC (or via the Network Coordinator) will send an email to EPA Regional Office
Partners encouraging them to attend the Network User's conference.
o Leads: ENLC Co-Chairs
•	The ENLC will identify which sessions at the User's Meeting they would like the data
stewards to run and contact them to do so.
o Lead: Mitch West
•	The ENLC will consider adding Regional Program representatives to the Network
Governance groups.
o Leads: ENLC Co-Chairs
Draft | Rev. 25 March 2008 \ Page 3

-------
Regional Strategy Implementation Work Plan
Engage in Programmatic Outreach and Communication
•	Beyond supporting program travel to the annual User's conference, Network
governance could develop materials for Regional staff to use in marketing and
advocating the Network customers and programmatic counterparts.
o Leads: NOB/NPRG
•	Conference calls could be scheduled, perhaps 4 per year, with Network governance
and EPA Regional program staff to discuss outreach and communication,
programmatic updates, and future Network focus areas.
o Leads: Maryane Tremaine and Mitch West
Convene Network Partners
• Network governance could gather information on all the relevant meetings convened
by EPA Regional offices and identify opportunities where Exchange Network content
can be "piggybacked."
o Lead: Mitch West with NPRG
Leverage the Unique Role of OEI Lead Region ENLC Delegate
• Network governance could create training or marketing information about the
Exchange Network to familiarize lead regional coordinators with the Network and
enable them to fulfill their role. The Network User's Guides are an excellent
example of the type of material that could be developed to disseminate Network use
and functionality.
o Lead: NPRG
Continue Supporting Exchange Network Grant Administration and
Leverage the Network for Other EPA Grant Programs
• EPA Regional staff can consult with the Exchange Network Grant Program and the
Network governance to develop a tool that tracks how an Exchange Network was
used and the resulting product. EPA Grant Program could also require exit
interviews with grant recipients to identify observations, reflections, and challenges
encountered by grantees. Further, Network governance could assemble this
information into a database that could be used to inform future grant proposals and
disseminating ideas more broadly to the Network community,
o Lead: Andy Battin
Establish Regions as Centers of Leadership
•	Network governance and EPA Regional staff will work together to identify,
coordinate, and establish Centers of Leadership.
o Leads: Bill Rice and Maryane Tremaine
•	At the National User's meeting or other relevant conferences, Network governance
can give targeted presentations to the Center of Leadership on tools and resources
that could be implemented to develop solutions. For example, a presentation could
be given on how to adapt the HERE Tool to other regions. The States of Nebraska,
Kansas, Iowa and Missouri could also share their experiences using the Tool.
Draft | Rev. 25 March 2008 \ Page 1

-------
o Lead: Kurt Rakouskas
Coordinate with Tribes and Engage Network Tribal Participation
•	Network governance or EPA Regional Offices could convene a semiannual conference
calls for Regional Tribal Coordinators, Regional staff, and Network governance to
discuss tribal outreach and identify opportunities for Network participation. The
conference calls would also provide an opportunity for Regional Tribal Coordinators
and Regional staff to share what is going on in the ROC meetings and ensure that
the flow of communication between tribes and Network governance is further
enhanced.
o Lead: Mitch West and Robert Holden
Work with Network Governance to Implement the Regional Strategy
•	Network governance should convene data stewards for an annual "State of the
Flow" meeting. Not only will this keep the community of interest informed but it
also representing a prime marketing opportunity for the Network and individual
flows.
o Lead: NOB
•	The Network governance will work in conjunction with the Regions to identify,
recruit, and educate Program staff in each Region and in as many Programs as
possible to be voluntary Network advocates.
o Leads: Bill Rice (ENLC Regional Representative) with ENLC Co-Chairs, and
Mitch West
•	The NOB and Network Coordinator will work with the Regional Network advocates to
develop plans for engaging potential and existing Network customers on how the
Exchange Network might be leveraged to meet programmatic business needs and
priorities.
o Leads: Mitch West, Andy Battin, and Nancie Imler
•	The Network Coordinator and NPRG will continue to track national programmatic
meetings, and will also track significant Regional meetings, like Program Director
Meetings, and identify how to capitalize on those opportunities for outreach.
o Leads: Mitch West, Chris Simmers, Doreen Sterling
•	The ENLC will work with the Network Coordinator in determining how Network
Governance wants to manage its relationships with the EPA Regional staff working
on Network business.
o Lead: Mitch West
•	The Exchange Network Governance support will include preparation of materials that
outline where there are areas of convergence between EPA Grants and potential
uses of the Network.
o Lead: Andy Battin
•	The ENLC will discuss whether to recommend to the EPA that EPA Regions be given
sections in Appendix B of the Grants Guidance to identify projects of Regional
importance, or the ENLC could identify this information and make it available on the
Network website.
o Lead: Mitch West
Draft | Rev. 25 March 2008 \ Page 2

-------
•	The ENLC will work with the Network Coordinator in identifying how best define an
explicit role for the Regions in the Network financial strategy, especially in regards
to grant alignment. The ENLC will also collaborate with Regions in defining this role.
o Leads: Mitch West with ENLC Co-Chairs
•	The ENLC (or via the Network Coordinator) will send an email to EPA Regional Office
Partners encouraging them to attend the Network User's conference.
o Leads: ENLC Co-Chairs
•	The ENLC will identify which sessions at the User's Meeting they would like the data
stewards to run and contact them to do so.
o Lead: Mitch West
•	The ENLC will consider adding Regional Program representatives to the Network
Governance groups.
o Leads: ENLC Co-Chairs
Draft | Rev. 25 March 2008 | Page 3

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C02 TRADING ISSUES
Volume 2:
Choosing the Market Level for Trading
Final Report
Prepared by
Anne E. Smith
Anders R. Gjerde
Lynn I. DeLain
Ray R. Zhang
DECISION FOCUS INCORPORATED
1155 Connecticut Avenue NW
Washington, DC 20036
Prepared for
Adaptation Branch, Climate Change Division
Economic Analysis & Research Branch, Economic Analysis & Innovation Division
Office of Policy, Planning and Evaluation
U.S. Environmental Protection Agency
Washington, DC 20460
Contract No. 68-CO-0021
Project Manager	Chief, Adaptation Branch
Neil A. Leary	Joel D. Scheraga
May 1992

-------
PREFACE
There has been increasing concern within the international community about rising
concentrations of carbon dioxide (C02) and other greenhouse gases in the atmosphere that may
contribute to global climate change. The United States and other nations have been, and will
continue, grappling with the question of whether or not to constrain the emissions of C02.
Should a decision be made to constrain greenhouse emissions, there exists a variety of policy
tools that could be employed to achieve this objective. Discussions of policy tools have recently
focused on approaches that rely upon the creation of market incentives that would induce
sources to reduce their emissions. The advantage of these market incentive approaches is that
they offer the possibility of controlling emissions at much lower costs than are likely to be
achieved through more traditional regulatory approaches.
This three volume report examines one market incentive approach to controlling
emissions of COz: tradeable permits. There are a number of points in the economy at which
a tradeable permit system might be implemented to control C02. For example, permits might
be required for supplying carbon-based energy. Alternatively, carbon permits might be required
of consumers of carbon-based energy. Potential performance of alternative permit market
designs and potential implementation problems are investigated in the report.
Recommendations are made for market designs that promise to be more cost-effective than other
market designs.
Volume 1 of the report examines emissions of C02 from industry, the largest source of
emissions from energy consumption. Volume 2 examines alternative carbon permit market
designs and evaluates the potential performance of the alternatives considered. Volume 3
examines the potential behavior of electric utilities in a carbon permit market and the
implications for the functioning of a permit market.
Designing a cost-effective C02 trading system that can be readily implemented and
enforced is a complex undertaking. This study illuminates these complexities and provides
insights useful to policymakers considering such a system.
Neil A. Leary Joel D. Scheraga
EPA Project Manager Chief, Adaptation Branch
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EXECUTIVE SUMMARY
Tradeable carbon permits and carbon taxes create market incentives for sources to reduce
their emissions of carbon dioxide (C02). The advantage of abatement policies that rely on
market incentives is that they offer the possibility of controlling emissions at much lower costs
than are likely to be achieved through more traditional regulatory approaches. There are,
however, a variety of ways in which tradeable carbon permits or carbon taxes might be
implemented and the choice of implementation can be important to the costs and performance
of the policy. This three volume report examines alternative ways of implementing a tradeable
carbon permit system for controlling emissions of C02.
The focus of the report is limited to the control of COz emissions from fossil energy
production and consumption, which accounts for nearly all US C02 emissions. The quantity of
C02 generated by energy production and consumption is largely a function of the carbon content
of the fossil energy input to economic activity. Because capture and disposal of generated C02
is prohibitively costly, carbon content of fossil energy input also determines the quantity of C02
emissions. Thus a system of carbon permits for fossil energy is equivalent to a system of permits
for emissions of C02 from fossil energy use. This allows a great deal of flexibility for choosing
where in the energy system to implement a permit market for the control of C02. For example,
permits might be required of suppliers for the carbon content of fossil energy supplied to the
market. Alternatively, permits might be required of consumers for the carbon content of the
fossil energy consumed.
Although these alternative permit systems can be designed to achieve equivalent C02
abatement, the costs of the emission reductions and their distribution can vary significantly. This
report examines a number of key issues that will influence the costs of C02 abatement and their
distribution for alternative carbon permit market designs. Volume 1 examines emissions of C02
from industry, the largest source of carbon emissions. Volume 2 examines alternative carbon
permit market designs and evaluates the potential performance of the alternatives considered.
Volume 3 examines the potential behavior of electric utilities in a carbon permit market and the
implications for the functioning of a permit market.
The alternative carbon permit market designs evaluated include both supplier and
consumer permit systems. There are a number of points in the supply chain at which a carbon
permit market might be implemented. Three alternative designs for a supplier permit market
are examined: (i) a market that requires primary energy extractors and importers to obtain
carbon permits, (ii) a market that requires energy processors to obtain carbon permits for the
products that they produce, and (iii) a market that requires energy distributors to obtain carbon
permits for the energy that they sell to final consumers. The consumer carbon permit market
designs examined include (i) a market that would require all carbon energy consumers to obtain
permits, and (ii) a market that would require only major industrial carbon energy consumers to
obtain permits.
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Executive Summary S-3
Of the various points in the supply chain at which permit trading might be implemented,
none emerges as clearly superior. One factor that may influence the cost-effectiveness of COz
control is the potential for leakages of emissions that are unconstrained by a permit market. If
carbon permits are required at the point of distribution, upstream emissions from energy
extraction, refining and processing of energy, and transmission represent potential leakages.
These leakages could narrow the range of options for emission reductions and raise costs. In
contrast, if carbon permits are required at the point of extraction, these emissions would occur
downstream from the permit market and would not represent leakages.
Another factor that may influence the cost of C02 control is whether or not the policy
imposes constraints that have no emission reduction benefits. Energy used as feedstocks does
not contribute to C02 emissions and requiring permits for feedstocks would raise costs without
providing any emission abatement benefits. If carbon permits are required at the point of
extraction, identifying and exempting energy that will ultimately be used as feedstocks may be
administratively difficult and costly, while failure to exempt feedstocks will raise control costs.
Alternatively, if carbon permits are required at the point of distribution to consumers, identifying
and exempting feedstocks may be less costly.
A third factor that may influence the cost of C02 control is the ease of monitoring and
enforcing compliance with permit requirements. Due to vertical integration of firms that supply
energy, monitoring and enforcing compliance may be costly at the levels of extraction and
processing. Because there is little vertical integration beyond the point of distribution of energy
to energy consumers, monitoring and enforcement costs may be lowest for a carbon permit
market at the point of distribution. The net effect of these various factors on the costs of C02
reductions for the alternative permit market designs is ambiguous at this time and warrants
further study.
The recommendations of the report are based on an evaluation of the cost-effectiveness
of alternative permit markets. Another factor that may also guide the selection and design of
a C02 abatement policy is the distribution of the costs of abatement. The report demonstrates
that a carbon permit market for suppliers can yield a very different distribution of costs than
would a carbon permit market for consumers. If permits are required of suppliers, the cost of
emission reductions may be borne more heavily by energy consumers than by suppliers. If,
alternatively, permits are required of consumers, some of these costs may be shifted from energy
consumers to energy suppliers. Of course most energy is consumed as an intermediate input
by firms, and the ultimate distribution of costs among different portions of the population have
not been investigated for this study.
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Volume 2: Choosing the Market Level for Trading
Table of Contents I
TABLE OF CONTENTS
—Volume 2: Choosing the Market Level for Trading—
Section	Page
1	INTRODUCTION AND OVERVIEW
Synopsis of the Issue and Analysis	1-1
What Would Trading Requirements Consist of at the Different
Market Levels?	1-6
Regulation of Industrial Sources of COz	1-7
Regulation of All End-Users of Fuel Services	1-7
What Are the Welfare Distribution Impacts from Trading at Different
Market Levels?	1-8
An Hypothetical Example	1-9
2	HOW MANY SOURCES ARE THERE AND WHERE?
Industry Structure at the Fossil Fuel Primary Production Level	2-1
Number of Sources	2-2
Size and Regional Distribution	2-4
Market Concentration	2-5
Interrelationships Among the Sub-levels	2-7
Downstream Price Signals	2-10
Industry Structure at the Industrial Combustion Level	2-11
Number of Sources	2-11
Size and Regional Distribution	2-12
Market Distortions	2-18
The End-Use Level of the Fossil Fuels Markets	2-19
Numbers of Sources	2-19
Regional Distribution	2-19
Implementing Permit Trading at the End-Use Level:	A Hybrid Approach 2-21
Summary	2-23
3	WHAT AMOUNT OF EMISSIONS WOULD BE SUBJECT TO CONTROL?
Permit Trading at the Primary Production Level	3-1
Permit Trading at the Industry Level	3-5
Permit Trading at the End-Use Level	3-7
Summary	3-8
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II Table of Contents
Volume 2: Choosing the Market Level for Trading
TABLE OF CONTENTS (continued)
Section	Paee
4	WHAT ARE THE MECHANISMS FOR MONITORING AND
ENFORCEMENT?
Number of Sources	4-1
Estimating and Reporting Emissions	4-2
Vertical Integration	4-4
Summary	4-4
5	CONCLUSIONS
Trading at the Primary Producer Level	5-2
Trading at the Industrial Level	5-3
Trading at the End-Use Level	5-3
Controlling End-Uses at the Manufacturer Level	5-4
Recommendations for Further Study	5-4
APPENDIX A: Detailed Industry Data	A-l
APPENDIX B: Top Twenty Producers in Supplier Markets	B-l
APPENDIX C: Car Manufacturers in a Permit Trading Program	C-l
REFERENCES	R-l
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Table of Contents III
LIST OF FIGURES
Fieure	Page
1-1	Illustration of Components of Market Surplus Concept	1-9
1-2	Hypothetical Market for Oil Products	1-10
1-3	Market Conditions After Permits Allocated to Primary
Producers: (A) No Permit Trading Is Allowed; (B)
Permit Trading Is Allowed	1-11
1-4	Market Conditions After Permits Allocated to Consumer
Level: (A) No Permit Trading Is Allowed; (B)
Permit Trading Is Allowed	1-15
2-1	Fossil Fuel Pathways to the End-User	2-2
2-2 Number of Sources at Primary Production Level	2-3
2-3 Major Fossil Fuel Extraction Regions in the U.S.	2-4
2-4 Histogram of Carbon Extracted, by State	2-5
2-5 Key Locations for Electric Units Using Different Fuels	2-13
2-6 Geographical Locations of Major C02 Emitting Industries	2-13
2-7 Histogram of Carbon Emissions from Major Industrial
Sources, by State	2-14
2-8 Comparison of Top 15 States when Ranked (A) by Carbon Extraction
and (B) by Carbon Emissions from Major Industrial Sources	2-17
2-9 Geographical Concentrations of Various Types of Chemical
Industries	2-18
2-10	Histogram of Total End-user Carbon Emissions, by State	2-20
3-1	Considerations in Trading at Primary Production Level	3-2
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Iv Table of Contents
Volume 2: Choosing the Market Level for Trading
LIST OF TABLES
Table

Paee
1-1
Evaluation of C02 Allowance Trading at Different Market Levels
1-4
1-2
Sample of Price Elasticities of Demand for Fossil Fuels
1-13
2-1
Market Concentration at Primary Production Level, 1989
2-6
2-2
Interrelationships Among Fossil Fuel Markets
2-8
2-3
Number of Sources at the Industry Level
2-11
2-4
Source Units at the End-Use Level, 1986
2-20
2-5
Producers of C02 Emitting Devices, 1986
2-21
3-1
U.S. Fossil Fuel Consumption, 1989
3-4
3-2
Total U.S. COz Emissions Estimated from Fuel Production, 1989
3-4
3-3
Emissions Estimates in U.S. Industrial Sector, 1988
3-6
4-1
Options for Estimating Emissions
4-3
5-1
Evaluation of C02 Allowance Trading at Different Market Levels
5-1
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1
INTRODUCTION AND OVERVIEW
The current debate on appropriate methods for controlling emissions of greenhouse gases
frequently refers to the use of tradeable emissions permits. In fact, prominent Congressional
activity, in the form of the Cooper/Synar Bill, would introduce an offsets program for new
sources of CO2.1 Despite the attention that emissions trading generates, relatively little has been
done to investigate the behavior of trading under different implementation options. This three
volume report covers several topics of interest for implementation planning:
Volume 1: Emissions from Industry
Volume 2: Choosing the Market Level for Trading
Volume 3: Effects of Utility Regulation
This volume (Volume 2) looks in some detail at the issue of implementing trading requirements
at different levels of the market. The topic is first defined and described, theoretical aspects are
summarized, and specific market data are presented in an effort to understand better the relative
advantages of the different options posed. Much of the data presented in Volume 1 is also used
in the analysis that follows.
SYNOPSIS OF THE ISSUE AND ANALYSIS
The issue of trading at different levels of the market is one that rarely gains attention in
the theoretical literature. It arises because many goods go through a series of manufacturing
stages before the point of final consumption. Unless these stages are fully integrated vertically,
there is a sequence of markets between the initial product development and the final purchase
by the consumer. Fossil fuels provide a good example of this type of market sequence. The
initial product may be crude oil. This is captured from a well, and may then be sold to a
company that will refine it into final consumer products. There may be additional intermediate
markets, such as companies that buy crude from small wells, and in turn sell their accumulated
crude to refiners. Distributors may purchase refined products from refiners before they reach
the point of sale to the final consumer. Vertical integration is present to some extent in these
markets, but intermediate markets do exist.
1. Offsets are very closely related to emissions allowances (which are used for SOz controls in the 1991 Clean
Air Act Amendments). The main differences between the two concepts are: (1) the supply of offsets is
created by market forces while allowances are created in a fixed quantity by regulators; and (2) offsets tend
to apply only to new sources, while allowances tend to apply to an entire set of sources.
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Volume 2: Choosing the Market Level for Trading
Given that an estimate of the ultimate C02 emissions resulting from a product's use can
be made at each market stage, it would be possible to impose a C02 emissions trading scheme
at any of the market levels. For instance, one might require that each oil well have sufficient
permits to cover the carbon contained in its total sales of crude. Or, one might instead allow
extraction processes to proceed freely, but require that permits be required for each unit of
carbon emitted when the petroleum-based fuel is burned. In the first case, the cost of the
permits will be passed through the market, ultimately affecting consumer demand. In the
second case, the cost of the permits will directly affect demand, which will in turn pass
incentives back to the initial producers. However, a variety of reasons may make one system
more functional than another. This study evaluates C02 permit trading at different market levels
subject to three basic criteria listed below. While we believe that each of these criteria should
be given considerable attention in evaluating policy options, the list is not intended to be
exhaustive. The criteria focused on in the study are:
1. Costs of monitoring and administering a trading program. This will
depend in part on the number of individual companies that make up each
of the market levels, which can vary substantially.
2. Effectiveness. We examine two aspects of market effectiveness: (a) There
may be some "leakage" in markets, meaning that some of the ultimate
emissions might not be accounted for. Similarly, some economic activities
may be penalized at a rate greater than their actual contribution to
emissions. The extent of this type of problem will vary at different levels
of the market, (b) Market power may exist in either the market for the
product, or in the market that will be created for allowances. Such market
power could alter the effectiveness of allowance trading at one market
level but not at others.
3. Distribution. The sharing of control costs (i.e., effects on welfare
distribution) will vary. This will include geographical as well as sectoral
distribution of the regulatory burden. Economic analysis does not itself
indicate what distribution is more desirable, but an understanding of
distributional implications is also an important element for the policy
making process.
In this volume, three generic market levels are considered as options for implementing
C02 trading:
¦ Regulation at the level of the primary producer of fossil fuels.
¦ Regulation of the key industrial points of fossil fuel combustion.
¦ Regulation of all end users of fossil fuel-based energy services.
There are many possible combinations of these three options that should be kept in mind when
devising an implementation plan. However, for purposes of understanding the relative
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Introduction and Overview 1-3
advantages of each, we focus on these three basic underlying options and note obviously
advantageous combinations where appropriate.
Initial analyses using EPA's GEMINI model for assessing national impacts of climate
change policies have indicated that there may well be some distinct differences in outcomes
when trading is implemented at the different market levels. In one example, the model found
that the social benefits of trading to reach stabilization were substantially greater when trading
occurred among producers of raw fossil fuels, compared to when trading occurred among those
who distribute refined fuels to fuel-using customers.2 GEMINI does not currently take account
of all of the issues mentioned above, and the cause of the differences captured by GEMINI
appears to be the leakage issue. GEMINI is also a very aggregate model with no detail on
numbers of firms in a given market or their locations. More investigation is needed of the
nature of these markets to develop an understanding of the best market level to implement
trading, should such regulations be desired. This study takes a first step in the direction of
collating the relevant information for such an assessment. The rest of this volume is organized
to cover the following general questions related to the three evaluation criteria:
¦ What would trading requirements consist of at the different market levels? (next
part of Section 1) This is to provide a clear explanation of what is meant
by this issue, before moving to a more detailed analysis.
¦ What are the welfare distribution impacts from trading at different market levels?
(also in Section 1) Welfare distribution is a theoretical concept used in
economics to investigate the relative gains and burdens under different
market structures. Investigation of this effect is useful for motivating the
point that trading at different market levels can produce situations that
will affect various segments of the population quite differently, even if
results are equivalent in terms of their overall effectiveness in reducing
emissions and cost.
¦ How many sources are there in each market level, how are they distributed by
size, and where are they geographically located? (Section 2) Trading will
involve a larger or smaller number of affected entities at different market
levels. Also, the affected entities may be more or less geographically
concentrated under different market level trading schemes. Potential
market power problems are also important to identify. All of these
concerns are addressed by a better understanding of the number, location
and relative sizes of sources at each market level, and are important in
drawing conclusions regarding costs, effectiveness, and distributive effects.
2. Scheraga, J. D. and N. Leary, Improving the Efficiency of Environmental Policy: The Implementation of Strategies
to Reduce C02 Emissions, Paper Presented to Stanford University's Energy Modeling Forum #12, Boulder
Colorado, August 27-29, 1991, p. 14. Also, "Efficiency of Climate Policy," Nature, Vol. 354, November 21,
1991, p. 193.
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1-4 Introduction and Overview
Volume 2: Choosing the Market Level for Trading
¦	What amount of total emissions would be subject to controls? (Section 3)
Effectiveness of a control program depends on whether a significant
fraction of the emissions are covered by the regulation in question.
Building on the data developed in Section 2, the relative degree of control
at different market levels is discussed, and options for achieving a degree
of control are suggested.
¦	What are the mechanisms for monitoring and enforcement? (Section 4) As
noted above, the ability to effectively enforce a market is also important
in determining the relative desirability of regulating at different market
levels. Enforceability may affect the effectiveness of a program, its overall
costs, and even public perceptions of fairness.
Section 5 provides a summary and conclusion, centered around Table 1-1. The key
conclusion is that the most promising level appears to be the primary producer level. After
defining that sector more fully as a series of sub-levels (extraction, refining/processing, and
distribution), the distribution sub-level, where fuel distributors sell final fuel products to users
of energy services, appears to be the best option, although with qualifications. The other
primary producer sub-levels present less enforceability, greater regional concentrations, and
issues related to treatment of imports and feedstocks. The distribution level, however, would
not account for significant upstream emissions from extraction and refining.
Table 1-1
EVALUATION OF C02 ALLOWANCE TRADING AT DIFFERENT MARKET LEVELS

# Involved
Market
Dysfunction
Potential
Degree of
Geographical
Concentration
Enforce-
ability
Emissions
Coverage
Import
Issues?
Extraction
1,000s
None
High
Moderate
High
Yes
Refining
1,000s
None
High
Moderate
High
Yes
Distribution to Users
1,000s
None
Low
High
High
No
Industries
10,000s
Electric
utility rates
regulations
Moderate
High
Low
No
All End-Users
100,000,000s
None
Low
Low
High
No
Hybrid (Equipment
Manufacturers &
10,000s
Electric
utility rates
Moderate
High
Moderate
Yes
Industry)	regulations
The industry level provides less coverage of emissions than either other level, and is
faced with an important problem area in the case of utility incentives. As Volume 3 of this
report explains in detail, utilities may fail to participate fully in an emissions trading market
except with very careful design of the implementation. Even with such care, the areas of
jurisdiction over utility decisions are so complex that the problem may not be easily
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Volume 2: Choosing the Market Level for Trading
Introduction and Overview 1-5
circumvented. Because utilities would be such a large fraction of any industrially-based C02
emissions market, the potential for disruption is a serious concern.
The end-user level is too cumbersome to administer and enforce for the entire population
of end-users. An hybrid approach that expands an industrial-based system to try to capture
most other end-user emissions is a promising idea, but in our judgment appears have less
potential effectiveness than the fuels distribution level, with no offsetting advantages other than
a possible one of social welfare distribution. The latter issue is described at the end of this
section.
The industry data collected for this study come from standard sources such as the Energy
Information Agency, the Census of Manufacturers, and industry statistical reports. The data
from these sources can be disaggregated geographically only to the state level, making it difficult
to obtain reliable estimates of the size distribution of individual facilities. The only direct
information on size distributions is for companies, which may comprise many individual
facilities in many parts of the country. These caveats should be kept in mind in interpreting
some of the specific numbers presented in this report.
This report considers the case of C02 emissions trading only, rather than all greenhouse
gases. This is in part because manmade C02 emissions come almost entirely from combustion
of fossil fuels. (Cement production is the key exception, as described in Volume 1.) Comparison
of market levels is made more clear when limited to the fossil fuels. Further, many of the other
greenhouse gases are not as clearly tied to specific markets. For example, methane emissions
are largely by-products of a large variety of activities such as agriculture, landfilling, and mining.
In each case, the level of activity (e.g., the number of acres cultivated with rice or the tons of rice
sold) is less important in determining the emissions level than the nature of the activity (e.g., the
method of fertilization, tillage, or irrigation). While CFCs do have very clear markets, they are
of less interest in discussions of trading because they are being phased out of existence. Options
for including all greenhouse gas emissions in a trading scheme could be considered after a
system has been designed to address C02 only. Doing the analysis in this order does not mean
that regulations should be phased in this order.
For this analysis, fossil fuels considered include natural gas, coal, and petroleum-based
fuels (fuel oil, gasoline, etc.). Markets for wood and other biomass fuels are not analyzed
because they pose a question of how significantly they create net emissions, if at all. Similarly,
use of waste methane, such as that captured from landfills or farming, is also not considered
because of complications in determining whether its use adds to emissions, or whether it in fact
reduces total greenhouse forcing. This could happen because (1) the methane that is captured
is itself a powerful if short-lived greenhouse gas, and (2) its use as a new fuel source could
displace more carbon-intensive coal or oil, thus reducing net carbon emissions per energy unit.
Both of these energy sources require further analysis to determine whether they would be
considered fuels that require allowances, or whether use of them would be a basis for the award
of additional allowances.
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reduction would be passed on to the ultimate polluters, this type of implementation could
potentially be perceived as much as an intervention in energy markets as a controlling of
pollution levels. As will be discussed below, there are also distributional effects that could have
implications for this approach, regardless of its cost-effectiveness: producers may gain more
than consumers.
Regulation of Industrial Sources of C02
Tradeable allowances could also be required at the industrial combustion point. In this
case, allowances could be tracked in terms of measured carbon emissions, giving the impression
of a more direct link to the control of pollution. The system would work by allotting, or
requiring purchase of, allowances for each unit of carbon emissions from fossil fuels. Companies
that currently burn fossil fuels would have incentives to switch to low- or no-carbon energy, and
to conserve energy, exactly as in the case of trading at the primary production level. These
reactions would feed back to the fossil fuels market in the form of a shift in output to relatively
more low- and no-carbon energy sources.
Controls on industrial sources of pollution have a strong political heritage. Yet, as
Volume 1 of this report discusses, there are many more important sources of C02 than industry
alone. In particular, transportation is equally as important as electric utilities, or as all other
industry put together. Unfortunately, with millions of vehicles, transportation amounts to an
area source created by the independent decisions of millions of citizens. Unless the options of
individual citizens are also included in the trading scheme, direct control of C02 emissions will
be less effective than their indirect control via requiring allowances per unit of fossil fuel
extracted. Similarly, consumers of electricity (i.e., virtually every household as well as industrial
and commercial users) can affect the effectiveness of emissions control in the electric sector.
However, without changes in the current system of rate setting, there are incomplete incentives
for such consumers to take actions that would be socially cost-effective.
Regulation of All End-Users of Fuel Services
A third level of the market in which emissions allowance trading might be required: all
end-users of energy services. In such a scheme, allowances would be required of consumers as
a function of energy used in a number of daily activities. These could be required (1) at the time
of purchase of the fuel or electricity, or (2) they could be estimated from records of annual
mileage or kWh consumption.
In the first case, the permits requirement could be more precise: annual transportation
usage would not have to be estimated, and in the case of electricity, time of day information
could allow the type of generating equipment being dispatched to be included in the emissions
estimate. However, the actual accounting of permits might be cumbersome on an as-used basis.
Consumers would have to have a continual supply of permits in small denominations, almost
like carrying around a second currency, or a second type of checking account. It is possible that
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Volume 2: Choosing the Market Level for Trading
the providers of the energy sources could start buying up allowances themselves, and then sell
them to consumers with the fuel or electricity. This would appear as a surcharge on fuel pump
prices, or on the electricity bill. Consumers might welcome the service of not having to obtain
their own allowances, but also might perceive the system as a large energy tax rather than a
market in which they actively participate.
In the second case, there would be problems of agreeing on a fair basis for estimating
total annual emissions, especially for the use of equipment such as automobiles where the fuel
usage rates can vary dramatically according to personal driving styles, even for a given brand
and model of equipment. Further, waiting until the end of a year before taking an accounting
may be more problematic at the individual citizen level than at the corporate level. Some form
of permits withholding might be necessary throughout the year, with the resulting system being
as cumbersome as a second income tax scheme, replete with forms and filing requirements.
WHAT ARE THE WELFARE DISTRIBUTION IMPACTS FROM TRADING AT
DIFFERENT MARKET LEVELS?
The previous discussion indicated how trading might proceed on different bases
depending on the market level at which it could be implemented. Before moving to a
comparison based on the cost-effectiveness criteria, it is useful to review welfare distributional
considerations that may enter into the debate, at least implicitly. These are considerations of
how the total social welfare would be shared by the market participants, depending on which
market level is required to have allowances for its economic activities. Section 2 then also
provides some information on the distributional impacts across regions of the country.
Total surplus is a term used in economics to describe how well off society is under specific
market conditions. It is used by economists primarily for comparing among market options,
rather than to determine if a specific market outcome is acceptable in some absolute sense. Total
surplus in a market has two components: consumer surplus and producer surplus. These concepts
indicate the benefits captured by producers and consumers from market transactions. They are
always greater than or equal to zero for both sides of the market, or else the market would cease
to exist.
A regulatory action will often reduce the total surplus in the market for a good that is
responsible for some externality, such as pollution. This is accepted as part of the decision to
regulate because surplus is believed to be increased elsewhere in the economy, such as through
enhanced environmental quality, and such increase is judged to outweigh the loss in surplus in
the regulated market. However, regulatory actions can also change the relative shares of total
surplus among economic sectors or regions. That is, the burden of meeting the regulation may
fall more on one party than another. Although these concepts come from the economics
literature, they have nothing to do with the economic optimality of an outcome. Instead,
decisions among these effects can only be decided on the basis of concepts of fairness, which is
inherently a political issue.
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Consumer surplus is defined as the excess that consumers would be willing to pay for
the commodity over that which they have to pay as the market price. Producer surplus is the
excess over costs that producers can earn, given the market price they obtain for their product.
(Producer surplus is synonymous with economic profits.) These are best displayed graphically,
as in Figure 1-1. The market price is the point where the demand and supply curves intersect.
Since the demand curve traces out the marginal willingnesses of consumers to pay, each
consumer's individual marginal surplus is the difference between the market price and that
consumer's position on the demand curve. The total consumer surplus is thus the area labelled
CS. Since the supply curve traces out the marginal costs of producers, each producer's marginal
surplus is the difference between the supply curve and the market price, and total producer
surplus is the area labelled PS.
An Hypothetical Example
To compare the surplus outcomes of different trading schemes, a simple hypothetical
market case is presented. In this, there are only two market levels: the primary producer and
the consumer levels. The primary producers are represented by two oil extraction enterprises.
They sell fuel to a set of six industrial customers, which represent the consumer level of the
market. Hypothetical market information is presented to provide easily verified surplus
calculations, so that the example can concentrate on the comparative nature of market outcomes
under trading of permits instituted at each level of this market.
The two oil extraction enterprises have different costs of production: $lO/barrel for
producer X and $100 for producer Y. Clearly producer X would always take the market from
Y, but cannot take the entire oil market because he cannot extract more than 6 barrels of oil per
Price
Supply (Marginal
Production Costs)
Demand
("Willingness to
Pay")
Quantity
Figure 1-1. Illustration of Components of Market Surplus Concept
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maximum rate possible. The supply curve shifts to that labelled Si in Figure 1-3(A). Because
there is excess demand at the initial price, prices may rise to as high as $400/barrel, which is the
value above which there is still sufficient willingness to pay for up to the six barrels/year now
permitted. Under these new market conditions, total surplus has declined to $2670, but producer
surplus has actually risen to $2070 and both producers are now making larger profits.
Figure 1-3. Market Conditions After Permits Allocated to Primary Producers:
(A) No Permit Trading Is Allowed; (B) Permit Trading Is Allowed
If the two producers are allowed to trade allowances, producer X will have an incentive
to buy out producer Y at any price less than $390 (400-10). Producer Y may be making a profit
of $300/barrel now, but will sell out at any price above $300/permit. Thus the two can be
mutually happier by a trade of permits somewhere in the price range of $300 to $390. If we
assume that they roughly split the difference at a price of $350/barrel, producer X can now sell
at his full capacity, producer Y leaves the market a richer person, and society benefits from lower
costs of meeting the regulation (Figure 1-3(B)). That is, the total surplus increases from $2670
to $2940. This is not as high as the pre-regulation surplus in the oil market, but the rise in total
surplus represents a cheaper regulation for society as a whole than if permit trading were not
allowed. The trading of permits reallocates the burden of emissions reductions so as to minimize
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Volume 2: Choosing the Market Level for Trading Introduction and Overview 1-13
supplied. However, this extension of the illustrative example does not apply to a carbon permits
market: reduction of carbon emissions can only be attained by reducing use of fuels.
Table 1-2
SAMPLE OF PRICE ELASTICITIES OF DEMAND FOR FOSSIL FUELS
Short-run Long-run
Industrial, heavy oil [1] N/A -0.30 to -1.17
Industrial, natural gas [1,31 -0.07 to -0.63 -0.12 to -2.53
Industrial, coal [1] N/A -1.00 to -1.12
Commercial/Residential, heating oil [1] N/A -1.10 to-1.38
Commercial/Residential, natural gas [1,3] -0.05 to -0.68 -0.39 to -4.60
Commercial/Residential, coal [1] N/A -1.29 to-2.24
Electricity [4] -0.16 to -0.29 -0.17 to -0.63
Transportation, gasoline [1,2] -0.13 to-0.29 -0.60 to-1.77
Transportation, diese! [1] N/A -0.61 to-1.10
(Sources: [1] Al-Sahlawi, M.A., "The Demand for Natural Gas: A Survey of Price and Income Elasticities," The
Energy Journal, Vol. 10, No. 1, January 1989, p. 77-90. [2] Moss, M. F., and J. L. Small, "Deriving Electricity Demand
Elasticities from a Simulation Model," The Energy Model, Vol. 10, No. 3, July 1989, p. 51-76. [3] Jacoby, Henry D.,
and J. L. Paddock, "World Oil Prices and Economic Growth in the 1980s," The Energy Journal, Vol. 4, No. 2, April 1983,
p. 31-47. [4] Dahl, Carol A., "Gasoline Demand Survey," The Energy Journal, Vol. 7, No. 1, January 1986, p. 67-82.
Taking the multi-fuels market extensions into account, we can summarize the general
effects of a market of producer emission allowances for carbon:
¦ Supplies of fossil energy will decrease.
¦ Marginal (e.g., high cost) carbon-intensive fuel producers will leave the
market with the benefit of a large "bribe."3
¦ Prices of fossil energy will rise.
¦ Economic profits in the energy supply industry will rise (given relatively
inelastic demands for fossil energy).
¦ Consumers of energy services will lose.
¦ Overall, there will be a fall in total social welfare related to fossil fuel
markets.
3. This "bribe" is the amount the marginal producer could obtain by selling his permits and leaving the
business. This transfer of wealth would not occur if permits were auctioned rather than allocated to the
existing producers in a market. However, the ability to give out such wealth is an inducement that makes
tradeable permits appear politically advantageous over taxes, which leave no such winners in the regulated
community.
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1-14 Introduction and Overview
Volume 2: Choosing the Market Level for Trading
The last point should be qualified to acknowledge that we have focused solely on effects
in the energy sector, and have not attempted to account for environmental benefits associated
with these costs. The losses in social welfare in the energy sector are the costs of obtaining
environmental gains. Whether or not the environmental gains are sufficiently large to justify the
costs of carbon emission reductions is beyond the scope of this study.
Note that our discussion assumes that producers do not pay for the emission allowances
allocated to them. If producers were required to pay for the allowances, producer surplus would
decline correspondingly and be transferred to the authority collecting the payments.
Controls Implemented at the Consumer Level. What happens to the surplus if instead the oil
consumers are required to have permits to buy oil? In this case, assume that each of the six
industries are allocated 1 permit for each unit of carbon emissions, rather than the 2 units that
they are currently producing (assuming that 1 barrel of oil burned produces 1 unit of carbon
emissions). In this case, the effect is to shift the demand curve rather than the supply curve, as
depicted in Figure 1-4(A). Without trading, all six consumers remain in the market, but the
market is halved. The reduction in oil consumption by half for each oil consumer reduces
consumer surplus from $3000 to $1500. Total surplus is reduced from $3540 to $2040. (Oil
prices may fall if a lower cost set of producers can now meet the full demand. In this example,
the price remains at $100, but this is an anomalous outcome specific to this special case.)4
If trading of emission allowances among primary energy consumers is permitted,
allowances will be sold by consumers who place relatively low value on carbon-based energy
to consumers who place a high value on carbon-based energy. These trades reallocate
allowances so that carbon energy goes to the uses for which it has the highest market value. In
the example, industries A, B, and C would buy allowances from industries D, E, and F.5 As
permits are transferred to industries that are willing to pay the most for oil, the demand curve
shifts out to the right as depicted in Figure 1-4(B). The result is to raise consumer surplus from
$1500 to $2400, substantially reducing the costs to consumers of emission reductions. The total
surplus rises from $2040 to $2940.
In the example provided, producers do not benefit from trading of allowances among
consumers (i.e., in the comparison of Figures 1-4(A) and 1-4(B)) because the trades do not alter
4. The lack of change in price is an artifact of the problem construction, where the oil market is split 50-50
between producers X and Y, and the regulation cuts demand exactly in half. If demand were cut more,
prices for oil could drop, particularly if the example were more realistic, to include more than just two
producers.
5. Industries D, E, and F would not necessarily go out of business, but would likely turn to other sources of
energy services that may be available to them at lower cost than the alternatives for A, B, and C.
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Introduction and Overview 1-15
the price of oil nor the quantity of oil traded in the market.6 This is because a fixed quantity
of emission allowances for consumers also fixes the quantity of oil demanded in the example.
Just as in the case of producer permits, if a carbon permit system for consumers includes all
carbon-based fuels and not just oil, then a fixed quantity of carbon emission allowances does not
fix the quantity of energy demanded for any fuel type, nor does it fix the aggregate quantity of
energy demanded. In the example, oil consumers might buy allowances from coal consumers
and increase the quantity of oil demanded beyond 6 units. The price of oil received by suppliers
would rise above $100 and producer surplus of oil suppliers would rise as a result of allowance
trading among consumers. The net effect on producer surplus is ambiguous for the general case.
Market
Price
Market
Price
10
12
14
Quantity
—»—
12
—r— Quantity
14
Figure 1-4. Market Conditions After Permits Allocated to Consumer Level:
(A) No Permit Trading Is Allowed; (B) Permit Trading Is Allowed
6. This is a different point from the special-case result discussed in Footnote 4, that the producers in the
example suffer no loss when a regulation is implemented putting constraints on consumers. That unusual
result is because of the simplistic supply function assumed in the example. Under more general assumptions
for the supply of oil, a reduction in the demand for oil would reduce producer surplus as well as consumer
surplus.
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1-16 Introduction and Overview
Volume 2: Choosing the Market Level for Trading
In the case of a producer permit system we saw that producers could benefit from a
policy that restricts the supply of oil. Symmetrically, consumers could benefit from a consumer
permit system that restricts the quantity of oil demanded. Although consumer surplus is
decreased in the example presented, an emission permit system for consumers could increase
consumer surplus under specific elasticity conditions. An emission permit market for consumers
reduces the price and quantity of energy. The reduced quantity reduces consumer surplus
because consumers consume less energy. The reduced price raises consumer surplus because
consumers pay less for what they do consume. Whether the net change in consumer surplus
from these two opposing effects is positive or negative will depend upon the price elasticities
of demand and supply. The more elastic is demand, and the less elastic is supply, the more
likely is it that consumer surplus will increase. However, because energy demand appears to
be relatively price inelastic, and aggregate energy supply appears to be relatively price elastic,
we expect that a carbon emission allowance system for fossil fuel consumers would decrease
consumer surplus and producer surplus relative to a case of no regulation (i.e, when comparing
Figures 1-2 and 1-4(B)).
In summary, the effects of an emission allowance trading system implemented at the
consumer level of the market are:
¦ Demand for primary energy will decrease in aggregate and demand will
shift away from carbon-intensive energy to low- or no-carbon energy.
¦ Marginal carbon-intensive fossil fuel producers will leave the industry
without large personal gains.
¦ Prices of fossil energy will fall.
¦ Economic profits in the energy supply industry will fall.
¦ It is ambiguous whether consumers of energy are likely to lose or win.
¦ Total social welfare will fall in the fossil fuels market (as before,
presumably offset by social welfare gains from environmental
improvements).
In well-functioning markets, trading of emission permits will yield identical results in
terms of the quantities of each energy type produced and consumed, the allocation of production
among producers, and the allocation of consumption among consumers, regardless of whether
the trading is implemented at the producer or consumer level. Both systems achieve emission
reductions at the same total cost. This can be seen in the above examples by noting that for both
allowance trading systems, total surplus is reduced $590, from $3540 to $2950. In the example,
this is the lowest possible cost for a 50% reduction of emissions.
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Introduction and Overview 1-17
Although the total cost of emission reductions is the same for the two systems, the
burden may be distributed very differently between producers and consumers. In a producer
allowance system, consumer surplus unambiguously decreases, while producer surplus is likely
to increase due to a transfer from consumers. In our example, a permit market for oil producers
reduces consumer surplus from $3000 to $600 and raises producer surplus from $540 to $2340.
In comparison, a permit market for oil consumers that yields an identical reduction in oil
consumption and carbon emissions reduces consumer surplus from $3000 to $2400. Producer
surplus is unchanged. The costs of emission reductions paid by consumers in our examples are
much lower in a consumer permit market than in a producer permit market. Producers fare
better, and even benefit, in a producer permit market. More generally, in a producer allowance
system, producer surplus unambiguously decreases, while consumer surplus may increase or
decrease. Even if consumer surplus decreases, the fact that prices fall makes them
unambiguously better off with trading at the consumer level than with trading at the producer
level.
We have demonstrated that there is a clear difference in which parties bear the burden
of a regulation depending on the market level at which it is implemented. However, it is
important to recognize that the specific conclusions about which parties are better off come from
assuming the permits are allocated at no cost to market participants according to their historical
market activities. While this is a plausible scenario, results can be quite different if other ways
of distributing permits are applied. By auctioning allowances or charging fees for allowances,
it would be possible to alter the distribution of the burden of reducing emissions under a chosen
allowance market structure. If one allowance system was thought to yield an undesirable
distribution of costs, payments for the allowances could be used to improve upon the allocation
of costs. In any case, the analysis of consumer and producer surplus changes makes it clear that
alternative systems for allowance trading can yield very different distributions of costs. The
distribution of costs will be an important criterion by which competing COz policy options will
be judged by the various constituencies that will influence climate policy.
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How Many Sources Are There and Where? 2-3
On the other hand, there are only about 200 refineries,11 owned by the 2,000 companies
mentioned above, and 3,600 coal blending /cleaning facilities (roughly one per coal mine) in the
U.S. However, implementing permit trading at this level would require special consideration
for natural gas, since this energy type usually is transferred directly to a distributor or the final
user without further processing. For gas, permit trading could be implemented at the
transportation level to reduce the number of source units. There are 133 gas pipeline companies
in the U.S.12
Figure 2-2. Number of Sources at Primary Production Level
Because there is a high degree of vertical integration in the oil, gas, and coal industries
(discussed separately below), it would be possible to impose a permit trading market at any
primary production sub-level outlined in Figure 2-1, and treat oil and coal companies as
"bubbles", i.e., multi-source units where only total production by company would face the
scrutiny of the regulators. This would probably be more workable than requiring permits at
each point of extraction.
11.	U.S. Department of Commerce, Bureau of the Census, 1987 Census of Manufacturers. Industry Series,
Washington, D.C., 1989, Table 2.
12.	Oil & Gas lournal Special. Pipeline Economics, Tulsa, Oklahoma, November 27, 1989, p. 64-66.
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2-4 How Many Sources Are There and Where?
Volume 2: Choosing the Market Level for Trading
Size and Regional Distribution
Fossil fuels are produced in regional production centers around the country. Figure 2-3
provides an overview of major production regions in the U.S. Appendix A provides a detailed
breakdown of oil, gas, and coal production by state, with extraction volumes reported in physical
units; barrels of oil, cubic feet of natural gas, and short tons of coal. By converting these units
to energy equivalents (i.e., Btu), we are able to compare total U.S. energy extraction across the
three sectors. While coal production accounts for about 40% of total U.S. fossil energy extraction,
coal mines account for only about 0.5% of the extraction sources. Oil and gas each account for
approximately 30% of energy extraction, and about 69% and 30% of total source units,
respectively. Thus, an average coal mine produces about 200 times more energy than an oil well,
and about 100 times more than a gas well.
Figure 2-3. Major Fossil Fuel Extraction Regions in the U.S.
These data also can be combined into a measure of total carbon extracted in each state
by weighting each fossil fuel unit by its carbon content. The result provides a regional
distribution on the sources of carbon at the primary producer level. Figure 2-4 illustrates this
distribution in a histogram. Note how skewed the distribution is, with the majority of emissions
in a few states, and over half of the states being accountable for negligible amounts of the
carbon. Over 50 percent of the carbon comes from only four states (Texas, Wyoming, Louisiana,
and Kentucky). Not surprisingly, the key carbon extraction states correspond to the major fossil
fuel extraction regions of Figure 2-3: the Gulf states, Ohio River Valley states, and North Central
states. If a trading scheme were instituted at the primary producer level, transfers of wealth
among producers would be concentrated in these regions.
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How Many Sources Are There and Where? 2-5
US Carbon Emissions Based on State ol Extraction
250
200
150
o
S
c
o
State
Figure 2-4. Histogram of Carbon Extracted, by State
Market Concentration
Market concentration is an important factor in determining the possibilities for market
power within an industry or a market. However, a permit trading market will typically cut
across different industries/markets, and this will reduce the risk of any one participant gaining
significant market power. For example, if a refinery wanted to gain market power in a C02
permit market, it would face not only other refineries but also all coal and gas producers.
Table 2-1 provides information about concentration of output markets for different
sub-levels of oil production, gas production, and coal production. Market concentration is
typically measured by large producers' market share. The ten largest producers cover between
33% and 60% of their output markets. In no instance does the market share of the largest firm
exceed 11% of its output market. In comparison with concentration ratios for the major
carbon-emitting industries (see Volume 1), the concentration of energy producers in their
individual markets is moderate. The ten largest producers are, on the average, between three
and five times the size of the next ten producers. A list of the top 20 producers is provided in
Appendix B.
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HOW MANY SOURCES ARE THERE AND WHERE?
Comparing some of the cost-effectiveness and distributional consequences of different
implementations of a permit trading market requires knowledge about the major emitters, and
the structure of the markets in which they will interact. Administration and monitoring depend
on the numbers of agents that might be regulated at each level. Total emissions from each
market level are important for the effectiveness criterion. The potential for market power to
arise in the permits market is also relevant to an assessment of effectiveness. The overall
structure and interrelationships in output markets may affect the feasibility of instituting and
monitoring a permits market at specific levels of the economy.
In this section we summarize the market locations and other features, addressing each
of the three market levels under consideration separately. The facts presented do not enable us
to make rigorous predictions about the workings of a dynamic permit trading market. However,
they provide a good basis for identifying problem areas and key relationships in designing a
COz trading scheme, and will serve well as a starting point for more structured modeling of
market behavior.
INDUSTRY STRUCTURE AT THE FOSSIL FUEL PRIMARY PRODUCTION
LEVEL
Extraction (oil and gas wells and coal mines) is most commonly thought of as the primary
production of fossil fuels. However, fossil fuels typically proceed through a number of
transportation, storage, and processing links in order to get to the final consumer. For example,
once crude oil has been extracted from the well, it is transported to the refinery through
pipelines, or by tanker, barge, or truck. Sometimes a different company performs the transport
than performs the extraction. In the refinery, the oil is processed into multiple products.
Marketers sometimes buy the refined products and sell them to distributors or large single
customers.7 Natural gas, on the other hand, is typically transported directly from the well via
pipeline to distributors or large consumers, without intermediate processing. Coal can either go
through a blending/cleaning process at the extraction site, or it can be shipped in its extracted
form to the final consumer. Either way, modes of transportation for coal include rail, conveyer,
barge, truck, or ship.
7. This latter step of distribution is not formally part of primary production, and is sometimes called a secondary
energy market.
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2-2 How Many Sources Are There and Where?
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Figure 2-1 illustrates the different transition points for oil, natural gas, and coal. While
the wellhead or minehead may be the immediate concept of where the "primary production
level" is, there are in fact several sub-levels before the products reach industrial and other
consumers. It would be possible to implement permit trading at any of these sub-levels. It may
be desirable to keep such options in mind, in addition to the standard "point of extraction"
concept, as the number and location of market agents ("sources") varies dramatically at different
sub-levels.
OIL
^, Crude Oil
^ Retining^^
/ x f Refined Products
GAS
Well ^ ^ Well ^
^ 1 Crude Oil ^, Gas
^Transport^ ^Transport^
Gas
Distribution
5
COAL
Coal
Transport
Coal
Coal
Primary
Production
Level

Refined Products \

Gas

Coal
>
r 1
>
f
\\ >
f
Consumer
0
Consumer
D
Consumer
Industry/
End-Use
Level
Figure 2-1. Fossil Fuel Pathways to the End-User
Number of Sources
Figure 2-2 shows the number of sources at different sub-levels of the primary production
sector for oil, natural gas, and coal. Permit trading at the extraction level would imply more
than 863,000 source units, with oil and gas wells accounting for more than 99% of these units.
There are only about 3,600 coal mines in the U.S.8 Although there are very many individual
source units for oil, most are owned by large integrated oil and gas companies. There are
approximately 2,000 oil companies9 and 3,600 coal companies10 in the U.S.
8. American Petroleum Institute, Basic Petroleum Data Book. Petroleum Industry Statistics, Vol. XI, No. 1,
Washington, D.C., 1991; and Energy Information Administration, Coal Production 1989, DOE/EIA-0118(89),
Washington, D.C., 1989, Table 28.
9. U.S. Department of Commerce, Bureau of the Census, Statistical Abstract of the United States 1988, Washington,
D.C., 1988, Table 1153.
10. Energy Information Administration, Coal Production 1989, Table 28.
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Table 2-1
MARKET CONCENTRATION AT PRIMARY PRODUCTION LEVEL, 1989

Market share
of largest company
Market share
of 10 largest
Market share
of 20 largest
Oil extraction
9%
50%
60%
Oil refineries *
11%
58%
78%
Gasoline marketers **
8%
60%
75%
Gas producers
5%
33%
44%
Gas pipeline companies
11%
45%
69%
Coal producers
11%
44%
55%
* Measured as capacity for crude oil input.
1973 data
(Sources: American Petroleum Institute (1991), Tables IV:7c, Vlll:11c, and Xlll:12b; E. J. Mitchell
(1976), Table 7; Energy Information Administration (DOE/EIA-0130(91/03), Table FE2; Oil and Gas
Journal Special (November 27, 1989), p.66; and EIA Coal Production 1989, Table 28.)
Because an allowance market for carbon content of primary energy would include coal,
oil, and gas producers as a single group, concentration in the allowance market would be less
than in the individual fuel markets. The ten largest extractors of fossil carbon account for 34%
of total carbon extracted in the U.S. The twenty largest account for 46% of domestic carbon
extracted.13 The ten largest domestic extractors of carbon include two coal companies, seven
companies that extract oil and natural gas, and one that extracts only oil. The largest source is
a coal company, which accounts for 4% of domestic carbon extraction.
The above figures for concentration of an allowance market at the primary producer
corporate level are based on quantities of energy extracted in 1989, and the concentration will
change once allowance trading occurs. If the emission reduction target is aggressive, requiring
significant reduction in the production of fossil fuels, it is possible that the allowance market,
and energy markets, will become more concentrated.
The analysis suggests that a carbon allowance market for primary energy producers and
importers would not be heavily concentrated and that market power would not be a severe
problem. However, it is possible that the larger producers would have some degree of market
power that could lead to some losses of efficiency in an allowance market.
If permit trading was implemented at the energy extraction level, we would also be
interested in the size distribution of wells and mines. Information on this distribution was not
directly available. To obtain an estimate, we divided the total production in each state by the
13. It is unclear whether the carbon market concentration would increase or decrease if imports could be
included in these estimates.
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number of wells or mines in that state. (Details are provided in Appendix A.) Although this
gives only a crude estimate of the average size, some interesting patterns emerged for
comparisons across fuel types and across geographical regions. Long established extraction
areas, such as oil and gas extraction in the Gulf and Appalachian regions, have more wells than
relatively new production areas, such as Alaska. In the Appalachian region, production units
are generally small, but elsewhere oil and gas wells vary widely in typical size.14
Interrelationships Among the Sub-levels
If a specific sub-level is selected for implementing trading at the primary producer level,
a full evaluation of its effectiveness will require understanding the degree of economic
interrelationships among the agents in each sub-level. For example, if the sub-levels are fully
integrated vertically, then there should be little difference in regulatory outcomes, regardless of
which sub-level were regulated. If vertical integration is high, regulators may be able to take
advantage of this by designing regulations at the most easily monitored sub-level. Complex and
strongly tied interrelationships among sub-levels may provide insights about an emissions
market from a couple of perspectives:
¦ They are likely to affect a company's motivation to switch fuels; the more
integrated, the more the commitment to a given fuel type within the
industry.
¦ They might make monitoring of a permit trading market more difficult.
An integrated oil/coal company may not publicly report internal product
flows, making some levels of the market less easily implemented if they
include companies of differing degrees of integration.
Following is a discussion about market relationships in the oil, gas, and coal sectors,
structured around the fossil fuel pathways illustrated in Figure 2-1. A summary is provided in
Table 2-2, from which one can see that a substantial amount of ties exist, but the sub-levels are
not fully integrated.
Oil and Gas. Most oil and gas production is carried out by conglomerate oil companies. Crude
oil is generally transported directly from wells to refineries. Approximately 60% of the oil
flowing through refineries has been transported through pipelines, 38% has been transported
14. The greatest size variability is noted in the Gulf region. This may in part be explained by the region's
substantial offshore production. Due to the large capital investments connected to offshore drilling, offshore
wells tend to be much larger than onshore wells: offshore oil wells account for only 5% of total oil wells in
the Gulf region, but they produce approximately 25% of the region's oil; offshore gas wells are about 18%
of total gas wells, and 40% of production. This means that offshore wells in the region are about 6 and 3
times the magnitude of the average onshore oil and gas well, respectively. This information is derived from
American Petroleum Institute's Basic Petroleum Data Book (1991).
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2-8 How Many Sources Are There and Where?
Volume 2: Choosing the Market Level for Trading
by barge or tanker (most of which is imported crude oil), and 2% by truck.15 Oil companies
own about one-third of private tanker capacity. Pipelines are owned directly by large oil
companies, or by joint ventures of oil companies.
Table 2-2
INTERRELATIONSHIPS AMONG FOSSIL FUEL MARKETS
Holding Company
Activity
Degree of Involvement
OH Company
Drilling
Base Activity

Pipeline Transportation
Substantial

Tanker Transportation
Some

Refining
Substantial

Marketing
Substantial

Distribution
Substantial

Chemicals Industry
Substantial
Gas Company
Drilling
Base Activity

Transport
Substantial

Distribution
Some
Coal Company
Mining
Base Activity

Transport
Some

Cleaning/Blending
Substantial

Distribution
Substantial

Electric Utilities
Some

Steel Industry
Some
The top 20 refining companies in the U.S. have 78% of total U.S. refining capacity,16 and
have about 50% of the total U.S. plant units (over 90 plants).17 Of the top 20 refining
companies, 13 (with more than 90% of the top-20 production) are integrated oil companies with
crude oil extraction in the U.S. Three leading companies are foreign oil companies without
substantial drilling in the U.S.18
15. U.S. Department of Commerce, Bureau of the Census, op. cit., Table 1166,1986 data.
16. American Petroleum Institute, op. cit., Section VIII, Table 11c.
17. Oil & Gas Journal, Annual Refining Report, Tulsa, Oklahoma, March 18,1991, p. 59.
18. American Petroleum Institute, op. cit., Section VIII, Table 11c.
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Marketing of refined petroleum products is carried out by marketers ("jobbers") who
purchase refined oil products and supply retail dealers. Marketers can be independent of
refiners and retailers, but are often affiliated with one or both of them. Of the top 20 marketers,
at least 19 were extensions of large refineries (99% of top-25 capacity) in the 1970s.19
Most large oil companies are also suppliers of natural gas, and several are substantial
participants in the coal industry.20 Most natural gas is sold at the wellhead to large natural
gas pipeline companies. Pipelines require large capital investments, and there are substantial
economies of scale to their operation. The pipeline companies are mostly joint ventures between
producers and/or marketers, and some are owned by single large oil companies. From them,
the gas is sold directly to gas distribution companies or large end-users. The top 20 pipeline
companies had about 70% of the market in 1988.21
Most large oil companies also are heavily involved in various chemical industries through
domestic and foreign subsidiaries.22 However, there appears to be little integration between
oil companies and electric utilities.
Coal. The 20 largest coal producers have diverse backgrounds. In addition to pure "coal
companies," their ranks include companies that are chiefly known for their interest in other
industries.23 For example, most steel companies are substantial coal producers. In 1972 the
sixth and seventh largest coal producers were owned by steel companies (approximately 6% of
total U.S. production). Several oil companies are also substantial coal producers. In 1970, four
of the top twenty coal producing companies were oil companies (approximately 19% of total U.S.
production). Two of these four oil companies were among the top twenty oil producers in
1972 24
Some electric utilities are also heavily involved in coal mining. However, states differ
markedly in their attitudes toward vertical integration in the utility industry. Integrated
companies east of the Mississippi are limited to production of coal for their own use, whereas
some western companies have become active in supplying coal to other utilities. For coal-fired
electric units as a whole, however, only between 4.5 and 7% of the coal stems from captive coal
19. Mitchell, Edward J., Vertical Integration in the OQ Industry, American Enterprise Institute, Washington, D.C.,
1976, pp. 47,50.
20. Ibid., p. 58.
21. Energy Information Administration, Natural Gas Monthly, op. cit., Table FE2; and Oil & Gas lournal Special.
Pipeline Economics, Tulsa, Oklahoma, November 27,1989, p. 66.
22. PennWell Publishing Company, 1991 U.S.A. Oil Industry Directory, Tulsa, Oklahoma, 1991.
23. Mitchell, Edward J., op. cit., p. 57.
24. Gordon, Richard L., U.S. Coal and the Electric Power Industry, Resources for the Future, Washington, D.C.,
1975.
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mines.25 "Partial" integration is also an option for some utilities, where the utility owns the
coal lands but extraction activities are performed by operating companies, or joint operations that
lease the lands.
Approximately two-thirds of total coal supply to electric utilities is based on long-term
contracts (ten years or more). The tendency to enter long term commitments is more
pronounced for large utilities than for small. Much of the difference between small and large
utilities with respect to contracting seems to be attributable to the availability of oil. Companies
that might want to shift from coal to oil would not want their options foreclosed by contracts.
The difference in contract use between large and small utilities may be a result of the fact that
the largest utilities typically are older, and consequently have less flexibility for change in fuel
type.26
Downstream Price Signals
Through refining processes, oil is converted into multiple fuel products with somewhat
different carbon contents. As a result, the decision to implement permit trading prior to the
refining process could have some distorting effects on consumer behavior downstream. Permit
trading at the wellhead level could imply that price signals would be transferred downstream
without consideration of these effects. That is, the change in fuel prices would not necessarily
reflect each fuel type's carbon content.
For example, if permit trading was implemented at the wellhead level, an oil well would
be likely to incorporate the price of permits acquired into the price of crude oil. The refineries
would purchase the crude oil at a higher price, and would in turn incorporate the higher crude
oil prices in the price of refined products. This could be done in a number of ways, such as:
(a) the price increase could be allocated evenly to all products, (b) the refinery could increase the
price only for less price sensitive products, or (c) the price increase could be allocated to reflect
the carbon content of each product. The latter case is the least likely from a behavioral point of
view, but the most desirable from the regulatory perspective.
Estimates of the differences in carbon content of various refined petroleum products
indicate that the overall potential for such distortions may be minor (on the order of several
percentage points of difference in carbon contents). However, a substantial portion of crude oil
(about 28%) is destined for use as an industrial feedstock rather than for direct combustion.
Since feedstocks do not always immediately contribute to carbon emissions, there might be
reasons to exempt them from permits requirements to avoid potential downstream distortions
of incentives. These considerations are added reasons to consider the point of permit trading
better placed at or after the point of refining.
25. Gordon, Richard L., op. cit., Table 3.2.
26. Gordon, Richard L., op. cit., p. 57-59.
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INDUSTRY STRUCTURE AT THE INDUSTRIAL COMBUSTION LEVEL
A second scheme for instituting tradeable permits would be to require permits at the
point of emissions, as is typical of other environmental regulations. For the most part, this
would be equivalent to trading at the point of fuel combustion. It can be contrasted to options
for trading at the primary producer level on a number of grounds. Parallel to the discussion
about primary producers, we now consider the structure of the fuel-using industries that would
be affected.
Number of Sources
Volume 1 of this report identifies the major C02 emitting industries in the U.S. and
estimates their emissions. The top three are chemicals, paper, and steel, although much of the
paper industry emissions appears to be the result of wood burning. Cement is a more distant
fourth, largely because of process-related production of C02 rather than burning of fossil fuels.
Petroleum refining is fifth, although its combustion-related emissions are higher than those of
cement. These five industries account for about 70% of C02 emissions in the non-utility part of
the industry sector. Utility emissions alone, however, are more than twice as large as all other
industry emissions combined. For this section, we assume that these six major emitting
industries would be the target of a trading scheme at the industrial level. Table 2-3 shows the
total number of plant units in each of these industries. We do not have information on the
number of companies that own these units.
Comparing permit trading at the primary production level and the industry level, we find
that depending on how we define source units at the primary production level, the number of
units can be below or above the number of source units at the industry level. By defining a unit
as well/mine, the number of primary production sources would be in the order of 860,000 units.
If the source unit is defined as oil company, refinery, or transporter, the number of sources at
Table 2-3
NUMBER OF SOURCES AT THE INDUSTRY LEVEL
Industry
Number of plants
Electric utilities (SIC 491)
Chemicals (SIC 28)
Paper (SIC 261 - 263)
Steel (SIC 3312)
Cement (SIC 3241)
Petroleum refining (SIC 2911)
Total
6,500
8,500
500
300
200
200
16,200
(Sources: For utilities: Energy Information Administration, Inventory of Power
Plants in the United States 1989, DOE/EIA-0095(89), Washington, D.C., 1989,
Table 14; For all others: U.S. Department of Commerce, Bureau of the Census,
1987 Census of Manufacturers. Industry Series, Washington, D.C., 1989.)
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the primary production level will probably be less than 10,000, closer to that of the industrial
level.
Size and Regional Distribution
In examining size and regional distribution at the industrial fuel combustion level, we
try to answer questions such as: Are industries generally located near fuel extraction sources,
or are they located near markets, i.e., near population centers? What "drives" industry location?
This information can provide insights about geographical transfer of wealth under different
permit trading schemes. Observations in this section are primarily based on detailed data
presented in Appendix A.
Figures 2-5 and 2-6 show regional location centers for utilities and other major C02
emitting industries, respectively. To derive Figure 2-5, the states were ranked according to their
production of electricity (in GWh) with coal, oil, and gas, respectively. The top states for each
fuel were then noted accordingly. (We used judgment to determine how many states belonged
in the top categories for each fuel, by identifying the first clear gap in the ranking.) Coal-fired
utilities account for substantially more electricity production than oil and gas-fired utilities, and
also appear less geographically concentrated. This is reflected in Figure 2-5 by the larger
representation of coal-fired generation. The geographical pattern that emerges is heavy coal use
in the Appalachian and Western regions, which do have large coal deposits (see source regions
illustrated in Figure 2-3). Gas is used most intensively in the South and Southwest. This is not
necessarily closely tied to gas source regions. Oil is mostly used in the Northeast, again not
closely tied to source regions. These patterns are consistent with the greater transportability of
oil and, provided pipelines are present, gas.
Figure 2-6 indicates the top ten producing states in each industry, by value of shipments.
Here it is clear that the Northeast, out to the Great Lakes Region, is highly industrialized, relying
heavily on local coal as an energy source. The South and West in turn have a large volume of
refined petroleum and chemicals production, consistent with the location of major extraction
regions for petroleum.
State by state estimates of carbon emissions from the major industries listed in Table 2-3
can be estimated using the same data. This regional distribution of emissions is presented in
Figure 2-7, which can be compared to Figure 2-4. From the figure, it appears that industrial
carbon emissions are much more broadly distributed among states than is carbon extraction.
Now ten states account for 50 percent of the carbon emissions, compared to four states in the
case of carbon extraction. Thus, the welfare impacts of allowance trading on industrial
consumers of energy would be less geographically concentrated than the impacts on producers
of energy. However, there is still a reasonable amount of emissions concentrated in a few states,
and these states tend to coincide with the top carbon extraction states. Figure 2-8 compares the
top fifteen states for carbon extraction with those for major industrial emissions, using the
information in the histograms of Figures 2-4 and 2-7.
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Figure 2-6. Geographical Locations of Major C02 Emitting Industries
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Stately-State Carbon Emissions from Major OS. Industries'
80 -r
70 •
60
50 -
40
Stale
* Major industries include electricity, chemicals, steel, paper, refining, and cement, and account for 90% of total US.
industrial emissions.
Figure 2-7. Histogram of Carbon Emissions from Major Industrial Sources, by State
Electric Utilities. It is hardly surprising that electricity generation generally takes place around
population centers (the correlation coefficient between state populations and state generation in
GWh is 0.44). However, if this is broken down by fuel types, we find that the pattern is more
pronounced for oil and gas-fired generation than for coal-fired generation (correlation coefficients
of 0.23, 0.40, and 0.15, respectively). Oil-fired units are not necessarily found in large oil
producing states (the correlation coefficient between state GWh and state oil production in
barrels is 0.01). Exceptions to this trend are Florida, Pennsylvania, and California, for which
both oil production and oil-fired electricity generation are high. For gas-fired units we found
a strong correlation (0.61) between gas extraction and gas-fired electricity generation; gas-fired
units tend to be located near gas extraction areas. Coal-fired units are often located near coal
mines (correlation coefficient of 0.25).
Based on these observations we may carve out the following picture to describe the
electric utility industry:
¦ Coal-fired utilities are located around coal production areas. The
observation that coal-fired utilities are located outside densely populated
areas can have two explanations: transportation costs are high, or there
are environmental/legislative disincentives to such siting.27
27. Gordon, Richard L., op. cit.
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Figure 2-8. Comparison of Top Fifteen States when Ranked
(A) by Carbon Extraction and (B) by Carbon Emissions from Major Industrial Sources
¦ For gas-fired utilities, the picture seems somewhat more complex. Gas-
fired electricity and gas extraction seem to go hand in hand, and at the
same time, gas-fired generation seems to take place near population
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centers. This may suggest that where gas extraction takes place around
highly populated areas, it is a preferred source of power.
¦ Oil-fired utilities have little correlation to oil production centers, possibly
because oil is highly transportable.28
Petroleum Refining. Petroleum refineries burn considerable amounts of oil and gas. Not
surprisingly, refineries are often located close to oil and gas production centers in the South and
in California (correlation coefficient of 0.57). Two exceptions to this tendency are Alaska and
Washington. Alaska has a large oil production but a small refining production, whereas
Washington has a small oil production and a relatively large refining production. Much of the
oil processed in refineries in Washington comes from Alaska.
Paper Industry. Like petroleum refining, the sources of fuel and raw materials are similar. The
single most important energy source for the paper industry is wood chips. As such, the paper
industry is also concentrated where raw materials—and wood chips—are abundant.29 The key
paper processing areas are in the South, Northeast, and Northwest.
Cement. Cement plants are generally located close to raw materials, and if inland, close to their
markets. However, imports have increased steadily in recent years to 18.5% of total
consumption in 1988. Imports are primarily from Mexico, Canada, Japan, and Spain. In the
future, imports from Mexico and other developing countries are expected to increase.30
Steel. The steel industry consumes large amounts of coal, and several steel mills are owners of
coal mines. However, there is little evidence that the location of steel mills is triggered by the
location of coal mines (correlation coefficient of 0.04). More important natural resource related
factors determining the location of steel mills are likely to be proximity to iron ore and water,
both of which are available in the South and Northeast. (Other important determinants are
economic, such as the location of steel consumers and availability of scrap input.)
Chemicals Industry. The chemicals industry is very diverse, with multiple product groups,
different fuel burning intensity, and different use of feedstocks. To accommodate this we
divided the industry into five sub-categories; organic chemicals, inorganic chemicals, plastic
28. Mitchell, Edward J., op. cit., p. 43.
29. U.S. Department of Energy, Industry Profiles/Paper, Final Report Prepared by Energetics, Inc., Washington,
D.C., December 1990, p. 1.
30. U.S. Department of Energy, Industry Profiles/Cement, op. cit., p. 3.
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materials and resins, nitrogenous fertilizers, and other chemicals. Figure 2-9 displays the
regional distribution of each of these sub-groups of the chemicals industry.
Figure 2-9. Geographical Concentrations of Various Types of Chemical Industries
¦	Inorganic Chemicals. This industry uses relatively more natural gas than
other fuel types, but plant location does not appear to be triggered by gas
production (correlation coefficient of 0.05). This again is consistent with
the mobility of natural gas.
¦	Plastic Materials and Resins. This is a natural gas and LPG-intensive
industry, which also uses a significant amount of oil as feedstock (about
9% of direct fossil fuel consumption). In general, plants seem to be
located close to oil and gas production centers (correlation coefficients of
0.46 and 0.60, respectively).
¦	Organic Chemicals. This is also a natural gas and LPG-intensive industry,
which uses considerable amounts of oil as feedstock (about 22% of direct
fossil fuel consumption). There seems to be a good correlation between
plant location and large oil/gas production centers (correlation coefficients
of 0.48 and 0.77, respectively).
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¦ Nitrogenous Fertilizers. This is a natural gas intensive industry, which also
seems to be located around gas production centers (correlation coefficient
of 0.53).
¦ Other Chemicals. These diverse production activities use relatively more
natural gas than other fuel types, but there does not appear to be a
relationship between gas production and plant locations (correlation
coefficient of 0.04).
Market Distortions
A carbon emissions allowance market, like carbon taxes, has the potential to reduce the
costs of emission reductions substantially below the costs that would be incurred by a command-
and-control emissions policy. The degree to which an allowance market can reduce costs,
however, can be lessened by market imperfections and barriers to market exchanges. Extensive
rates regulation of electric utilities may create inefficiencies in an allowance market that includes
utilities. This is a serious concern since utilities would be such a major factor in a market for
carbon at the industrial level, accounting for about two-thirds of U.S. industrial carbon emissions
and over one-third of total U.S. C02 emissions.
Regulations of the allowed rates of return of utilities can distort utilities' costs of capital
investments for emission controls away from the true social costs of these investments.
Regulations that require capital gains and losses to be passed on in whole or in part to utility
customers can distort utilities' costs of purchases and sales of emission allowances if the
regulations are applied to allowances. These distortions alter the relative costs of emission
controls and allowance purchases that are perceived by electric utilities. Because of this, the
combination of investment in emission control and purchases of allowances that individual
utilities will choose may not be the efficient choices. The result will be an allocation of emission
reductions across sources that will fail to achieve reductions at least cost.
Since utilities represent a large portion of C02 emissions, the regulatory distortions
discussed above could cause significant efficiency losses for an emissions allowance market that
includes utilities. However, it should be kept in mind that market imperfections caused by
electric utility regulation would also influence the efficiency of other market-based approaches
to emissions control. For example, a carbon tax also would rely on energy users to respond
efficiently to energy prices, and may face similar implementation problems in the utility sector.
Volume 3 of this report, "Effects of Utility Regulation," discusses electric utility regulation
and emission allowance trading in more detail. Included in the discussion are suggestions for
the treatment of emission control investments and allowance purchases and sales in utility
regulation to reduce efficiency losses in an emission allowance markets.
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THE END-USE LEVEL OF THE FOSSIL FUELS MARKETS
While discussion about permit trading at the combustion level most often focuses on the
utility industry and other major emitters in the industrial sector of the economy, it is important
to keep in mind that large quantities of fossil fuels also are burned in other sectors; more
specifically the transportation sector, the residential sector, and the commercial sector. Together,
these sectors account for about 40% of U.S. C02 emissions (see Volume 1). Could permit trading
be implemented at the combustion level for these sectors, as well? Following a brief outline of
the structure of these sectors, we discuss how permit trading could be implemented so as to
include these sectors.
Number ol Sources
The transportation sector consists of private and commercial road vehicles (cars, trucks,
motorbikes, etc.), aviation, rail transportation, and shipping. Table 2-4 provides rough estimates
of the number of source units for cars and trucks, merchant vessels under the U.S. flag, and U.S.
commercial airplanes. There is also a large number of additional sources, such as military
aircraft, leisure vessels, and motorbikes.
The residential sector covers residential houses and buildings. Table 2-4 estimates owner-
occupied houses in the U.S. at 55 million. In addition, approximately 35 million households live
in rented houses and apartments. There is also a large number of second homes, vacant homes
etc. Approximately 55% of occupied housing units are gas heated, 20% oil or LPG heated, 5%
wood heated, and 0.4% coal heated.31 Gas is also used for cooking in about 38% of housing
units. Electricity, of course, is ubiquitous and accounts for about 19% of home heating.
The commercial sector accounts for commercial and public office buildings. Table 2-4 also
provides information about such buildings in the U.S.
Regional Distribution
When all of the sources of emissions are added together, one might expect a more
widespread regional distribution of emissions. However, locations of populations are largely
correlated with industrial centers. Figure 2-10 provides a histogram of total state by state
emissions, including all industrial, commercial, residential, and transportation sources.32 By
comparing Figure 2-10 with Figure 2-7, the regional emissions concentration appears equivalent
to that based on location of key industrial emitters. Although high population states tend to
have high total emissions, there is substantial variation in the state averages for emissions per
31. U.S. Department of Commerce, Bureau of the Census, op. cit.. Table 1225.
32. The data for the total state-level emissions used here come from The Heat Is On: America's C02 Polluters,
Citizens Fund, Washington, D.C., December, 1990, p. 37.
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capita, and the ranking of the states is altered. For example, California ranks second for total
emissions but is 45th in terms of per capita emissions among the states. Of the top fifteen states
in Figure 2-10, only West Virginia and Louisiana have per capita emissions that are significantly
different from the average. The top ranked states on a per capita emissions basis are Wyoming
(by far the highest at 66,600 lbs./person of carbon), North Dakota (38,700 lbs. C/person), West
Virginia (34,500 lbs. C/person), Alaska (31,500 lbs. C/person), and Louisiana (25,200 lbs.
C/person). The average for all states is 11,800 lbs. C/person.
Table 2-4
SOURCE UNITS AT THE END-USE LEVEL, 1986
Category	Number of Sources
Cars and Trucks	177 million
Commercial Airplanes	215,000
Merchant Vessels	738
Owner-occupied Homes	55 million
Rented Houses/Apartments	35 million
Commercial Buildings	4 million
* 1,000 gross tons and over. Not inclusive of "U.S." vessels under foreign flag.
(Source: U.S. Department of Commerce, 1987 Census of Manufactures, Tables
992, 1028, 1044, 1221,1237.)
Figure 2-10. Histogram of Total End-user Carbon Emissions, by State
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Implementing Permit Trading at the End-Use Level: An Hybrid Approach
Any attempt to directly include the transportation, residential, and commercial sectors
in a permit trading program, using cars and buildings as source units, could easily lead to
administrative overload. An alternative way to include these sectors in a permit trading
program would be to focus on producers of C02 emitting equipment; for example car producers,
manufacturers of oil and gas-fired heaters for residential and commercial buildings, etc. This
would effectively result in an extension of the concept of trading at the industrial level rather
than at the consumer level. Instead of confining the industrial groups to those that burn fossil
fuels, any industry that produces goods that later burn fuels in the hands of a user would also
become responsible for emissions of their products in the hands of their customers.
Table 2-5 provides information about the number of U.S. plants for car producers, aircraft
manufacturers, ship-builders, and producers of heating devices. The list is not intended to give
a complete picture of all the sources that would need attention, but merely indicate that the
number of source units now would be reduced to a more practical level.
Table 2-5
PRODUCERS OF C02 EMITTING DEVICES, 1986
Industry
SIC Code
Number of Plants
Motor Vehicles and Equipment
371
3,867
Aircraft Products and Parts
372
1,471
Ship Building and Repair
373
2,566
Heating and Plumbing Manufacturers
343
1,177
(Source: U.S. Department of Commerce, 1987 Census of Manufactures, Table 1242.)
The way such controls would work would be that each piece of equipment sold would
have an emissions rating. (This is probably easily obtained from current rating requirements
such as fuel economy on cars.) The average lifetime and usage patterns of the equipment and
change in emissions rating over its lifecycle would have to be estimated. With these data, a total
lifecycle C02 emissions estimate could be derived, and the equipment manufacturer would be
required to have sufficient permits to cover all equipment sold.33 However, each company
would have a very complicated trading problem, since every line of car or type of equipment
would require its own lifecycle emissions estimate. Appendix C demonstrates how emissions
estimates for the car manufacturing industry, as well as car manufacturers can be derived.
33. This type of regulatory approach would not be unlike the use of CAFE standards where vehicle
manufacturers are allowed to average their fleet fuel economy ratings. The key difference is that the
performance of the fuel economy would have to be demonstrated over ten or more years of vehicle usage,
rather than at time of sale.
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Clearly the manufacturer cannot completely control lifecycle emissions because this is
ultimately in the hands of the user. The user would still have no incentive to adjust the lifetime
of a piece of equipment, nor to use it less frequently, nor to maintain it in its most efficient state.
All of these actions can be very important cost-effective ways of reducing emissions over
equipment lifecycles. Manufacturers might develop maintenance programs or early retirement
programs as a way of obtaining a lower requirement for allowances, but this type of permitting
system would still primarily affect incentives to improve lifecycle performance in terms of
technical design. The technology focus of this approach would probably also fail to provide
sufficient incentives for end-users to turn to cost-effective alternatives with lower emissions. For
example, more efficient and more costly furnace technology would provide little incentive to
invest in home insulation. Only an approach focused on actual emissions, either through
consumer behavior or consumer fuel usage, can completely address lifecycle emissions
incentives. Another caveat to this approach is that it would only apply to new equipment. Old
and less efficient units would not automatically be affected. In fact, a disincentive to replacing
the existing stock could be created.
An interesting feature appears with this hybrid approach that deserves further
consideration. In regulating the actual points of combustion, there is no question of "leakage"
of responsibility for emissions. However, whenever the regulations affect a party that is up or
downstream of the point of emissions, one must face questions of how to regulate non-U.S.
entities (the importers of goods). By transferring responsibility for controlling emissions from
the vehicle owner to the vehicle manufacturer, one is transferring the responsibility onto multiple
foreign companies.
Clearly the regulations must face importers as well as domestic producers. Otherwise
production abroad would become more competitive and imports might increase. Such
international transfers of production could reduce the effectiveness of unilateral regulation. On
the other hand, if imports were to be included in the permits requirements, permits would have
to be allocated to foreign producers. As is frequently noted in the theoretical literature on
trading, free allocation of tradeable permits amounts to an allocation of wealth. The concept of
giving permits to foreign companies may therefore meet considerable resistance politically.
However, even allowing foreign interests to purchase such permits has implications for the
transfer of U.S. capital assets abroad, and may create serious political concerns. Imports instead
could be required to meet specific technology standards, but this works against the concept of
free trade. It could even be in violation of trade agreements. More needs to be. considered
regarding treatment of imported goods that create emissions when used after purchase.
Other hybrid approaches are also possible. For example, industrial source permits could
be combined with permits for distributors of fuels to the transportation and household sectors.
This approach would close the leakage gap without requiring estimation of lifecycle emissions.
On the other hand, it is somewhat less integral than the former approach: distributors would
be regulated, but only for a part of their activities. If this hybrid approach were advantageous,
then it would probably be even more advantageous to institute the entire permits market at the
distribution level.
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SUMMARY
A carbon emission allowance market for producers of energy would include
approximately 6,000 companies as participants in the market. These 6,000 companies own and
operate nearly 900,000 extraction facilities such as oil wells, gas wells, and coal mines. They also
own and operate about 200 domestic oil refineries, 3,600 coal processing plants, and 130 gas
pipeline companies.
The extraction facilities are geographically concentrated in the Gulf states, Ohio River
Valley states, and North Central states. The six states that extract the greatest quantities of fossil
energy carbon are Texas, Wyoming, Louisiana, Kentucky, West Virginia, and Alaska. Together
they extract 63% of domestic fossil energy carbon. Only four states account for over half of all
U.S. carbon extraction.
Given relatively inelastic demands for fossil energy, an allowance market for producers
is likely to transfer surplus from consumers to producers. This transfer may be concentrated in
the regions where fossil energy production is concentrated. The six states which account for 63%
of carbon extraction could capture large gains. Note, however, that if ownership of these energy
resources is not concentrated in the production regions, the transfer will be more dispersed than
suggested by the geographical concentration of production.
Within the regions that do benefit, the gains may be distributed very unevenly. For
example, any policy that significantly reduces carbon emissions will likely require reductions in
coal production. Owners of coal resources will benefit from a rise in the price of coal, but with
the reduction in coal production comes a reduction in coal industry employment. There will also
be reductions in payments for other factors used in the production of coal which may have
negative impacts on coal regions.
A market for carbon allowances for energy production may not be a perfectly competitive
market in the sense that it will not be composed of very large numbers of very small buyers and
sellers. If a producer permit market for carbon is implemented at the level of energy extraction,
the ten and twenty largest participants will represent roughly 35% and 45% of the market, which
is not a particularly high degree of concentration relative to other industries. The implication
is that, although some market participants may possess some degree of market power, it is not
expected that this will be a serious problem for efficiency of an allowance market at the producer
level.
An emission allowance market for industrial consumers of energy would include 10,000
to 20,000 participants. Industrial sources, defined here to include electric utilities, emit roughly
60% of total U.S. C02 emissions. The six industrial sectors with the largest C02 emissions
account for approximately 90% of industrial emissions and 55% of total emissions. The largest
emitting industries are electric utilities, chemicals, paper, steel, cement, and petroleum refining.
Although industrial emissions are heavily concentrated in these six industrial sectors, the
six sectors include nearly 17,000 industrial plants. Concentration ratios in each industry are
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similar to those in the primary energy sector, but these would be greatly reduced when
aggregated into an emissions-based concentration ratio. Although we do not have emissions
data by plant to compute that ratio, it is likely that an allowance market for industrial sources
would be much less concentrated than an allowance market for energy producers. Thus we
would not expect market concentration and market power to be a problem in this market.
Industrial emissions of COz are somewhat concentrated geographically, but less so than
is the extraction of carbon. Up to ten states are required to account for half of U.S. emissions.
Three states stand out with the greatest industrial emissions of C02: Texas, Ohio, and
Pennsylvania.
The regional concentration of industrial emissions should not be interpreted to mean that
the social welfare losses of emission reductions will fall disproportionately upon the states where
emissions are concentrated. An emission allowance system, whether it be for energy producers
or consumers, will raise the industrial costs of producing goods. Industrial consumers of energy
will suffer losses and highly C02 intensive industries may reduce employment. But a large
portion of the costs of emission reductions will be passed on to the final consumers of the goods
produced by industry. These consumers are widely distributed across the U.S. and in foreign
markets. The geographic distribution of ownership of industrial sources is also likely to differ
from the geographic distribution of industrial plants.
Electric utilities represent a large share of industrial C02 emissions. Due to the structure
of electricity markets and regulations of electric utilities, the incentives faced by utilities in an
emission allowance market will be distorted. This may cause utilities to choose a sub-optimal
mix of investment in emission control and purchases of allowances that would lessen the
efficiency of the allowance market. Although this distortion should be addressed for any
market-based emissions control scheme, it is even more salient for trading at the industrial end
user level of the market.
A policy focusing on industrial emissions alone neglects large emissions from residential,
commercial, and transportation end uses. Omitting these end uses from an emission reduction
policy could significantly raise the costs of achieving an emission target, but extending an
emission allowance market to include them directly would be prohibitively costly. One
alternative is to estimate lifecycle emissions for energy-using equipment in the residential,
commercial, and transportation sectors and to require equipment manufacturers to obtain
allowances for the equipment that they sell. This option is also likely to be administratively
costly and fails to provide end users with incentives to reduce emissions by operating their
equipment efficiently. Other alternatives would be to require distributors of energy to these
sectors to obtain permits for the energy sold, or to combine an industrial emission allowance
market with carbon taxes for fuels distributed to other end users. These options create
administrative burdens and a relatively complex regulatory structure. However, some such
hybrid approach is probably advisable if a carbon emissions market is to be implemented other
than at the energy producer level of the market.
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3
WHAT AMOUNT OF EMISSIONS WOULD BE
SUBJECT TO CONTROL?
In this section we discuss how permit trading at different levels of the economy would
affect how much of total emissions would be subject to control, and for what possible control
options would incentives to take action be lost.
PERMIT TRADING AT THE PRIMARY PRODUCTION LEVEL
As discussed in Section 2, C02 permit trading at the primary producer level would target
fossil fuel production close to the source of extraction (see Figure 2-1) rather than at the point
of emissions. Possible sources of "leakage" that may arise in controlling emissions when the
responsibility is shifted upstream to primary producers are summarized as "considerations" in
Figure 3-1, and discussed below.
Imports of Fossil Fuels. Crude oil imports accounted for approximately 32% of U.S. oil
consumption in 1986.34 By contrast, imports of natural gas and coal accounted for only
4.5%35 and 0.2%,36 respectively. The discussion of imports and exports of fossil fuels
assumes that foreign countries with which we trade energy do not implement their own policies
raising the prices of traded energy to reflect the carbon content of the energy. If the contrary
were true, care would be needed in the treatment of imports and exports in a carbon permit
market to ensure that traded energy is constrained neither more nor less than energy that is not
traded in international markets. Equating the treatment of the two may be a very complex task,
particularly if other countries do not adopt market incentive approaches to reducing carbon
emissions.
If permits are required only at the wellhead, a leakage problem would occur. Importers
could be required to obtain a number of permits equal to the carbon imported, thereby solving
this leakage problem, but also bringing foreign interests into the permits market. To some
extent, this leakage problem also could be circumvented by instead implementing permit trading
34. U.S. Department of Commerce, Bureau of the Census, Statistical Abstract of the United States 1988, Washington,
D.C., 1988, Table 1166.
35. Ibid., Table 1173.
36. Ibid., Table 1175.
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at the refinery level. Each refinery would be required to have permits independent of where the
oil came from. Domestic production and imports of crude oil would therefore compete on the
same terms as without trading.
Imports of refined petroleum products, however, are also significant. They accounted for
approximately 14% of U.S. consumption in 1986.37 Unless this is also accounted for under a
permit trading program, foreign producers would be likely to gain a competitive advantage over
U.S. refineries; imports would go up, thereby neutralizing the environmental gain. One could,
in fact, also have instances where the net environmental effect would be negative; for example
if foreign refineries with less fuel efficient production were able to increase their U.S. market
share.
Primary Focus Considerations
Figure 3-1. Considerations In Trading at Primary Production Level
If none of the importer-trading options are acceptable, it would be wise to implement
trading at some point in the system that distributes refined petroleum products. This would
increase the number of parties involved to several thousand rather than the several hundred
refineries. Probably this is wise, if only to also avoid market power problems that could arise
in the case of only a few hundred parties (many of which belong to the same oil company
anyway).
Export of Unrefined or Refined Fuels. Fuel exports account for approximately 1.8% of crude
oil production, 5% of domestic refined products,38 approximately 0.4% of natural gas
37. Ibid., Table 1166.
38. Ibid., Table 1166.
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production,39 and approximately 10% of coal production.40 There is the question as to
whether or not fuel exports should be subject to control. One could argue that the U.S.
unilaterally should set an example to the world, but setting an example would have its costs in
terms of lost foreign revenue. On the other hand, as the carbon trading in the U.S. reduces
domestic demand for coal, coal exports might increase beyond the current 10%, partially
offsetting any reductions in emissions inside the U.S. Thus, this source of emissions leakage
should be carefully addressed if implementing trading at the primary producer level.
Feedstocks. Feedstocks accounted for approximately 28% of petroleum product consumption
in the U.S. industrial sector in 1988.41 A feedstock is a part of the fossil fuel production that
is used as an ingredient in a production process, but is not part of fuel combustion. For
example, plastics are made from petroleum products. Thus no C02 emissions arise directly from
use of feedstocks. Based on this, one could argue that feedstocks should be subject to a "permit
refund," or should otherwise be exempted from the calculation of required permits. This would
be easy to implement if trading were to occur at a level of the market after refining, such as at
the final distribution to consumers. A bigger accounting problem arises for trading prior to the
refined product distribution. In this case, it would be quite difficult to determine which units
of fuel products will ultimately go to feedstocks, or even what fraction of a refiner's output goes
to feedstocks. It would be virtually impossible to account for at the wellhead. Again, we find
an argument for defining primary producers as the final distributors rather than the extractors
or the refiners.
Input/Output Issues. In addition to determining at what level of the economy permit trading
should take place, one must also decide whether emissions estimates should be input or output-
based. For example, if emissions trading were implemented at the fuel extraction level,
emissions estimates could be based on fuel extraction volumes, or alternatively, volume sold.
While fuel extraction volumes could account for losses in the extraction process, measuring fuel
volume sold (or shipped out) would probably be easier in terms of monitoring and control. This
may be a fairly small error that is considered not a serious issue compared to others. For
example, it has been estimated that approximately 1.8% of natural gas produced in the U.S. is
either lost in transmission, or vented and flared.42 However, if trading occurs after the refining
stage, all of the emissions associated with refining might not be captured by the regulation,
unless careful consideration is given to this in the regulatory design. As has been shown, the
refining emissions are likely the fifth highest industrial source of C02 emissions.
39. Ibid., Table 1173.
40. Ibid., Table 1175.
41. See Volume 1 of this report, Table A-l.
42. American Petroleum Institute, Basic Petroleum Data Book. Petroleum Industry Statistics, Vol. XI, No. 1,
Washington, D.C., 1991, Section XIII, Table 5a.
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Table 3-1 provides estimates of fossil fuel consumption that would be covered under a
permit trading program at the primary producer level. We have included some of the caveats
discussed above; accounting for imports and exports (assuming exports are outside the permit
trading market), including all production units, subtracting feedstocks, and adding wood
burning.
Table 3-1
U.S. FOSSIL FUEL CONSUMPTION, 1989
(trillion Btu *)

Oil
Gas
Coal
Wood
Total
U.S. extraction"
15,285
18,045
24,721
1,236
59,197
Imports,unref."*
8,255
750
50

9,055
Imports, refi.*"
3,916

3,916
Exports,unref."*
-308
-60
-2,167

-2,535
Exports,refin.***
-1,243

-1,243
Feedstocks ""
-6,446

-6,446
Net fuel consumption
19,459
18,735
22,604
1,236
61,944
* To convert from physical production units to energy equivalents, units of a million barrels of oil were multiplied
with 5.5 to obtain trillion Btu, trillion cubic feet of natural gas with 1,000, and million short tons of coal with 25.2.
These conversion numbers are provided In a publication .from the U.S. Department of Commerce; Energy
Interrelationships. A Handbook of tables & Conversions Factors for Combining and Comparing International
Energy Data, prepared by National Energy Information Center, Washington, D.C., 1977, pages 34-36.
" Oil and gas extraction data from Energy Information Administration, Natural Gas Annual 1989, DOE/EIA-O131(89),
Washington, D.C., 1989. Coal extraction data from Energy Information Administration, Coal Production 1989,
DOE/EIA-0118(89), Washington, D.C., 1989. Wood burning is all in the pulp and paper industry from 1985 data;
from Energy Information Administration, Consumption of Energy 1988, DOE/EIA-O512(88), Washington, D.C.,
1991, Table 1.
1986 data from U.S. Department of Commerce, Bureau of the Census, Statistical Abstract of the United States
1988, Washington, D.C., 1988.
"" Energy data from Energy Information Administration, Consumption of Energy 1988, DOE/EIA-O512(88),
Washington, D.C., 1991, Table 1.
Table 3-2 shows C02 emissions estimates for each fuel type. We multiplied the net
energy values for each fuel type with a corresponding emissions factor. For simplicity, we
assumed that imports and exports of refined petroleum products had the same carbon content
as crude oil.
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Table 3-2
TOTAL U.S. C02 EMISSIONS ESTIMATED FROM FUEL PRODUCTION, 1989
(million tonnes of carbon)
Fuel Type Oil" Gas" Coal" Wood"* Total
Emissions * 410 271 576 27 1,284
* Emissions estimates were calculated by first multiplying the "net fuel consumption" for each fuel type with a
corresponding emissions factor; oil = 73,113 gram of COj/GJ, gas *> 50,257 g/GJ, coal = 88,440 g/GJ, and
wood = 75,000 g/GJ. Next, these products were multiplied with 1.056 10E-6 to yield million tonnes of C02,
and finally, multiplied with 12/44 to convert from C02 to carbon.
** The numbers follow United Nations convention, and is detailed in Marland (1983).
"* Emissions factor for wood from U.S. Environmental Protection Agency's; Policy Options for Stabilizing Global
Climate, Vol 1, Washington, D.C., 1989, p. IV-21.
PERMIT TRADING AT THE INDUSTRY LEVEL
Volume 1 estimates C02 emissions at the industry level, repeated here as Table 3-3. The
estimates are based on fossil fuel consumption (less feedstocks) in each industry, plus process-
based emissions from cement manufacture.
Since Tables 3-2 and 3-3 show emissions estimates for different years, a precise
comparison is not feasible. However, the tables indicate that total emissions covered under
permit trading at the industrial level are substantially lower than under permit trading at the
primary production level. Only on the order of one-half to two-thirds of the carbon emissions
would be regulated if all industry were to be involved in trading. Note that if only the top six
industries (including electric utilities) were to be regulated, almost equivalent regulatory
coverage would be attained. Some of the reasons for this low coverage are:
¦ Sectors of the economy. Fossil fuel combustion in the transportation,
residential and commercial sectors of the economy is not included at the
industry level. For example, gasoline consumption for road vehicles
would not be covered, and neither would fossil fuel fired heating of
residential and commercial buildings. While permit trading at the
industrial level would capture emissions from electric utilities, competing
energy sources like oil and gas-heated buildings would be exempt. The
transportation sector accounts for about 30% of U.S. C02 emissions, and
the residential and commercial sector account for about 11%.
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Table 3-3
EMISSIONS ESTIMATES IN U.S. INDUSTRIAL SECTOR, 1988
(million tonnes of carbon)
Industry
SIC
Estimate
Electric Utilities
491
527
Chemicals
28
60
Paper
261 - 263
45*
Steel
3312
44
Cement
3241
15"
Petroleum Refining
2911
13
Glass & Stone
32 ex 3241
9
Transport Equipment
37
4
Other, non-utility industry
20-39
40
Other, non-manufacturing
1-17
32
Total

789
The estimate for paper mills includes about 27 million tonnes of carbon emissions from wood, which may have lower
net emissions when accounting for the offsetting reduction due to replacement growth of trees.
The estimate for cement include emissions from calcining, which is unrelated to fossil fuel consumption. Calcining
emissions from cement manufacturing are estimated at roughly 9 million tonnes carbon, and fuel combustion
emissions at 6 million tonnes.
Fuel lost in transit. As fuels move from the point of extraction, through
refineries and distributors, and finally reach the final user, each
transportation, storage and processing link is likely to have losses in terms
of fuel spills, leakages, etc. These fuel losses would not be included in an
accounting of emissions at more upstream levels of market where the
permit trading might be implemented. This is probably a relatively small
effect, especially compared to the previous point. It is also unclear if "lost"
fuels should be treated as if carbon emissions occur from them. Like
feedstocks, these may not result in emissions of CO2, although VOCs will
be affected.
Point versus non-point sources. Emissions at the industry level could be
measured indirectly via fuel purchases, or it could be measured directly
by monitoring each stack. (The estimates provided here are based on fuel
purchase data.) The direct method may be preferred by regulators,43
43. The 1990 Clean Air Act actually sets the groundwork for this approach by requiring utilities to start
continuous stack monitoring of C02.
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What Amount of Emissions Would Be Subject to Control? 3-7
however, it would not automatically capture non-point emissions sources,
creating further possible leakage for regulating industry emissions.
¦ Global emissions. Over time, implementing permit trading at the industry
level would also bring about the risk of increased "importing" of
emissions.44 For example, permit trading would be likely to make the
cement industry even more vulnerable to foreign competition. If foreign
producers are less fuel efficient, one may in fact see a net increase in
global C02 emissions as a result of industrial regulations to reduce them.
This paradox could be counteracted by taxing imports according to the
fossil fuel used in the production process.
Thus it is apparent that an implementation of trading at the industrial level creates many
more opportunities for leakage of emissions than trading at the primary producer level. Even
more importantly, regulation of industrial emissions does not address up to 40 percent of all
man-made C02 sources in the U.S. If a goal of carbon emissions stabilization or reduction is to
be achieved, these industries would have to bear a much heavier control burden than if a better
coverage of the other 40 percent of emissions were to be designed into the regulations.
PERMIT TRADING AT THE END-USE LEVEL
By definition, permit trading among all end-users of fossil fuels would provide the most
comprehensive regulatory coverage. Only by observing emission-causing activities directly can
the problems of leakages and overcounting be avoided completely. However, the millions of
parties involved in such regulations (mostly individual citizens who individually make up a
miniscule fraction of the total) would create another problem altogether. It would be very
difficult to administer and enforce such a program.
In Section 2, a hybrid approach was suggested, to regulate the producers of equipment
that individuals use to burn fuels. This avoids the numbers problem of the end-use level, but
is a very indirect and incomplete way to regulate emissions. Approximation of eventual
emissions based on fuel sales was one of the drawbacks noted for trading among primary
producers. The degree of approximation that follows from the suggested industry/end-user
hybrid is much greater. Not only must the emissions rate be estimated, but so also the fuel
usage of the average consumer over time. Potentials for error are large, and systematic leakages
will almost certainly occur in such a regulatory scheme. Further, the incentives for finding the
most cost-effective responses are incomplete. On the other hand, it would almost double the
coverage that can be obtained from trading at the industrial level without a disproportionate
increase in the parties involved in the regulation.
44. This problem will be true to some degree of any regulation that increases domestic costs relative to foreign
costs. However, it may be greater when the burden of control falls fully on only one portion of the economy.
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SUMMARY
The cost-effectiveness of C02 emission reductions in a carbon permit market can be
reduced by excluding from coverage carbon sources that contribute to emissions. Imports of
fossil fuels represent one potential leakage and a permit market implemented at the level of
energy production would need to take this into account. Inclusion of imports in a producer
permit market probably presents no serious administrative problems, but needs to be considered
in the regulatory design.
Another potential source of leakage is the emissions associated with refining, processing,
and transporting energy. Emissions from oil refining represent the fifth largest industrial source
of COz emissions. If carbon permits are required for the sale or purchase of refined or processed
energy products, the emissions from these processes will not be directly constrained unless
carbon permit requirements are calculated after accounting for all upstream emissions in the
processing of raw materials into fuels consumed.
The high cost of administering a permit market for all energy consumers (including
residential, commercial, and transportation) creates a large potential leakage, because a workable
permit market for energy consumers would likely be reduced in scope to cover only major
industrial sources. However, the major sources, even broadly defined, only account for about
60% of emissions. This leakage could be plugged by complementing a permit market for
industrial sources with other policies directed at the remaining energy consuming sectors.
The cost-effectiveness of C02 emission reductions in a carbon permit market might also
be reduced by including carbon that does not contribute to emissions. For example, energy
feedstocks sequester carbon in products and, thus, do not contribute to C02 emissions.
Identifying and exempting energy that is bound for use as feedstocks will be difficult in a carbon
permit market for producers and less difficult in a carbon permit market for consumers.
Renewable energy that contains carbon presents problems for both producer and consumer
permit markets. Depending upon how renewable carbon energy stocks are managed, and the
time horizon considered relevant, use of these resources may or may not result in net C02
emissions.
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4
WHAT ARE THE MECHANISMS FOR MONITORING
AND ENFORCEMENT?
An EPA scoping study on emissions trading issues45 elucidates how incentives to cheat
in a permit market exist, regardless of the fact that such a market can function competitively.
Neither buyer nor seller in a permit market would have an incentive to see that the emissions
reductions transacted would actually occur. This fact has been observed in the case of enforcing
the phase-down of lead in gasoline.46 The possible lack of incentives to comply, combined
with the diversity of the sources included in a permit trading market for C02 indicate that
effective monitoring and means of enforcement could be key issues in ensuring that an emissions
market will work. This section discusses specific implementation issues connected with permit
trading at different levels of the economy, including how emissions will be monitored and the
effect of the number of sources.
NUMBER OF SOURCES
The number of source units included in a permit trading market has important
implications for monitoring; the more source units there are and the more dispersed they are,
the more resources will be required for effective monitoring. From the perspective of effective
monitoring; the fewer sources the better. On the other hand, basic economic theory argues that
market efficiency is a function of the number of market participants. Thus, the design of a
permit trading market would require policy decision makers to make a tradeoff where both
considerations are sufficiently accounted for.
From Section 2, we know that depending on how we define a source unit at the primary
production level, the number can vary from less than 6,000 to almost 900,000 (see Figure 2-2).
At the industry combustion level, the major emitting industries (Table 2-3) add up to about
16,000. If we include some of the producers of products with a life-cycle of emissions (car
producers, home appliances, etc., from Table 2-5) to represent emissions from the transportation
and commercial and residential sectors, the total number will still likely be below 30,000 source
units. At the end-use level, there would be millions of sources.
45.	Smith, A. E., A. R. Gjerde, and D. Cohan, Practical Considerations in Using Emissions Trading to Control
Greenhouse Gases, EPA Report Under Contract No. 68-CO-0021, January 1991, p. 15.
46.	Loeb, Alan P., Three Misconceptions About Emissions Trading, Air & Waste Management Association
Conference, Paper No. 90-155.8, 1990.
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ESTIMATING AND REPORTING EMISSIONS
Enforcement of the trading program will be a concern for implementation at any of the
market levels. However, because trading would proceed on different bases, enforcement issues
may be quite different among the implementation options. For example, controls at the primary
level would have to be based on the carbon content of fuel products while controls at the
industrial level could be based on measured emissions as well. The ability to track the two may
be quite different.
Fuel purchases or sales may be relatively easy to monitor wherever there is a distinct
market, and in fact there are already very reliable systems in place for such data. (We have
relied on such data to prepare this analysis.) Problems with such data may arise when markets
are not easily distinguished, as in the case of vertical integration.
Stack monitoring may seem more appealing because it directly addresses actual
emissions. However, it requires that new equipment be placed on many thousands of sources.
(Tailpipe monitoring for vehicles is not even considered an option at this point.) Where it is
feasible, stack monitoring may be costly and may be subject to reliability problems.47 It also
may fail to detect much of the emissions, if fugitive COz emissions are common among the
industrial processes. Given these concerns, it would be reasonable to choose to measure fossil
fuel use as a proxy for emissions, even where stack monitoring would be an option. This is
because COz is one of the few pollutants for which the main control option is not a technological
change of the manufacturing process or equipment. The key control options that are cost-
effective today are to use less carbon-intensive sources of energy, or less energy itself. Both
actions would be reflected directly in fossil fuel use statistics.
Thus it is likely that monitoring would proceed on the basis of measured fuel use. .
However, as has been noted in earlier sections, the fuel used may be measured in terms of either
fuel purchased or fuel sold for all levels and sub-levels of the market through to the point where
the fuel is burned. At that point, fuel purchased is the only fuel-based monitoring option, and
stack monitoring becomes the other alternative. Table 4-1 shows some of the alternative ways
in which emissions can be measured at different levels of the economy.
Note from the table that the quantity sold at one sub-level of the primary production
categories should be equal in aggregate to the quantity purchased at the next sub-level. The
main difference in the two options consists of the form of disaggregation in which the data will
be available. Data on quantities sold will be disaggregated by the seller, and data on total
quantity purchased will be disaggregated by the purchasing entities, even though the two
quantities would be identical when summed. It is possible that data may already be collected
in one of the two forms, but not the other. If so, this would have implications for which side
of the market would be easiest to monitor, should that market be identified as the appropriate
level where trading should occur.
47. Discussions about how to achieve acceptable levels of reliability in continuous monitors required under the
1990 Clean Air Act Amendments have been quite protracted. The technology is however developing rapidly.
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Table 4-1
OPTIONS FOR ESTIMATING EMISSIONS
Level of Economy
Examples
Input-based Measuring Output-based Measuring
Fuel Extraction
Sub-level
Refining Sub-level
Distribution to
End-User Sub-level
Industry Level
End-User Level
Oil and gas wells, coal
mines
Petroleum refineries, and
coal cleaning/ blending
units'
Gas pipeline, gasoline
distributors, coal
distributors, etc.
Electric utilities, chemical
plants, etc.
Motor vehicles, home
appliances, etc.
Quantity of crude oil,
natural gas or coal
extracted
Quantity of crude oil or
uncleaned coal
purchased
Quantity of fuel
purchased from gas well,
refinery, or coal refiner
Quantities of fuel types
purchased
Fuel and electricity
purchased
Quantity of raw products
sold or otherwise shipped
out
Quantities of refined fuels
sold, by fuel type, and
cleaned coal
Quantity sold to end-users
(industry and retailers)
Stack monitoring
None
If permit trading were implemented at the fuel extraction level, it would probably be
more difficult to monitor fuel extraction volumes than volumes sold or shipped from the well.
Other than in cases of long term on-site storage, there should be little difference between the two
measures.
At the refining sub-level,48 monitoring could take place in terms of the unrefined fuel
entering the refining process, or it could be attached to volumes sold or shipped after refining.
However, for petroleum, output-based measuring would require accounting for multiple
products (e.g., gasoline, diesel, residual fuel oil), whereas input-based measurement would apply
to the crude fuel only. This has advantages and disadvantages. The relative carbon content of
specific refined fuels could be defined more precisely. Also, products headed for feedstock
usage might be more easily accommodated. There is a substantial vise of fuels during the
refining process that should be accounted for, however.
At the refined product distribution sub-level, one is very close to actual end-use.
Feedstock sales should be easiest to identify at this level, and imports of fossil fuels, either
refined or unrefined, largely must go through the distribution system, thus reducing that
problem area. Again, fuels used in the extraction and refining processes should be accounted
for when estimating the carbon contents at this level. Fuel losses from distribution itself would
mostly account for any differences between quantities input and output from this level. These
may be relatively small, so either measure would probably be acceptable.
48. There is no equivalent to the refining sub-level for natural gas. For coal, cleaning and processing would be
the equivalent activity, but the "refined" product would still be coal, rather than the array of fuel products
that would be obtained from crude oil.
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At the industry level of the economy, monitoring could be attached to fuel purchases, or
each stack could be monitored. While stack monitoring is the most direct way of measuring
emissions, it would probably be relatively costly to install such devices, and would probably
affect small scale operations more than large scale. Further, stack monitoring would not
automatically capture non-point emissions, and may not be exceptionally reliable for continuous
monitoring.
At the end-user level of the economy, the only feasible way to monitor emissions would
be through fuel purchases. Even this will be difficult to monitor, as it would require accounting
for every gasoline purchase for every car. Without an extremely cumbersome comparison of
sales records of gasoline stations with declarations by millions of consumers, there would be no
way to introduce quality assurance. Tailpipe monitoring seems only slightly less cumbersome,
should there ever be a technology that could perform such monitoring on a cumulative basis that
could be tallied at periodic intervals. No such technology exists, nor is known to be under
development. The only alternative would involve letting fuel sellers buy the allowances for the
consumers, and then charge consumers on a per purchase basis for such permits. This would
become equivalent to trading among fuel distributions.
VERTICAL INTEGRATION
As mentioned in Section 2, vertical integration may create difficulties in obtaining the
necessary data for controlling emissions at specific levels of the market. Where large portions
of a market level are internalized within several major integrated firms, reporting requirements
may require the development of new regulatory infrastructure. In addition to the start-up and
administrative costs, there would also some potential concern with the quality of such data. It
would be far more straightforward to implement a trading system that could depend on readily
available market data. Thus, trading at market levels beyond the point where vertical integration
is no longer a major aspect of market structure would be favored. Vertical integration is a
common feature in primary energy production, through to the point of energy consumption.
This makes a case for trading at the distribution sub-level, or else among energy end users.
SUMMARY
It is clear that the end-use level would present extraordinary burdens for enforcement.
The industrial combustion level has a more limited number of entities that would have to be
subject to reporting requirements, but information on fuels used rather than stack monitoring
would seem to be the more cost-effective and reliable approach for assessing permit
requirements. As such, there should be no difference whether their fuel suppliers or they
themselves should be required to obtain the sufficient number of permits. However, monitoring
may be easier still for the distributors, and this would provide coverage of a much broader range
of emissions sources than just the industrial fuel users.
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Volume 2: Choosing the Market Level for Trading
What Are the Mechanisms for Monitoring and Enforcement? 4-5
Referring back to information presented in Sections 2 and 3, it appears that any primary
market sub-level may be acceptable for obtaining a sufficiently sized market that also provides
good coverage of emissions. The only possible exception might be the refining level where there
are only about 200 refining units. Since refining does not pose itself as exceptionally
advantageous from any other standpoint, it should perhaps be given less attention as a possible
point of emissions trading.
The primary production level in general seems to offer the greatest flexibility in terms
of monitoring and enforcement. From the point of view of monitoring, the point where sales
are made from the distributors to fuel users appears to have the most advantages from the point
of view of manageability of monitoring and enforcement, and in terms of having reasonable
sources of sales data from which to estimate permit requirements.
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5
CONCLUSIONS
This report has described a series of options for implementing C02 emissions trading, and
has reviewed a number of the considerations in choosing among them. The requirements of
each option were described, and a theoretical formulation showed how economically equivalent
options may seem to be different in terms of "fairness." The focus of the report, however, has
been on criteria of cost and effectiveness. Considerations that should be incorporated into the
implementation decision include how much of the emissions would be controllable, the size of
the trading market, how much market concentration there might be, geographical transfers of
wealth that might result as well as geographical concentrations of groups that might wish to
trade in a similar fashion, monitoring feasibility, and administrative burdens.
Table 5-1 summarizes how the three levels of the market might compare along these
dimensions, based on the data developed for this study, and presented in earlier sections of this
report. In the table, the primary producer level has been split into three intermediate stages
(extraction, refining, and distribution), as Section 2 explained. The table also includes one of
many possible hybrid approaches, where industrial emissions trading would be expanded to
include the energy equipment manufacturing industry, which would be held accountable for
lifecycle emissions from the equipment that is produced and sold.
Table 5-1
EVALUATION OF C02 ALLOWANCE TRADING AT DIFFERENT MARKET LEVELS

# Involved
Market
Dysfunction
Potential
Degree of
Geographical
Concentration
Enforce-
ability
Emissions
Coverage
import
Issues?
Extraction
1.000s
None
High
Moderate
High
Yes
Refining
1.000s
None
High
Moderate
High
Yes
Distribution to Users
1,000s
None
Low
High
High
No
Industries
10,000s
Electric
utility rates
regulations
Moderate
High
Low
No
All End-Users
100,000,000s
None
Low
Low
High
No
Hybrid (Equipment
Manufacturers &
10.000s
Electric
utility rates
Moderate
High
Moderate
Yes
Industry)	regulations
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5-2 Conclusions
Volume 2: Choosing the Market Level for Trading
From Table 5-1, a couple of immediate conclusions can be drawn. Trading that includes
all end users seems unwise. Although they have good coverage of total carbon sources, both
levels may be very costly to administer and enforce.
Similarly, the option to institute trading among major industrial end users, although a
very obvious one with a long regulatory precedent, may be dominated by other options on a
cost-effectiveness basis. The problems of utility incentives could be very serious for effective
market functioning.49 Coverage of emissions is also lowest for this option. The hybrid
approach improves on the coverage problem of trading at the industry level, but retains the
utility incentives problem that could lead to market dysfunction. It also provides only
incomplete incentives for control among end-users.
Thus, trading at the primary producer level appears to be most promising on a cost-
effectiveness basis. However, it is not immediately clear which of the three sub-levels would be
the best candidate. At the extraction and refining sub-levels, there could be problems associated
with data availability because of the substantial degree of vertical integration. Also, accounting
fairly for feedstocks and for imports could be difficult. Finally, the distribution of impacts may
be relatively concentrated geographically. A system introduced at the fuels distribution level,
after the refining/processing stage, would avoid these drawbacks but add a new one. Emissions
of carbon upstream are significant. The refining industry is one of the major industrial source
categories in the U.S. Some method for accounting for these upstream emissions may be
important to develop, and may not be straightforward to do. Nevertheless, for the primary
producer level in general, the number of sources is manageable, emissions coverage is high, and
enforceability is good.
Each of the three key market levels that were considered is summarized in more detail
in the remainder of this section.
TRADING AT THE PRIMARY PRODUCER LEVEL
This is not a simple market level, but has numerous sub-levels, from extraction activities
through processing and refining, to distribution systems that get the final products to the end-
users. Vertical integration is a common feature, but not enough so that the entire set of sub-
levels should be considered as one. Of the sub-levels, it appears that the most reasonable one
in terms of controllability of total emissions sources, monitoring feasibility, and geographical
dispersion would be the distribution-to-end-users sub-level.
This set of parties sells to both industrial consumers and retailers. At this sub-level the
products have well defined uses that can be directly tied to C02 emissions. Also, fuel products
destined for use as feedstocks can be easily separated out of the trading system, and all forms
of energy imports can be included without special provisions for how to treat foreign enterprises.
49. This is a concern for implementation of any market approach to emissions control, including emissions taxes
as well as emissions trading.
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Volume 2: Choosing the Market Level for Trading
Conclusions 5-3
Some special considerations would have to be made to handle emissions caused by fuel use
among the other sub-levels, with refining operations at the focal point. That is, upstream
emissions should be estimated for each fuel distributed and these emissions added into the
carbon content assessed.
TRADING AT THE INDUSTRIAL LEVEL
The industrial level seems like the most natural level of the market to initiate a trading
program. It is where the largest point sources exist, monitoring can be performed directly on
emissions, and the trading would appear to target the emissions problem directly. Even though
emissions would be the commodity traded, the indirect effect on fuel markets would result in
changes in energy supplied, much like one would expect if the primary producers were the locus
of trading.
However, the results of trading industrial emissions would not be equivalent to those of
trading carbon content of primary fuels. The key reason is that industrial emissions only account
for half to two-thirds of all emissions of C02 in the U.S. Any regulation of industry would only
provide incentives affecting the use of fuels in the mix relevant to industry. A large number of
cost-effective control options might be missed, such as those associated with transportation.
Also, the energy supply effects that would trickle back to the primaiy producers could be quite
different than if carbon content of all fossil fuels were directly the basis of trading.
In return for these gaps associated with trading among industries only, there are few
gains among the other criteria noted above. The number of entities affected is of a similar order
of magnitude as for trading among primary producers, and options for monitoring compliance
are very similar. Although stack monitoring is an option here, it is probably more precise,
straightforward, and less costly to base emissions estimates on fuel use by industry. Other than
in terms of the way such fuel use data is disaggregated, it is equivalent information to that of
distributors' sales.
Regulation of industrial emissions is more likely to present problems of geographical
concentration in where emissions reductions occur than it is for either other market level. Thus
industrial trading has a greater potential than other forms of trading to be undermined by local
regulatory intervention that would try to avoid loss of the coincidental benefits of reductions in
other pollutants. On top of this can be added the problem of how the electric utilities would
participate in trading, given their rate setting process. Since the electric utilities account for more
than half of the industrial emissions, any potential for poor participation on their part would
have significant implications for the trading market as a whole.
TRADING AT THE END-USE LEVEL
The only advantage noted for the option of having all end-users participate in trading
was that it would provide the most complete coverage of actual emissions in the U.S. However,
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5-4 Conclusions
Volume 2: Choosing the Market Level for Trading
a very similar level of coverage is attained with regulating primary producers, but with a
reduction in the number of parties that must be monitored by a factor of as much as 10,000.
Although large numbers are important to a competitively functioning market, it looks like there
are sufficient numbers at the primary producer level (particularly if applied at the distributor
level). To move in the direction of millions of parties, as is found at the end-use level, is
unnecessary and probably infeasible to enforce effectively. The end-use level does provide the
most widespread geographical distribution of permits and impacts, with little likelihood of
intervention by local authorities. However, the distributor system is probably equally
widespread geographically.
CONTROLLING END-USES AT THE MANUFACTURER LEVEL
An hybrid approach has been discussed to incorporate emissions from the transportation,
residential, and commercial sectors without requiring trading among end-users. This would be
to include all the emissions of fuel-using equipment over equipment lives in the estimate of
emissions for which the equipment manufacturers must obtain permits. Trading would include
large industrial fuel consumers as well as equipment manufacturers, with the only difference
between the two categories being whether an estimate of life-cycle emissions would be added
to the on-site emissions for which permits would be required. Thus the much broader coverage
of most emissions categories can be attained with only a few thousand parties added to the
trading scheme.
This definitely has advantages over the option for trading at the end-user level of the
market, and at the industrial level, as defined in this study. However, the crucial question is
how well it compares to trading at the primary producer level. (Assume that this would mean
trading among distributors to industrial consumers and retailers.) Here it appears that the
decision will depend on the relative disadvantages of forcing manufacturers to be responsible
for the emissions of their customers. The latter problem is one of both of precision in making
the life-cycle emissions estimates and of incomplete user incentives. Another possible
disadvantage of the hybrid approach is that it raises possible concerns of geographical
concentration, and management problems for how to include importers of fuel-using equipment
into the trading scheme.
RECOMMENDATIONS FOR FURTHER STUDY
At this point in the study, it appears as if the most viable place that trading could be
implemented would be among the distributors of fuels to end-users, both industries and
retailers. The resulting economic impacts are the same as requiring emissions reductions as long
as there are no cost-effective measures for removing C02 from the stacks or tailpipes after the
carbon-containing fuel has been burned.
The possibility of developing additional programs that are hybrids of the three options
presented here should be noted. Two hybrid approaches were described in Section 2, and one
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Volume 2: Choosing the Market Level for Trading
Conclusions 5-5
noted above does have some promising features. Similarly, if trading were to be implemented
among fuel distributors, then additional consideration of emissions from primary producer
activities, such as refinery fuel use, should also be folded into the program in some way.
Further work should identify and look closely at other possible hybrid options.
Another area that requires further consideration is how additional greenhouse gases
could be incorporated into each possible implementation plan. Especially in the case where the
trading might be implemented in terms of the carbon content of fuel supplied, the extension to
other forms of emissions is not immediately apparent. Can some system of offsets for the other
gases be added to the trading, or is it necessary to go back to the concept of trading at the point
where emissions occur to obtain the desired integration of all emissions in a comprehensive
approach?
International trading issues are also of interest. The issue of how to incorporate foreign
enterprises into a national trading scheme has been briefly mentioned. It is quite feasible, but
could present some political concerns. Similarly, what would happen to the conclusions
presented here if an international trading scheme were to be considered rather than a national
one?
Finally, this study has focused on identifying ways in which there might be barriers to
the functioning or acceptable implementation of a trading scheme. Nothing in the analysis helps
determine who would trade with whom, or what the transactions of permits might look like
under any of the schemes. Inter-regional flows of permits, and inter-industry flows may be of
interest. To obtain a better understanding of these patterns, further analytical modeling must
be done. This line of work would provide interesting complementary information for the
deliberation on the best market level for trading, and hybrid options.
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Appendix A
DETAILED INDUSTRY DATA
This Appendix presents for each industry, the number of source units in each state,
production volumes, total C02 emissions, and average C02 emissions per source unit. Following
a discussion of data sources, and a brief outline of how we calculated emissions estimates, the
data table is displayed in Table A-3.
DATA AND DATA SOURCES
Data sources were not readily available to us for the same year. However, since the data
is relatively recent (1987 or later), and for the purposes of this report, we do not think that any
conclusions drawn would be affected. Table A-l shows the year for which the different data
were collected.
Table A-1
YEAR OF DATA SOURCES

Number of
Sources
Production
Volumes
Emissions
Estimates
Primary Production Level
1989
1989
1989
Electric Utilities
1989
1989
1989
Petroleum Refineries
1990
1987
1988
Other Industries
1987
1987
1988
Source units were defined as a single physical unit; well or mine at the primary
production level, and a production plant at the industry level. Production volumes at the
primary production level are physical production volumes; thousand barrels of oil, million cubic
feet of gas, and thousand short tons of coal. For electric utilities, production volumes are
measured in giga watthours. For all other industries, we measured production volumes as "value
of shipment" (million dollars). Total CO2 emissions are reported in million tonnes of carbon, and
emissions per source unit in thousand tonnes of carbon.
Data on number of source units and production volumes were taken from the following
sources:
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A-2 Detailed Industry Data
Volume 2: Choosing the Market Level for Trading
Oil and Gas Wells:
Coal Mines:
Electric Utilities:
American Petroleum Institute, Basic Petroleum Data Book.
Petroleum Industry Statistics, Vol. XI, No. 1, Washington,
D.C., 1991.
Energy Information Administration, "Coal Production 1989,
DOE/EIA-Ol 18(89), Washington, D.C., 1989.
Energy Information Administration, Inventory of Power Plants
in the United States 1989, DOE/EIA-0095(89), Washington,
D.C., 1989.
Petroleum Refineries: Number of units; PennWell Publishing Company, International
Petroleum Encyclopedia 1990, Tulsa, Oklahoma, 1991.
Production volume; U.S. Department of Commerce, Bureau of the
Census, 1987 Census of Manufactures. Industry Series,
Washington, D.C., 1989.
Other Industries:
U.S. Department of Commerce, Bureau of the Census, 1987
Census of Manufactures. Industry Series, Washington, D.C.,
1989.
CALCULATING EMISSIONS ESTIMATES
Primary Production Level. Emissions estimates for the primary production level were calculated
by converting fuel production volumes for each fuel type into energy equivalents, and
multiplying these with a corresponding emissions factor.
Table A-2 provides the multipliers used to convert physical energy volumes into energy
equivalents (trillion Btu), and the emissions factors we used for each fuel type.
We converted grams of C02/gigajoule into million tonnes of C02/trillion Btu by
multiplying with 1.056 10E-6,50 and converted C02 into carbon equivalents by multiplying with
12/44.
Electric Utilities. Emissions estimates from the electric utilities industry are based on energy
consumption from oil, gas, and coal-fired utilities.51 There is some difference between these
50. U.S. Department of Commerce, National Technical Information Service, Energy Interrelationships. A
Handbook of Tables & Conversions Factors for Combining and Comparing International Energy
Data, Washington, D.C., 1977.
51. Energy Information Administration, Electric Power Annual 1988, Washington, D.C., January 1990, Table
10.
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Volume 2: Choosing the Market Level for Trading
Detailed Industry Data A-3
estimates and those reported by the Energy Information Administration;52 our estimate is 580
million tonnes of carbon, versus EIA's 530 million tonnes.
Table A-2
CONVERSION FACTORS
Conv. From
Conv. To
Oil
Gas
Coal
Million barrels oil
Trillion Btu
5.5 *


Trill, cubic feet gas
Trillion Btu

1,000 ••

Million sh.tons coal
Trillion Btu


25.2 *"
Fossil Fuel	Gram CCyGJ	73,113 50,257 88,400
U.S. Department of Commerce, National Technical Information Service, Energy Interrelationships. A
Handbook of Tables & Conversions Factors for Combining and Comparing International Energy Data,
Washington, D.C., 1977, p. 34.
Ibid., p. 35.
Ibid., p. 36.
*"* The emissions factors comply with the United Nations convention, and is detailed in Marland (1983).
Other Industries. Total emissions estimates for other industries at the combustion level were
calculated in Volume 1 of this report. We allocated these estimates to the different states based
on production volume (as represented by value of shipment). For some industries, our data on
production volume breakdown was incomplete. In these cases, we allocated emissions to each
state based on number of plants.
52. Ibid., Table 31.
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A-4 Detailed Industry Data
Volume 2: Choosing the Market Level for Trading
Table A-3
INDUSTRY CHARACTERISTICS (106 tonnes C)








Emtss.
Emss.
Emiss.
Emss.
Emtss.
Emiss.


a
#
#
Oil
Gas
Coal
tr.oil
fr.gas
Ir.coai
per
per
per
STATE
Oil
Gas
Coal
Prod.
Prod.
Prod.
millmetr
mill metr
mil metr
oil well
gas well
coalmine


wells
wells
mines
(th.bbl)
(m.cu.ft)
(th.sh.t)
ton C
tonC
tonC
th.m.t.C
th.m.t.C
th.m.t.C
AL
Alabama
931
1701
105
19813
128411
27900
2
2
18
2.46
1.09
170.55
AK
Alaska
1337
108
1
683980
393729
1600
79
6
1
59.25
52.77
1026.98
AZ
Arizona
25
3
2
138
1360
11900
0
0
8
0.64
&56
3819.08
AR
Arkansas
7865
2830
7
11261
168300
70
1
2
0
0.17
0.86
6.42
CA
Call
43745
1214
1
364249
362860
40
42
5
0
026
433
25.67
CO
Colorado
6362
5125
23
30655
216737
17100
4
3
11
056
0.61
477.21
CT
Connect.
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
OE
Delaware
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
R_
Florida
101
0
0
7289
7534
0
1
0
0
8.36
0.00
0.00
GA
Georgia
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
HA
Hawaii
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
10
Idaho
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
IL
Illinois
32441
241
48
20377
1477
59300
2
0
38
0.07
0.09
792.97
IN
Indiana
7543
1310
60
3310
416
33600
0
0
22
0.05
0.00
359.44
IA
Iowa
0
0
5
0
0
400
0
0
0
0.00
0.00
5135
KS
Kansas
44969
13935
5
55484
587320
900
6
9
1
0.14
0.61
115.54
KY
Kentucky
22859
11248
1099
5414
72417
167400
1
1
107
0.03
0.09
97.77
LA
Louisiana
22872
16309
2
404615
5078125
3000
47
74
2
2.05
4.51
962.79
ME
Maine
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
MD
Maryland
0
8
31
0
34
3400
0
0
2
0.00
0.06
70.40
MA
Massach.
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
Ml
Michigan
5557
1207
0
21566
155988
0
2
2
0
0.45
1.87
0.00
MN
Minnesota
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
MS
Mississip.
3598
543
0
27403
102645
0
3
1
0
0.88
2.74
0.00
MO
Missouri
807
4
9
136
4
3400
0
0
2
0.02
0.01
242.48
MT
Montana
4001
2700
9
20956
51307
37700
2
1
24
0.61
028
2688.69
NE
Nebraska
1787
15
0
6232
878
0
1
0
0
0.40
0.85
0.00
NV
Nevada
46
0
0
3218
0
0
0
0
0
8.10
0.00
0.00
NH
NewHamp
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
NJ
New Jerse
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
NM
New Mexe
17787
17087
8
68713
854615
23700
e
12
15
0.45
0.72
1901.52
NY
New York
4350
5304
0
495
20433
0
0
0
0
0.01
0.06
0.00
NC
N Carolina
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
NO
N Dakota
3442
61
13
36744
51174
30000
4
1
19
1.24
12.14
1481.22
OH
Ohio
30194
34450
184
10219
159730
33700
1
2
22
0.04
0.07
117.56
OK
Oklahoma
96344
27443
21
117493
2185240
1800
14
32
1
0.14
1.15
55.02
OR
Oregon
0
18
0
0
2500
0
0
0
0
0.00
2.01
0.00
PA
Peimsylv.
27218
30000
681
2702
191774
70600
0
3
45
0.01
0.09
66.54
SC
S Carolina
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
SD
S Dakota
156
53
0
1613
4369
0
0
0
0
1.20
1.19
0.00
TN
Tennessee
713
700
98
532
1900
6500
0
0
4
0.09
0.04
4257
TX
Texas
186226
48609
15
715790
6241425
53400
83
90
34
0.45
1.86
2285.03
irr
Utah
2234
834
21
28416
120089
20100
3
. 2
13
1.47
2.08
614.35
VT
Vermont
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
VA
Virginia
20
752
365
21
17935
43000
0
0
28
0.12
0.35
75.62
WA
Wasftingto
0
0
4
0
0
5000
0
0
3
0.00
0.00
802.33
WV
W Virginia
15940
36240
773
2243
198200
153600
0
3
99
0.02
0.08
12754
Wl
Wisconsin
0
0
0
0
0
0
0
0
0
0.00
0.00
0.00
WY
Wyoming
11539
2431
30
107713
665699
171600
12
10
110
1.08
356
3671.45


603009
262483
3620
2778790
18044625
980710
322
262
629
0.53
1.00
173.89
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Volume 2: Choosing the Market Level for Trading
Detailed Industry Data A-5
Table A-3
INDUSTRY CHARACTERISTICS (continued)


#
#
«
Oil
Gas
Coal
Emiss.
Emiss.
Emiss.
Emiss.
Emiss.
Emiss.


Oil
Gas
Coal
tired
fired
fired
from oil
from gas
Iiomcoal
peroa-
per gas-
per coal-
STATE
fired
fired
fired
Prod.
Prod.
Prod.
fired pi.
fired pi.
fired pi.
fired unit
fired unit
fired unit


util.
util.
util.
gigawhrs
gigawhrs
gigawhrs
mmt.C
m.nU.C

th.nrU.C
th.m.t.C
th.m.t.C
AL
Alabama
2
8
41
107
236
48835
0.02
0.04
15.82
12.08
554
38552
AK
Alaska
347
26
5
356
2588
316
0.08
0.49
0.10
0.23
18.71
20.48
AZ
Arizona
6
62
13
119
2341
28391
0.03
0.44
9.20
4.48
7.10
70759
AR
Arkansas
34
21
5
143
2065
19876
0.03
0.39
6.44
OSS
18.48
1287.96
CA
Calll.
59
149
0
7621
53893
0
1.72
10.13
0.00
29.17
6757
0.00
CO
Colorado
53
38
31
39
649
27801
0.01
0.12
9.01
0.17
321
29057
CT
Conned.
48
0
1
11356
111
2094
2.56
0.02
0.68
53.42
0.00
678.46
DE
Delaware
23
2
5
2848
317
5788
0.64
0.06
1.88
27.96
29.79
375.06
a
Florida
192
130
29
2S387
14744
57516
5.73
2.77
18.64
29 £6
2131
642.59
GA
Georgia
39
4
39
260
119
64834
0.06
0.02
21.01
151
559
538.62
HA
Hawaii
73
0
0
7597
0
0
1.72
0.00
0.00
2350
0.00
0.00
ID
Idaho
4
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
n.
llfinots
170
75
61
697
435
52994
0.16
0.08
17.17
033
1.09
281.48
IN
Indiana
37
15
80
383
317
82813
0.09
0.06
26.83
2.34
3.97
335.39
IA
Iowa
270
52
53
49
417
23345
0.01
0.08
756
0.04
151
142.71
KS
Kansas
233
177
20
147
1489
23089
0.03
028
7.48
0.14
158
374.04
KY
Kentucky
13
9
57
126
40
73847
0.03
0.01
23.93
2.19
0.84
419.76
LA
Louisiana
10
106
6
272
24286
18431
0.06
456
5.97
6.14
43.05
99527
ME
Maine
57
0
0
2944
0
0
0.66
0.00
0.00
11.66
0.00
0.00
MO
Maryland
60
16
14
3547
402
23316
0.80
0.08
755
13.35
4.72
539.60
MA
Massach.
109
7
9
19908
1802
11687
450
034
3.79
41.24
48.38
420.73
Ml
Michigan
178
67
82
1414
585
68578
0.32
0.11
22.22
1.79
1.64
27057
MN
Minnesota
168
47
55
142
410
26726
0.03
0.08
8.66
0.19
1.64
157.44
MS
Mississip.
5
37
9
659
2800
12051
0.15
053
330
29.76
1422
433.84
MO
Missouri
176
80
47
131
112
49051
0.03
0.02
15.89
0.17
026
338.14
MT
Montana
0
3
6
30
37
16462
0.01
0.01
5.33
0.00
2.32
888.95
NE
Nebraska
106
118
12
69
163
12225
0.02
0.03
3.96
0.15
026
330.08
NV
Nevada
32
16
8
542
899
16764
0.12
0.17
5.43
3.82
1056
678.94
NH
New Hamp
7
0
5
2828
5
3197
0.64
0.00
1.04
9123
0.00
207.17
NJ
New Jerse
50
52
9
5052
4276
7163
1.14
0.80
2.32
22.82
15.45
257.87
NM
New Mexic
6
29
13
45
1979
24245
0.01
0.37
7.86
1.69
12.82
60426
NY
New York
167
89
32
39865
14012
22761
9.00
2.63
7.37
53.91
2959
230.46
NC
N Carolina
38
8
47
225
55
46090
0.05
0.01
14.93
1.34
129
317.73
ND
N Dakota
29
2
14
18
0
25450
0.00
0.00
8.25
0.14
0.00
588.99
OH
Ohio
76
30
120
415
63
114564
0.09
0.01
37.12
123
0.39
309.32
OK
Oklahoma
26
85
10
29
17688
24273
0.01
3.32
7.86
025
39.11
786.45
PA
Pennsytv.
109
11
65
7915
211
106239
1.79
0.04
34.42
16.40
3.60
52956
Rl
Rhode Isl.
24
0
0
749
15
0
0.17
0.00
0.00
7.05
0.00
0.00
SC
S Carolina
44
12
24
96
226
23485
0.02
0.04
7.61
0.49
354
317.05
SD
S Dakota
39
9
6
15
11
2605
0.00
0.00
0.84
0.09
023
140.67
TN
Tennessee
20
20
37
187
16
51122
0.04
0.00
1656
2.11
0.15
447.66
TX
Texas
33
325
33
756
102521
112876
0.17
19.27
3657
5.17
5928
110824
UT
Utah
13
20
14
59
5
28806
0.01
0.00
9.33
1.02
0.05
666.65
VT
Vermont
24
0
0
26
0
0
0.01
0.00
0.00
024
0.00
0.00
VA
Virginia
45
3
24
2838
102
21413
0.64
0.02
6.94
1424
6.39
289.08
WA
Washingto
10
7
2
8
153
8670
0.00
0.03
2.81
0.18
4.11
140454
WV
W Virginia
1
0
33
260
10
80747
0.06
0.00
26.16
58.71
0.00
792.79
Wl
Wisconsin
107
19
54
97
180
31867
0.02
0.03
10.32
020
1.78
19120
WY
Wyoming
9
0
19
62
18
38279
0.01
0.00
12.40
156
0.00
652.76


3385
1992
1250
148438
252803
1540682
33.52
47.51
499.18
9.90
23.85
399.34
R2023g
Dedslon Focuj Incorporated

-------
A-6 Detailed Industry Data
Volume 2: Choosing the Market Level for Trading
Table A-3
INDUSTRY CHARACTERISTICS (continued)





Reliner.
Paper
Steel mis
Retiner.
Paper
Steel
Refiner.
Paper
Sleel





Value
Value
Value
C02 emiss C02 emtss C02 emiss C02 emts/ C02 ems/ C02 emts/
STATE
#
*
*
of shipm.
of shipm.
of shipm.



Unit
Unit
Unit


Reliner.
Paper uts
Steel mis
mill $
(rati $
mdl$
nutu.C
nunj.C
mmt.C
thmLC
th.m.t.C
thJTU.C
AL
Alabama
3
16
13
830
3835
1449
0.09
3.82
1.84
3058
23839
141.49
AK
Alaska
6
2
0
1490
130
0
0.16
0.13
0.00
27.45
6455
0.00
AZ
Arizona
1
2
0
0
130
0
0.00
0.13
0.00
0.00
6455
0.00
AR
Aricansas
3
7
4
499
1491
446
0.06
1.49
057
18.39
21222
141.49
CA
Calif.
31
27
18
15639
1312
571
1.73
1.31
0.73
55.79
48.44
40.28
CO
Colorado
2
0
2
564
0
223
0.06
0.00
0.28
31.16
0.00
141.49
CT
Connect.
0
9
3
0
583
334
0.00
0.58
0.42
0.00
6455
141.49
DE
Delaware
1
0
1
298
0
111
0J03
0.00
0.14
3235
0.00
141.49
FL
Honda
0
9
13
0
1089
1449
0J00
1.09
1.84
0.00
120.62
141.49
GA
Georgia
2
22
5
0
3329
557
0.00
332
0.71
0.00
15031
141.49
HA
Hawaii
2
0
0
596
0
0
0.07
0.00
0.00
3235
0.00
0.00
10
Idaho
0
1
0
0
65
0
0.00
0.06
0.00
0.00
6455
0.00
IL
Illinois
6
9
28
6458
583
2760
0.71
0.58
3.50
119.02
6455
125.16
IN
Indiana
4
8
14
2383
518
1560
0.26
052
138
65.89
6455
141.43
IA
Iowa
0
2
2
0
130
223
0.00
0.13
0.28
0.00
6455
141.49
KS
Kansas
8
0
0
2771
0
0
0.31
0.00
0.00
38.31
0.00
0.00
KY
Kentucky
2
4
8
894
2S9
891
0.10
0.26
1.13
49.42
6455
141.49
LA
Louisiana
17
12
2
17500
2348
223
134
2JJ4
0.28
11333
195.02
141.49
ME
Maine
0
15
0
0
2871
0
0.00
236
0.00
0.00
190.78
0.00
MO
Maryland
0
4
5
0
259
557
0.00
0.26
0.71
0.00
6455
141.49
MA
Massach.
0
32
0
0
2072
0
0.00
2.07
0.00
0.00
6455
0.00
Ml
Michigan
4
35
17
1490
2458
2691
0.16
2.45
3.42
41.18
70.00
201.00
MN
Minnesota
2
9
4
894
983
446
0.10
0.98
0.57
49.42
10852
141.49
MS
Mississip.
S
10
1
2383
648
111
0.26
0.65
0.14
52.71
6455
141.49
MO
Missouri
0
0
5
0
0
557
0.00
0.00
0.71
0.00
0.00
141.49
MT
Montana
4
1
0
892
65
0
0.10
0.06
0.00
24.66
6455
0.00
NE
Nebraska
0
0
1
0
0
111
0.00
0.00
0.14
0.00
0.00
141.49
NV
Nevada
1
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
NH
NewHamp
0
10
0
0
402
0
0.00
0.40
0.00
0.00
40.03
0.00
NJ
New Jerse
6
19
10
3855
1178
1114
0.43
1.17
.1.41
71.04
6131
141.49
NM
New Mexc
3
0
0
632
0
0
0.07
0.00
0.00
23.30
0.00
0.00
NV
New York
1
45
14
0
2018
1560
0.00
2.01
138
0.00
44.69
141.49
NC
N Carolina
0
10
1
0
648
111
0.00
0.65
0.14
0.00
6455
141.49
NO
N Dakota
1
0
0
298
0
0
0.03
0.00
0.00
3235
0.00
0.00
OH
Ohio
4
29
35
3682
2233
7047
0.41
2.23
8.95
101.78
76.75
2S5.66
OK
Oklahoma
6
5
6
2883
324
126
0.32
0.32
0.16
53.13
64.55
26.67
OR
Oregon
1
11
3
0
1601
334
0.00
1.60
0.42
0.00
145.02
141.49
PA
Pennsytv.
8
30
50
6640
1640
6525
0.73
1.63
823
91.79
54.49
165.71
SC
S r ^/oltna
0
9
10
0
1622
1114
0.00
1.62
1.41
QJOO
179.67
141.49
SD
S Dakota
0
0
0
0
0
0
0.00
0.00
0X10
0.00
0.00
0.00
TN
Tennessee
1
13
9
596
1249
1003
0.07
1.24
1.27
65.89
95.76
141.49
TX
Texas
31
10
14
34470
648
1560
3.81
0.65
138
12236
6455
141.49
UT
Utah
6
0
2
2681
0
223
0.30
0.00
0.28
49.42
0.00
141.49
VT
Vermont
0
7
0
0
205
0
0.00
020
0.00
0.00
29.25
0.00
VA
Virginia
1
12
5
596
1179
557
0.07
1.18
0.71
6539
9736
141.49
WA
Washingto
7
21
9
3499
1911
1003
0.39
130
1.27
55.27
90.71
141.49
WV
W Virginia
2
2
5
09D
130
557
0.07
0.13
0.71
3235
6455
141.49
Wl
Wisconsin
1
45
5
1192
4361
557
0.13
4.35
0.71
131.78
9659
141.49
WY
Wyoming
5
0
0
1017
0
0
0.11
0.00
0.00
22.49
0.00
0.00


188
514
324
118216
46506
38663
13.07
46.35
49.09
69.53
90.18
151.52
R2023g	Decision Focus Incorporated

-------
Volume 2: Choosing the Market Level for Trading
Detailed Industry Data A-7
Table A-3
	INDUSTRY CHARACTERISTICS (continued)	
Glass	Co mart	Glass Cement Glass Cement
Value	Value	C02 emissC02 emissC02 emis/ C02 eats/
STATE	#	# of shipm.	of shipm.	UnS Un#
Glass Cement min$	m.m.t.C m.nu.C thmt.C thmt.C
AL
Alabama
9
7
140
190
0.08
0.66
9.19
9337
AK
Alaska
0
0
0
0
0.00
0.00
0.00
0.00
AZ
Arizona
20
3
26
97
0.02
0.33
0.77
111.60
AR
Arkansas
18
3
148
97
0.09
0.33
5.46
111.60
CA
Calif.
329
21
2347
621
1.39
2.15
422
10237
CO
Colorado
27
4
63
129
0.04
0.45
138
111.60
CT
Connect.
25
0
98
0
0.06
0.00
232
0.00
DE
Delaware
0
0
0
0
0.00
0.00
0.00
0.00
FL
Florida
81
8
297
2
0.18
0.01
2.17
036
GA
Georgia
31
2
216
66
0.13
022
4.12
111.60
HA
Hawaii
0
0
0
0
0.00
0.00
0.00
0.00
ID
Idaho
0
0
0
0
0.00
0.00
0.00
0.00
IL
Illinois
77
7
756
226
0.45
0.78
531
111.60
IN
Incfiana
53
5
554
6
0.33
0.02
6.18
4.15
IA
Iowa
15
5
56
161
0.03
0.56
999
111.60
KS
Kansas
11
5
41
85
0.02
029
222
58.79
KY
Kentucky
18
3
217
97
0.13
0.33
7.12
111.60
LA
Louisiana
3
0
68
0
0.04
0.00
1333
0.00
ME
Maine
0
0
0
0
0.00
0.00
0.00
0.00
MO
Maryland
17
5
46
103
0.03
0.36
1.60
7124
MA
Massach.
43
0
282
0
0.17
0.00
337
0.00
Ml
Michigan
70
7
852
273
0.50
034
7.19
13438
MN
Minnesota
23
0
213
0
0.13
0.00
5.47
0.00
MS
Mississlp.
8
0
135
0
0.08
0.00
9.97
0.00
MO
Missouri
29
8
288
244
0.17
0.84
537
105.48
MT
Montana
0
3
0
97
0.00
033
0.00
111.60
NE
Nebraska
0
1
0
32
0.00
0.11
0.00
111.60
NV
Nevada
0
1
0
32
0.00
0.11
0.00
111.60
NH
NewHamp
2
0
8
0
0.00
0.00
222
0.00
NJ
New Jerse
136
0
1246
0
0.74
0.00
5.41
0.00
NM
NewMexic
0
0
0
0
0.00
0.00
0.00
0.00
NY
New York
150
9
853
290
0.50
1.00
336
111.60
NC
N Carolina
54
0
754
0
0.45
0.00
825
0.00
ND
N Dakota
0
0
0
0
0.00
0.00
0.00
0.00
OH
Ohio
118
10
1035
116
0.61
0.40
5.19
40.12
OK
Oklahoma
23
4
478
67
0.28
0.23
1227
5733
OR
Oregon
19
0
65
0
0.04
0.00
2.02
0.00
PA
Pennsylv.
124
20
2140
387
1.26
134
10.20
66.92
Rl
Rhode IsL
2
0
22
0
0.01
0.00
6.40
0.00
SC
S Carolina
21
3
257
97
0.15
033
735
111.60
TN
Tennessee
37
7
487
226
029
0.78
7.78
111.60
TX
Texas
114
20
993
329
0.59
1.14
5.15
5639
UT
Utah
0
4
0
66
0.00
0.23
0.00
57.06
VT
Vermont
0
0
0
0
0.00
0.00
030
0.00
VA
Virginia
31
5
250
92
0.15
032
4.76
63.63
WA
Washingto
33
5
134
63
0.08
022
2.41
43.58
WV
W Virginia
42
1
513
32
0.30
0.11
722
111.60
W1
Wisconsin
35
0
247
0
0.15
0.00
4.17
0.00
WY
Wyoming
0
0
0
0
0.00
0.00
0.00
0.00
1846 186 16324 4322 9.6S 14.95 * 5.23 8036
"includes emissions from calcining
K2Q23g
Dedston Focus Incorporated

-------
A-8 Detailed Industry Data
Volume 2: Choosing the Market Level for Trading
Table A-3
INDUSTRY CHARACTERISTICS (continued)
NitrJen	Plast.mat.	Inorg.	Nitr.tert. Plastmat Inorg. Nitr.ten PlasLmaL Inorg.
Value	Value	Value	C02 emss C02 emiss C02 emiss C02 emts/ C02 errw/ C02 emts/
STATE	0	«	# of shipm.	of shipm.	of shipm.	Unit Unit Unit
Nitr.fert. Plast.mat. Inorg. mill $	mill $	mill $	nun.t.C m.itU.C m.m.t.C th.m.t.C th.rru.C thmt.C
AL
Alabama
0
0
15
0
0
286
0.00
0.00
0.07
0.00
0.00
4.90
AK
Alaska
2
0
0
39
0
0
0.10
0.00
0.00
49.06
0.00
0.00
AZ
Arizona
0
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
AR
Arkansas
3
3
7
58
108
200
0.15
0.05
0.05
49.06
10.18
7.34
CA
Calif.
18
64
63
348
2875
533
0.88
0.90
0.14
49.06
12.71
2.17
CO
Colorado
0
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
CT
Connect.
0
11
5
0
494
143
0.00
0.14
0.04
0.00
12.71
7M
OE
Delaware
0
3
4
0
135
114
0.00
0.05
0.03
0.00
12.71
7J4
FL
Florida
0
10
17
0
449
54
0.00
0.15
0.01
0.00
12.71
0.82
GA
Georgia
5
13
36
97
381
424
02S
0.13
0.11
49.06
8.29
3.03
HA
Hawaii
0
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
ID
Idaho
0
0
3
0
0
441
0.00
0.00
0.11
0.00
0.00
37.78
tL
Illinois
0
33
29
0
1483
464
0.00
050
0.12
0.00
12.71
4.11
IN
Indiana
4
11
20
77
494
571
0.20
0.14
0.15
49.06
12.71
7J4
IA
Iowa
6
2
7
116
90
200
02S
0.05
0.05
49.06
12.71
7.34
KS
Kansas
5
0
6
97
0
171
0.25
0.00
0.04
49.06
0.00
7.34
KY
Kentucky
0
10
6
0
449
171
0.00
0.13
0.04
0.00
12.71
7.34
LA
Louisiana
8
16
32
546
2434
617
1.38
0.69
0.16
173.07
43.03
4.96
ME
Maine
0
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
MO
Maryland
0
0
9
0
0
169
0.00
0.00
0.04
0.00
0.00
4.83
MA
Massach.
0
15
11
0
674
314
0.00
0.19
0.08
0.00
12.71
7.34
Ml
Michigan
0
16
11
0
719
314
0.00
0.20
0.08
0.00
12.71
7.34
MN
Minnesota
0
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
MS
Mississip.
1
8
9
19
359 _
257
0.05
0.10
0.07
49.06
12.71
7.34
MO
Missouri
5
S
17
97
225
485
0.25
0.06
0.12
49.06
12.71
7.34
MT
Montana
0
0
5
0
0
66
0.00
0.00
0.02
0.00
0.00
3.39
NE
Nebraska
3
0
0
72
0
0
0.18
0.00
0.00
60.86
0.00
: 0.00
NV
Nevada
2
0
0
39
0
0
0.10
0.00
0.00
49.06
0.00
0.00
NH
NewHamp
0
3
0
0.
135
0
0.00
0.04
0.00
0.00
12.71
0.00
NJ
New Jerse
0
39
33
0
1752
714
0.00
0.55
0.18
0.00
12.71
5.56
NM
New Mexic
0
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
NY
New York
0
20
28
0
899
160
0.00
0.25
0.04
0.00
12.71
1.47
NC
N Carolina
0
13
17
0
584
380
0.00
0.19
0.10
0.00
12.71
5.74
NO
N Dakota
0
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
OH
Ohio
10
27
39
193
1213
1067
0.49
037
0.27
49.06
12.71
7.03
OK
Oklahoma
5
0
15
97
0
428
osts
0.00
0.11
49.06
0.00
7.34
on
Oregon
0
7
0
0
315
0
0.00
0.13
0.00
0.00
12.71
0.00
PA
Pennsylv.
9
26
46
49
1043
346
0.12
0.29
0.09
13.81
11.35
153
Rl
Rhode.IsL
0
0
4
0
0
114
0.00
0M
0.03
0.00
0.00
7.34
SC
S Carolina
0
7
8
0
315
228
0.00
0.11
0.06
0.00
12.71
7.34
SO
S Dakota
0
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00
TN
Tennessee
1
7
18
19
315
1554
0.05
0.09
0.40
49.06
12.71
22.19
TX
Texas
16
58
63
310
7678
985
0.78
2.17
0.25
49.06
37.44
4.02
UT
Utah
0
0
6
0
0
40
0.00
0.00
0.01
0.00
0.00
1.71
VA
Virginia
0
4
11
0
180
314
0.00
0.05
0.08
0.00
12.71
7.34
WA
Washingto
9
3
17
174
135
485
0.44
0.05
0.12
49.06
12.71
7.34
WV
W Virginia
0
0
6
0
0
171
0.00
0.00
0.04
0.00
0.00
7.34
Wl
Wisconsin
0
7
8
0
315
- 228
0.00
0.11
0.06
0.00
12.71
7.34
WY
Wyoming
0
0
0
0
0
0
0.00
0.00
0.00
0.00
0.00
0.00


112
441
631
2447
26246
13212
6
9
3
55.40
16.83
5.38
R2Q23g	Decision Focus Incorporated

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Volume 2: Choosing the Market Level for Trading
Detailed Industry Data A-9
Table A-3
INDUSTRY CHARACTERISTICS (continued)




Organic
Otherche
Organic
1
i
Organic
Other chem




Value
Value
C02 emtss C02 ermss C02 ems/ C02 emis/
STATE
#
#
ol shipm.
erf shipm.


Unit
Unit


Organic
Otherche
rrallS
mills
m.m.t.C
m.m.t.C
th.m.t.C
thm.t.C
AL
Alabama
IS
90
522
1853
0.32
0.28
21.00
3.10
AK
Alaska
0
0
0
0
0.00
0.00
0.00
0.00
AZ
Arizona
0
21
0
376
0.00
0.06
0.00
2.70
AR
Arkansas
8
22
279
226
0.17
0.03
21.00
155
CA
Call
58
862
2020
13351
1.22
2.01
21.00
2X4
CO
Colorado
0
24
0
510
0.00
0.08
0.00
320
CT
Connect.
13
75
453
1327
027
020
21.00
2.67
DE
Delaware
T
10
244
546
0.15
0.08
21X0
823
FL
Florida
13
308
453
5072
027
0.76
21.00
2.48
GA
Georgia
19
237
445
4253
027
0.64
14.12
2.71
HA
Hawaii
0
1
0
21
0.00
0.00
0.00
321
ID
Idaho
0
3
0
64
0.00
0.01
0X0
321
IL
llSnois
40
441
1587
5485
0.96
0.83
23X3
1X8
IN
Indiana
S
160
279
2435
0.17
0X7
21.00
¦>
!A
Iowa
5
98
174
2306
0.11
0.35
21.00
355
KS
Kansas
11
36
383
610
023
0.09
21X0
256
KY
Kentucky
10
84
348
1173
021
0.18
21.00
2.11
LA
Louisiana
29
72
6600
1751
338
0.26
13725
3.67
ME
Maine
0
2
0
67
0.00
0.01
0X0
5X2
MO
Maryland
3
93
104
1674
0.06
0.25
21.00
2.71
MA
Massach.
9
175
313
2819
0.19
0.43
21.00
2.43
Ml
Michigan
20
240
Q9w
3224
0.42
0.49
21.00
2.03
MN
Minnesota
0
88
0
1102
0.00
0.17
0X0
1X9
MS
Mississip.
6
15
209
394
0.13
0.06
21.00
3X6
MO
Missouri
17
209
592
3546
036
0.53
21X0
256
MT
Montana
0
0
0
0
0.00
0.00
0X0
0.00
NE
Nebraska
2
27
70
674
0.04
0.10
21X0
3.77
NV
Nevada
0
0
0
O
0.00
0.00
0X0
0.00
NH
NewHamp
2
5
70
32
0.04
0X0
21.00
0X6
NJ
New Jerse
77
516
2913
8691
1.76
1.31
22X1
2-54
NM
NewMexe
5
8
26
51
0.02
0.01
3.14
0X6
NY
New Yotk
38
428
754
8304
0.45
125
11X7
2.93
NC
N Carolina
21
153
731
4186
0.44
0.63
21.00
4.13
NO
N Dakota
0
24
0
523
0.00
0.08
0.00
329
OH
Ohio
43
421
965
6181
058
0.93
13.53
221
OK
Oklahoma
S
41
174
430
0.11
0.06
21.00
1X8
OR
Oregon
0
62
0
814
0.00
0.12
0.00
1X8
PA
Pennsylv.
23
365
692
5719
0.42
0.86
18.14
2X6
Rl
Rhode Isl.
0
22
0
34b
0.00
0.05
0X0
2X7
SC
S Carolina
18
71
627
3486
0.38
053
21.00
7.40
TN
Tennessee
13
152
1339
3298
0.81
0.50
62.11
327
TX
Texas
87
520
16595
8473
10.01
128
115X3
2.46
UT
Utah
0
24
0
315
0.00
0.05
0.00
1X8
VT
Vermont
0
2
0
18
0.00
Q.0Q
0.00
1X8
VA
Virginia
16
72
557
2S23
0.34
0.38
21.00
528
WA
Washingto
0
53
0
655
0.00
0.10
0.00
1X6
VW
W Virginia
15
26
522
536
0.32
0.08
21.00
3.11
W1
Wisconsin
13
139
453
1588
0.27
024
21.00
1.72
WY
Wyoming
0
11
0
161
0.00
0.02
0.00
221


669
6508
42189
111187
25
17
37.50
258
R2023g
Decision Focus Lncorpantted

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Appendix B
TOP TWENTY PRODUCERS IN SUPPLIER MARKETS
Tables B-l through B-6 show the top twenty U.S. producers for some of the industries
discussed in this document, including oil producers, natural gas producers, gas pipeline
companies, petroleum refineries, petroleum marketers, and coal producers.
Table B-1
TOP 20 OIL PRODUCERS, 198953
Company
Production
(1000 bbl/day)
Percent of
U.S. Production
Accumulated
Percent
BP America
784.0
8.5%
8.5%
Exxon
693.0
7.5%
16.0%
ARCO
660.0
7.2%
23.2%
Shell
494.0
5.4%
28.5%
Chevron
481.9
5.2%
33.8%
Texaco
479.5
5.2%
39.0%
Amoco
390.0
4.2%
43.2%
Mobil
293.2
3.2%
46.4%
Phillips
254.0
2.8%
49.1%
Unocal
165.0
1.8%
50.9%
Oryx Energy
143.8
1.6%
52.5%
USX
143.5
1.6%
54.0%
Occidental
135.0
1.5%
55.5%
DuPont
112.0
1.2%
56.7%
Amerada Hess
71.0
0.8%
57.5%
Union Pacific
63.8
0.7%
58.2%
City of Long Beach
53.9
0.6%
58.8%
Enron
53.3
0.6%
59.3%
Santa Fe Pacific
50.7
0.5%
59.9%
Valero Energy
43.7
0.5%
60.4%
U.S. TOTAL
9219.0
100.0%
100.0%
53. American Petroleum Institute, Basic Petroleum Data Book. Petroleum Industry Statistics, Vol. XI, No. 1,
Washington, D.C., 1991, Section IV, Table 7c.
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B-2 Top Twenty Producers in Supplier Markets	Volume 2: Choosing the Market Level for Trading
Table B-2
TOP 20 NATURAL GAS PRODUCERS, 198954
Company
Production
(bill cu. ft)
Percent of U.S.
Production
Accumulated
Percent
Chevron
880.7
5.1%
5.1%"
Amoco
756.3
4.4%
9.6%
Texaco
729.0
4.3%
13.8%
Exxon
666.9
3.9%
17.7%
Mobil
644.0
3.8%
21.5%
ARCO
558.1
3.3%
24.7%
Shell
532.1
3.1%
27.9%
USX
333.2
1.9%
29.8%
Phillips
319.0
1.9%
31.7%
Unocal
277.0
1.6%
33.3%
DuPont
273.8
1.6%
34.9%
Oryx Energy
269.7
1.6%
36.5%
Occidental
266.5
1.6%
38.0%
Union Pacific
153.3
0.9%
38.9%
Cons. Natural Gas
147.0
0.9%
39.8%
Anadarko
141.1
0.8%
40.6%
Mesa
137.2
0.8%
41.4%
Pennzoil
134.8
0.8%
42.2%
Enron
123.3
0.7%
42.9%
Amerada Hess
122.3
0.7%
43.6%
U.S. TOTAL
17115.0
100.0%
100.0%
54. Ibid., Section XIII, Table 12b.
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Volume 2: Choosing the Market Level for Trading	Top Twenty Producers in Supplier Markets B-3
Table B-3
TOP 20 GAS PIPELINE COMPANIES, 198855
Company
Sales Delivered
(bill. cu. ft)
Percent of U.S.
Production
Accumulated
Percent
Texas Eastern Trans. Corp.
679.0
10.6%
10.6%
Natural Gas PL of America
394.0
6.2%
22.3%
Enron Corp.
387.0
6.1%
28.4%
Tenneco Inc.
381.0
6.0%
41.5%
Columbia Gas Trans. Co.
353.0
5.5%
16.2%
Florida Gas Trans. Co.
236.0
3.7%
32.1%
Transco Inc.
234.0
3.7%
51.4%
CNG Transmission Co.
221.0
3.5%
35.6%
Texas Gas Trans. Co.
211.0
3.3%
47.8%
ANR Pipeline Co.
188.0
2.9%
44.5%
El Paso Natural Gas Co.
185.0
2.9%
59.2%
Trunkline Gas Co.
157.0
2.5%
56.3%
Southern Natural Gas Co.
153.0
2.4%
53.8%
Williams Natural Gas Co.
152.0
2.4%
61.6%
Colorado Interstate Gas Co.
114.0
1.8%
63.4%
Northwest Pipeline Co.
100.0
1.6%
68.3%
Transwestern Gas Pipeline
90.0
1.4%
64.8%
Panhandle Eastern Pipeline
51.0
0.8%
65.6%
United Gas Pipeline Co.
76.0
1.2%
66.8%
KN Energy Co.
31.0
0.5%
68.8%
U.S. TOTAL
6384.0
100.0%
100.0%
55. Energy Information Administration, Natural Gas Monthly, DOE/EIA-OISOOI/OS), Washington, D.C., March
1991, Table FE2; Oil & Gas Journal Special, Pipeline Economics, Tulsa, Oklahoma, November 27,1989, p. 66.
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B-4 Top Twenty Producers in Supplier Markets	Volume 2: Choosing the Market Level for Trading
Table B-4
TOP 20 REFINERIES, 198956
Company
Production
(1000 bbl/day)
Percent of U.S.
Production
Accumulated
Percent
Chevron
1621.0
10.7%
10.7%
Exxon
1147.0
7.6%
18.2%
Shell
1078.6
7.1%
25.3%
Amoco
956.0
6.3%
31.6%
Mobil
838.0
5.5%
37.1%
BP America
756.6
5.0%
42.1%
USX
603.0
4.0%
46.1%
Texaco
595.0
3.9%
50.0%
Sun
595.0
3.9%
53.9%
ARCO
559.0
3.7%
57.6%
DuPont
406.5
2.7%
60.3%
Ashland
346.5
2.3%
62.6%
Petroleos de Venezuela
344.5
2.3%
64.9%
Koch
310.0
2.0%
66.9%
Phillips
305.0
2.0%
68.9%
Coastal
302.8
2.0%
70.9%
Unocal
295.8
1.9%
72.8%
Aramco
295.0
1.9%
74.8%
Solomon
277.1
1.8%
76.6%
Total Petroleum
190.1
1.3%
77.9%
U.S. TOTAL
15183.6
100.0%
100.0%
56. American Petroleum Institute, op. cit.. Section VIII, Table 11c.
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Volume 2: Choosing the Market Level for Trading	Top Twenty Producers in Supplier Markets B-5
Table B-5
TOP 20 PETROLEUM MARKETERS, 197357
Percent of Accumulated
Company
U.S. Market
Percent
Texaco
8.0%
8.0%
Exxon
7.6%
15.6%
Shell
7.5%
23.1%
Indiana Standard
6.9%
30.0%
Gulf
6.8%
36.8%
Mobil
6.5%
43.3%
Socal
4.8%
48.1%
ARCO
4.4%
52.5%
Phillips
3.9%
56.4%
Sun
3.7%
60.1%
Union
3.1%
63.2%
Continental
2.3%
65.5%
Cities Service
1.7%
67.2%
Marathon
1.5%
68.7%
Ashland
1.5%
70.2%
Clark
1.3%
71.5%
Sohio
1.2%
72.7%
Hess
1.0%
73.7%
BP
0.8%
74.5%
Tenneco
0.8%
75.3%
U.S. TOTAL
100.0%
100.0%
57. Mitchell, Edward J., Vertical Integration in the OH Industry, published by American Enterprise for Public Policy
Research, Washington, D.C., 1976, Table 7.
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B-6 Top Twenty Producers in Supplier Markets	Volume 2: Choosing the Market Level for Trading
Table B-6
TOP 20 COAL COMPANIES, 1972s®
Company
Production
(mill short tons)
Percent of U.S.
Production
Accumulated
Percent
Peabody Coal Co.
71.6
12.1%
12.1%
Consolidation Coal
64.9
11.0%
23.1%
Island Creek Coal
22.6
3.8%
27.0%
Pittson Coal
20.6
3.5%
30.5%
Amax
16.4
2.8%
33.2%
U.S. Steel
16.3
2.8%
36.0%
Bethlehem Mines
13.3
2.3%
38.3%
Eastern Assoc. Coal Corp.
12.5
2.1%
40.4%
North American Coal Co.
12.0
2.0%
42.4%
Old Ben Coal Corp.
11.2
1.9%
44.3%
General Dynamics
10.0
1.7%
46.0%
Westmoreland Coal Co.
9.1
1.5%
47.5%
Pittsburgh & Midway
7.5
1.3%
48.8%
Utah International
6.9
1.2%
50.0%
American Electric Power
6.3
1.1%
51.1%
Western Energy Co.
5.5
0.9%
52.0%
Rochester & Pittsburgh
5.1
0.9%
52.8%
Valley Camp Coal
4.8
0.8%
53.7%
Zeigler Coal Co.
4.2
0.7%
54.4%
Midland Coal
3.9
0.7%
55.0%
U.S. TOTAL
590.0
100.0%
100.0%
58. Ibid., Table 10.
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Appendix C
CAR MANUFACTURERS IN A PERMIT TRADING
PROGRAM
This Appendix provides rough estimates of COj emissions for car manufacturers, based
on lifetime emissions from cars and trucks produced.
Lifetime C02 emissions for a particular car can be estimated based on fuel type used,
average fuel efficiency (MPG), expected lifetime, and expected mileage. This information
combined with each car producer's production volume makes it possible to estimate total COz
emissions that would accrue to each manufacturer. Table C-l provides rough emissions
estimates per car and truck over the vehicle's lifetime, annual total emissions from cars and
trucks, and average annual emissions per manufacturing plant.
Table C-1
C02 EMISSIONS FROM U.S. AUTOMOBILES
Fuel consumption Emissions *
(gallons) (tonnes carbon)
Lifetime emissions/car *' 5,200 10
Lifetime emissions/truck ** 14,300 26
Emissions/year cars and trucks, 1986 130 billion 238 million
Emissions/manufacturing plant/year, 1986 *" 23 million 43,000
Emissions calculations based on emissions factor for gasoline; 54,900 g CCy gigajoule (EPA, Policy Opttons
for Stabilizing Global Climate, Vol. 1, Washington, D.C., 1989, p. IV-21). Conversion factor from COz to
carbon; 12/44. Conversion from gallons of gasoline to gigajoule; multiply with 0.123 (U.S. Department of
Commerce, Energy Interrelationships. A Handbook of Table & Conversions Factors for Combining and
Comparing International Energy Data, Washington, D.C., 1977).
Assumptions: miles/year; cars 10k, trucks 14k. MPG; cars 19.3, trucks 9.8. Derived from Gas Research
Institute's Baseline Projection Data Book, Washington, D.C., 1990, p. 351-352. Lifetime of cars and trucks
here assumed to be 10 years.
Reduces annual emissions by 30% to account for imports of cars,59 and divides remaining emissions by
number of plants from Table 2-10; 3,867.
59. U.S. Department of Commerce, Bureau of the Census, Statistical Abstract of the United States 1988, Washington,
D.C., 1988, Table 992
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American Petroleum Institute, Basic Petroleum Data Book. Petroleum Industry Statistics, Vol. XI,
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R-2 References
Volume 2: Choosing the Market Level for Trading
Mitchell, Edward J., Vertical Integration in the Oil Industry, published by American Enterprise for
Public Policy Research, Washington, D.C., 1976.
Oil & Gas journal Special, Pipeline Economics, Tulsa, Oklahoma, November 27, 1989.
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Smith, A. E., A. R. Gjerde, and D. Cohan, Practical Considerations in Using Emissions Trading to
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Volume 2: Choosing the Market Level for Trading
References R-3
US. Department of Energy, Industry Profiles/Paper, Final Report Prepared by Energetics, Inc.,
Washington, D.C., December 1990.
U.S. Environmental Protection Agency, Polio/ Options for Stabilizing Global Climate, Vol. 1,
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