Air Pollution as a Commodity: Regulation of the Sulfur Dioxide Allowance Market

Order Code RL34235

Air Pollution as a Commodity: Regulation of the

Sulfur Dioxide Allowance Market

October 31, 2007

Larry Parker

Specialist in Energy and Environmental Policy

Resources, Science, and Industry Division

Mark Jickling

Specialist in Financial Economics

Government and Finance Division

Air Pollution as a Commodity: Regulation of the Sulfur

Dioxide Allowance Market

Summary

A number of congressional proposals to advance programs that reduce

greenhouse gases (GHGs) have been introduced in the 110th Congress. Proposals

receiving particular attention would create market-based GHG reduction programs

along the lines of the allowance trading provisions of the current acid rain reduction

program established by Title IV of the 1990 Clean Air Act Amendments. Under the

program, an allowance is limited authorization to emit a ton of pollutant.

However, there are several important differences. For example, the scope of the

greenhouse gases control program would be substantially greater than the Title IV

program, involving more covered sectors and entities. This diversity multiplies as the

global nature of the climate change issue is considered, along with the multiple

GHGs involved. Thus, a carbon market is likely to involve far greater numbers of

affected parties from diverse industries than the current Title IV program.

It will also involve far greater numbers of tradeable allowances than the current

Title IV program. Under the current program, about 9 million allowances are

allocated to over 2,000 emission sources annually. In contrast, a greenhouse gas

program that capped emissions in the electric power, transportation, and industry

sectors at their 1990 levels at some point in the future would be allocating about 4.85

billion allowances annually. Trading activities under Title IV has been increasing

since 2005. However, it doesn’t approach the anticipated volumes that would occur

if a greenhouse gas cap-and-trade program was instituted. Likewise, the economic

value of a future carbon market is likely to be substantially greater than the Title IV

program. Currently, the annual allocation of SO2 allowances has a market value of

about $4.5 billion. Using estimates of $15 to $25 an allowance, the annual allocation

of 4.85 billion allowances posited above for a greenhouse gas program would have

a market value of $72.8 billion to $121.3 billion.

Despite these differences in scope and magnitude, there are trends in Title IV

trading that are likely to continue in a carbon market. First, there is a trend toward

more diverse, non-traditional participants in the Title IV market. Like the Title IV

market, the economic importance of a carbon market will likely draw in entities not

directly affected by the reduction requirements, such as financial institutions. These

entities’ motivations may be equally diverse, including facilitating projects involving

the need for allowances, portfolio balancing, intermediary fees, and trading profits.

Second, as noted, there is a trend in the Title IV market toward using financial

instruments to manage allowance price risk. Given the greater economic stakes

involved in a carbon market, this trend toward more sophisticated financial

instruments is likely to emerge early as a hedge against price uncertainty. The

emergence of entities well-versed in the use of these instruments may reinforce the

trend and make options, collars, strangles, and other structures as common in the

allowance market as they are in other commodity markets. With a more liquid and

dynamic market, a carbon market may look more like other energy markets, such as

natural gas and oil, than the somewhat sedate SO2 allowance market.

Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Overview: Title IV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Administering the Program: The Environmental Protection Agency (EPA) . . . . . 4

Allowance Accounting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Allowance Auctions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Interface with Electricity Regulation: The Federal Energy Regulatory

Commission (FERC) and State Public Utility Commissions (PUCs) . . . . . . 5

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

FERC Allowance Accounting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

State Public Utility Commissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Allowance Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Internal Transfers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Over the Counter: Cash Market, Futures and Options . . . . . . . . . . . . . . . . . 11

Regulation of Allowances as an Exempt Commodity: Commodity Futures

Trading Commission (CFTC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Regulation of Trading Venues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

List of Tables

Table 1. Information Recorded by EPA’s Allowance Tracking System . . . . . . . . 4

Table 2. EPA Official Allowance Transfers and Transactions: 1994-2003 . . . . 11

Table 3. EPA 2007 Auction Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Table 4. SO2 Futures Contract Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Table 5. Summary of Trading Venues for Exempt

Commodities under the Commodity Exchange Act (CEA) . . . . . . . . . . . . . 17

Air Pollution as a Commodity: Regulation of

the Sulfur Dioxide Allowance Market

Introduction

A number of congressional proposals to advance programs that reduce

greenhouse gases have been introduced in the 110th Congress. Proposals receiving

particular attention would create market-based greenhouse gas reduction programs

along the lines of the trading provisions of the current acid rain reduction program

established by the 1990 Clean Air Act Amendments.1 These “cap-and-trade” schemes

would impose a ceiling (cap) on total annual emissions of greenhouse gases and

establish a market in pollution rights, called allowances, between affected entities.

An allowance would be a limited authorization by the government to emit one metric

ton of carbon dioxide equivalent (CO2e), and could be bought and sold (traded) or

held (banked) by participating parties.

These domestic proposals have parallels with the programs being implemented

in Europe to meet its obligations under the Kyoto Protocol. Specifically, the

European Union (EU) has decided to implement a cap-and-trade program, along with

other market-oriented mechanisms permitted under the Kyoto Protocol, to help it

achieve compliance at least cost.2 The EU’s decision to use emission trading to

implement the Kyoto Protocol is at least partly based on the successful emissions

trading program used by the United States to implement its sulfur dioxide (acid rain)

control program contained in Title IV of the 1990 Clean Act Amendments.3

These two operating cap-and-trade programs — the U.S.’s acid rain program

and the EU’s climate change program — may provide insights for the design of a

domestic greenhouse gas reduction scheme. However, while the experiences of the

EU system directly relate to the greenhouse gas reduction initiative of the domestic

legislative proposals, it has operated only a short time (see text box). The acid rain

control program has a longer operating history, although the control scheme differs

in some important ways — e.g., it is internal to one nation and involves fewer types

of sources.

1

P.L. 101-549, Title IV (November 15, 1990).

2

Norway, a non-EU country, also has instituted a CO2 trading system. Various other

countries and a state-sponsored regional initiative located in the northeastern United States

involving several states are developing mandatory cap-and-trade system programs, but are

not operating at the current time. For a review of these emerging programs, along with other

voluntary efforts, see International Energy Agency, Act Locally, Trade Globally (2005).

3

P.L. 101-549, Title IV (November 15, 1990).

CRS-2

Among the lessons that Phase 1 of

the European Trading System may have

for a similar U.S. program is that

allowance prices are linked to the price

of other energy commodities.4 Analysis

of ETS allowance prices during Phase 1

suggests the most important variables in

determining allowance price changes

have been oil and natural gas price

changes.5 This suggests that traders

will pursue arbitrage strategies

involving simultaneous transactions in

allowances and oil and gas contracts.

For example, a trader anticipating a rise

in the price of oil might take a position

in allowances in the expectation that the

two prices would move in tandem.

Since there is widespread suspicion that

excessive speculation by hedge funds

and others has affected energy prices in

recent years,6 the possibility that the

price of allowances could also be

subject to distortion or manipulation

will be a policy concern.

The EU’s Emissions Trading

System (ETS) covers more than 11,500

energy intensive facilities across the 27

EU Member countries, including oil

refineries, powerplants over 20 megawatts

(MW) in capacity, coke ovens, and iron

and steel plants, along with cement, glass,

lime, brick, ceramics, and pulp and paper

installations. Covered entities emit about

45% of the EU’s carbon dioxide

emissions. The trading program covers

neither CO2 emissions from the

transportation sector, which account for

about 25% of the EU’s total greenhouse

gas emissions, nor emissions of non-CO2

greenhouse gases, which account for about

20% of the EU’s total greenhouse gas

emissions. A “Phase 1” trading period

began January 1, 2005. A second, Phase

2, trading period is scheduled to begin in

2008, covering the period of the Kyoto

Protocol, with a third one planned for

2013. (For further background on the ETS

and its first year of operation, see CRS

Report RL33581, Climate Change: The

European Union’s Emissions Trading

System (EU-ETS), by Larry Parker.

Relevant directives on the EU-ETS are

available at [http://ec.europa.eu/environ

ment/climat/emission.htm#brochure].)

Taking that hint from ETS, this

report examines the Title IV sulfur

dioxide cap-and-trade program, with a

focus on the market activity and the

current regulatory overlay. From that

discussion, observations are drawn about implications for a future greenhouse gas

trading scheme. No current U.S. proposal has specific provisions with respect to

carbon allowance financial instruments or who would regulate such a market or its

participants.

Overview: Title IV

4

For more on the EU-ETS, see CRS Report RL34150, Climate Change: The EU Emissions

Trading Scheme (ETS) Gets Ready for Kyoto, by Larry Parker.

5

For example, when natural gas, the cleaner fuel, becomes more expensive relative to oil,

industrial users may switch to oil, creating increased demand for allowances. Maria

Mansanet-Bataller, Angel Pardo, and Enric Valor, “CO2 Prices, Energy and Weather,” 28

The Energy Journal 3 (2007), pp. 73-92. Powernext (a French energy exchange) has

described CO2 prices as the cornerstone of relative energy prices for generating electricity.

See Jean-Francois CONIL-LACOSTE, Chief Executive Officer, Powernext SA, Market

Based Mechanisms to Fight Climate Change (2006).

6

See, e.g., Senate Permanent Subcommittee on Investigations, “Excessive Speculation in

the Natural Gas Market” (Staff Report), June 2007, 135 p.

CRS-3

Title IV of the 1990 Clean Air Act Amendments supplements the sulfur dioxide

(SO2) command-and-control system of the Clean Air Act (CAA) by limiting total SO2

emissions from electric generating facilities to 8.95 million tons annually, beginning

in the year 2000.7 Title IV essentially caps SO2 emissions at individual utility sources

operating before enactment of the CAA in 1990 (known as “existing sources”)

through a tonnage limitation, and at those plants beginning operation after enactment

(known as “new sources”) through an emissions offset requirement. SO2 emissions

from most existing sources are capped at a specified emission rate times a historical

average fuel consumption level. Beginning January 1, 2000, SO2 emissions from

new plants commencing operation after enactment must be offset — in effect, the

emissions cap for new sources is zero. Their allowances come from emissions

reductions at existing facilities. The program was implemented through a two-phase

process with the final phase beginning in 2000.

To implement the SO2 reduction program, the law creates a comprehensive

permit and emissions allowance system (cap-and-trade program). An allowance is

a limited authorization to emit a ton of SO2 during or after a specified year. Issued

by EPA, the allowances are allocated to existing power plant units in accordance with

formulas delineated in the law. The owner of the facility receives the allowances for

a given plant regardless of the actual operation of the plant. For example, an owner

may choose to shut down an existing power plant and use those allowances to offset

emissions from two newer, cleaner facilities. As noted, generally, a power plant that

commences operation after enactment receives no allowances, requiring new units

to obtain allowances from those with allowances, or purchase them at an EPAsponsored auction, in order to operate after 2000. An owner may trade allowances

nationally as well as bank allowances for future use or sale.

If an affected unit does not have sufficient allowances to cover its emissions for

a given year, it is subject to an emission penalty of $2,000 (indexed to inflation) per

ton of excess SO2 , and it submits to EPA a plan for offsetting those excess emissions

in the next year (or longer if EPA approves). Further, EPA must deduct allowances

equal to the excess tonnage from the source’s allocation for the next year.

Another EPA responsibility is to provide for allowance auctions. For the post2000 period, the law sets aside a percentage of available allowances for auction.

Anyone may participate in these auctions as a buyer or seller, and those selling

allowances may specify a minimum sale price. EPA may delegate or contract the

conduct of the auctions to other agencies, such as to the Department of the Treasury,

or even to nongovernmental groups or organizations. Two streams of allowances are

sold in the auctions. The first stream represents “spot sales” of allowances that must

either be used in the year they are sold or banked for use in a later year. The second

stream represents “advance sales” of allowances that must either be used in the

seventh year after the year they are first offered for sale or be banked for use in a later

7

Clean Air Act Amendments of 1999, P.L. 101-549, Title IV. For a more detail discussion

of the title, see Larry B. Parker, Robert D. Poling, and John L. Moore, “Clean Air Act

Allowance Trading,” 21 Environmental Law 2021-2068 (1991).

CRS-4

year. For 2000 and thereafter, Title IV provides that 125,000 allowances be set-aside

annually for spot sales, and 125,000 for advance sales.

Administering the Program: The Environmental

Protection Agency (EPA)

It is EPA’s responsibility to administer the trading, banking, and auctioning of

allowances.

Allowance Accounting

EPA has developed an integrated system to track allowances (the Allowance

Tracking System — ATS);8 to verify and record SO2 emissions from affected units

(the Emission Tracking System — ETS); and to reconcile (true-up) allowances and

emissions at the end of the year. The Allowance Tracking System is the official

record of allowance transfers and balances used for compliance purposes. Each

participant in the system has an ATS account, and each account has an identification

number.

Table 1 identifies what the ATS tracks and does not track with respect to

allowance activity. As suggested, EPA primarily gathers information to ensure

compliance with the emission limitations of Title IV — the ATS is not a trading

platform. Participants are not required to record all transfers with EPA until the

affected allowances are to be used for compliance. Participants must notify EPA to

have any transfers recorded in the ATS. When parties agree on a transaction that

they want recorded on the ATS, they provide information on the buyer and seller and

the serial numbers of the affected allowances to the ATS which records the transfer.

Table 1. Information Recorded by EPA’s Allowance Tracking

System

ATS Records

ATS Does Not Record

Allowances issued

Allowance prices

Allowances held in each account

Option trades

Allowances held in various EPA reserves

Any allowance transaction not officially

reported to EPA

Allowances surrendered for compliance

purposes

Allowances transferred between accounts

8

EPA has renamed the ATS the Allowance Management System (AMS), but ATS remains

the commonly used term and will be used in this report.

CRS-5

To facilitate its primary compliance responsibility, EPA assigns each allowance

allocated a unique 12-digit serial number that incorporates the first year it can be used

for compliance purposes. These allowances may be held in one of two types of ATS

accounts. First, there are Unit Accounts where allowances provided under Title IV

allocation formulas are deposited and where allowances are removed by EPA for

compliance purposes. Second, there are General Accounts that may be created by

EPA for anyone wishing to hold, trade, or retire allowances. Participating entities

with General Accounts include (1) utilities who keep a pooled reserve of allowances

not needed immediately for compliance (i.e., an allowance bank); (2) brokers who

need a holding account for allowances in the process of being bought or sold; (3)

investors holding allowances for future sale; and (4) environmental and other groups

holding allowances they wish to remove from the market (i.e., retire).

Allowance Auctions

A key provision of Title IV to ensure liquidity in the SO2 markets for new

entrants is the EPA allowance auction. As noted above, the EPA is required to

auction 250,000 allowances annually in two streams, spot and advance. The auctions

began in 1993 and are held annually — usually on the last Monday in March. Sealed

bids entailing the number, type, and price, along with payment, are sent to EPA no

later than three business days before the auctions.

The auctions sell the allowances according to bid price, starting with the highest

bid and continuing down until all allowances are sold or there are no more bids.

Unlike allowances offered by private holders for auction, these EPA allowances do

not have a minimum price.

For the first 13 years, the auctions were conducted by the Chicago Board of

Trade (CBOT) for EPA. CBOT received no compensation for the service, nor was

it allowed to charge fees. Beginning in March 2006, CBOT decided to stop

administering the auctions, resulting in EPA now conducting them directly.

Interface with Electricity Regulation: The Federal

Energy Regulatory Commission (FERC) and State

Public Utility Commissions (PUCs)

Background

The 1990 Clean Air Act Amendments were enacted during a time of transition

in the electric utility industry. There are three components to electric power delivery:

generation, transmission, and distribution. Historically, electricity service was

defined as a natural monopoly, meaning that the industry had (1) an inherent

tendency toward declining long-term costs, (2) high threshold investment, and (3)

technological conditions that limited the number of potential entrants. In addition,

many regulators considered unified control of generation, transmission, and

distribution the most efficient means of providing service. As a result, most people

(about 75%) were served by vertically integrated, investor-owned utilities.

CRS-6

The Public Utility Holding Company Act (PUHCA)9 and the Federal Power Act

(FPA) of 1935 (Title I and Title II of the Public Utility Act)10 established a regime

for regulating electric utilities that gave specific and separate powers to the states and

the federal government. Essentially, a regulatory bargain was made between the

government and utilities. Under this bargain, utilities must provide electricity to all

users at reasonable, regulated rates in exchange for an exclusive franchise service

territory. State regulatory commissions address intrastate utility activities, including

wholesale and retail rate-making. Authorities of these commissions tend to be as

broad and varied as the states are diverse. At the least, a state public utility

commission will have authority over retail rates, and often over investment and debt.

At the other end of the spectrum, the state regulatory body will oversee many facets

of utility operation. Despite this diversity, the essential mission of the PUC is the

establishment of retail electric prices. This is accomplished through an adversarial

hearing process complete with attorneys, briefs, witnesses, etc. The central issues in

such cases are the total amount of money the utility will be permitted to collect

(revenue requirement) and how the burden of the revenue requirement will be

distributed among the various customer classes (rate structure).11 This is commonly

known as “rate of return” (ROR) regulation.

Under the regime set up by FPA, federal economic regulation addresses

wholesale transactions and rates for electric power flowing in interstate commerce.

Historically, federal regulation followed state regulation and is premised on the need

to fill the regulatory vacuum resulting from the constitutional inability of states to

regulate interstate commerce. In this bifurcation of regulatory jurisdiction, federal

regulation is limited and conceived to supplement state regulation. The Federal

Energy Regulatory Commission (FERC) has the principal functions at the federal

level for the economic regulation of the electricity utility industry, including financial

transactions, wholesale rate regulation, transactions involving transmission of

unbundled retail electricity, interconnection and wheeling of wholesale electricity,

and ensuring adequate and reliable service. In addition, until passage of the 2005

Energy Policy Act (EPACT05),12 the Securities and Exchange Commission (SEC)

regulated utilities’ corporate structure and business ventures under PUHCA to

prevent a recurrence of the abusive practices of the 1920s (e.g., cross-subsidization,

self-dealing, pyramiding, etc.).

This comprehensive, cost-based approached to regulation began to undergo

change in the 1970s and 1980s as passage of the Public Utility Regulatory Policies

9

15 U.S.C. 79 et seq.

10

16 U.S.C. 791 et seq.

11

For a comprehensive discussion of state and federal regulation, see Robert Poling, et. al.,

Electricity: A New Regulatory Order? Report for the Committee on Energy and Commerce,

House of Representative (June 1991), committee print.

12

P.L. 109-58.

CRS-7

Act of 1978 (PURPA)13 and the Fuel Use Act of 1978 (FUA)14 helped establish

independent electricity generators — electricity producers who sold at wholesale and

had no exclusive franchise area. Building on the perceived success of these

independent generators under PURPA, the Energy Policy Act of 1992 (EPACT92)

created a new category of wholesale electric generators called Exempt Wholesale

Generators (EWGs) that are not considered utilities and not regulated under

PUHCA.15 EWGs, also referred to as merchant generators, were intended to create

a competitive wholesale electric generation sector. EPACT92 effectively initiated

deregulated wholesale generation by creating a class of generators that were able to

locate beyond a typical service territory with open access to the existing transmission

system. EPACT05 continued this process by adding provisions to address system

reliability, repeal PUHCA, and modify PURPA.16

The current status of these initiatives and resulting state responses is a mixture

of states with traditional, comprehensive ROR regulation of electricity and those with

a restructured industry with segmented generation, transmission, and distribution

components. Over the past 20 years, some States have truncated their ROR regulation

to the extent they have chosen to restructure their industry in response to Federal

initiatives. In states that have not restructured, the system operates as it has since

enactment of the Federal Power Act, with retail consumers paying one price that

includes transmission, distribution, and generation. This is referred to as a bundled

transaction. In states that have restructured, consumers are billed for separate

transmission, distribution, and generation charges. This is referred to as unbundled

electricity service. In those states, retail consumers are allowed to choose their retail

generation supplier; however, few states actually have competitive markets for retail

choice (exceptions include Texas and Massachusetts). FERC regulates all

transmission, including unbundled retail transactions.17

13

P.L. 95-617, 16 U.S.C. 2601.

14

P.L. 95-620.

15

Exempt Wholesale Generators may sell electricity only at wholesale. EWGs may be

located anywhere, including foreign countries. Before enactment of EPACT05, utility

generators were limited by the Public Utility Holding Company Act of 1935 (PUHCA) to

operate within one state.

16

In repealing PUHCA, EPACT05 provides that FERC and state regulatory bodies must be

given access to utility books and records. Also, FERC is given approval authority over the

acquisition of securities and the merger, sale, lease, or disposition of facilities under FERC’s

jurisdiction with a value in excess of $10 million. With respect to PURPA, EPACT05

repeals the PURPA mandatory purchase requirement for new contracts if FERC finds that

a competitive electricity market exists and a qualifying facility has adequate access to

wholesale markets. Among its provisions to address reliability, FERC is authorized to certify

a national electric reliability organization (ERO) to enforce mandatory reliability standards

for the bulk power system. For more information on EPACT05, see CRS Report RL33248,

Energy Policy Act of 2005, P.L. 109-58, Electricity Provisions, by Amy Abel.

17

On October 3, 2001, the U.S. Supreme Court heard arguments in a case (New York et al.

v. Federal Energy Regulatory Commission) that challenged FERC’s authority to regulate

transmission for retail sales if a utility unbundles transmission from other retail charges. In

states that have opened their generation market to competition, unbundling occurs when

(continued...)

CRS-8

FERC Allowance Accounting

With the restructuring of the electric utility industry, FERC generally does not

set cost-based rates for electricity generation under its jurisdiction. Rather, FERC

conducts a two-pronged horizontal and vertical market power analysis to determine

an entity’s eligibility for “market-based” wholesale rates.18 If eligible, the entity may

set its wholesale prices according to market demand, not according to production

costs.

Because of the market-based nature of FERC wholesale rates, allowances are

an accounting issue, not a ratemaking issue for FERC. Electric public utilities and

licensees within FERC jurisdiction are required to maintain their books and records

in accordance with FERC’s Uniform System of Accounts (USofA).19 The USofA

guides the jurisdictional entity in understanding the information it needs to report on

various FERC forms. Included in the USofA are instructions on how to account for

allowances allocated to the entity under the 1990 Clean Air Act, or acquired by the

entity for speculative purposes. Allowances owned for other than speculative

purposes are accounted for at cost in either Account 158.1 (Allowance Inventory),

or Account 158.2 (Allowances Withheld) as appropriate. Allowances acquired for

speculative purposes are accounted for in Account 124 (Other Investments).20

By defining allowance value in terms of historic costs, allowances allocated by

EPA to entities are valued at zero. FERC does require that the records supporting

Account 158.1 and 158.2 be maintained “in sufficient detail so as to provide the

number of allowances and the related cost by vintage year.” Likewise, the Uniform

System of Accounts also provides instruction on accounting for gains and losses from

selling allowances.

17

(...continued)

customers are charged separately for generation, transmission, and distribution. Nine states,

led by New York, filed suit, arguing that the Federal Power Act gives FERC jurisdiction

over wholesale sales and interstate transmission and leaves all retail issues up to the state

utility commissions. Enron in an amicus brief argued that FERC clearly has jurisdiction

over all transmission and FERC is obligated to prevent transmission owners from

discriminating against those wishing to use the transmission lines. On March 4, 2002, the

U.S. Supreme Court ruled in favor of FERC and held that FERC has jurisdiction over

transmission, including unbundled retail transactions.

18

FERC Order 697, Market-Based Rates for Wholesale Sales of Electric Energy, Capacity

and Ancillary Services by Public Utilities, Docket No. RM04-7-000, Final Rule (issued June

21, 2007).

19

Code of Federal Regulations, Title 18, Conservation of Power and Water Resources, Part

101.

20

Code of Federal Regulations, Title 18, Conservation of Power and Water Resources, Part

101. Allowance accounting is described under General Instructions Number 21.

CRS-9

It should be noted that the Internal Revenue Service (IRS) also values

allowances allocated by EPA to an entity on a zero-cost basis.21

State Public Utility Commissions

In states with bundled rates, the valuing and disposition of allowances is more

than an accounting issue, it is also a ratemaking issue. During and after passage of

Title IV, there was substantial debate and studies were done on the role of the PUCs

in facilitating (or hindering) allowance trading.22 In Title IV, the regulatory treatment

of allowances is left to the appropriate state and federal regulatory bodies. Title IV

contains no mandated requirements regarding the treatment of allowance transactions

in state utility rate proceedings. Basically, Congress chose to leave the state

commissions free to apply any rate treatment they deem reasonable and appropriate.

The states responded in a diverse manner, some states issuing broad guidelines

on treatment of allowance transactions while others decided such events on a caseby-case basis. An analysis of the interaction between PUCs and the allowance

system made three general observations about the resulting PUC treatment of

allowances: (1) regulations tend to require 100% of both expenses and revenues from

allowances to be returned to ratepayers with net gains (losses) incurred used to offset

(or increase) fuel costs; (2) a few states have allowed utilities to retain some of the

profits as an incentive to sell excess allowances; (3) state regulations tend to be

tailored to a state’s specific circumstance — “allowance rich” states have regulations

encouraging sales, “allowance poor” states have regulations encouraging purchases.23

The focus of PUC decisions has not been to encourage allowance transactions, but

generally to ensure ratepayers and not shareholders receive the benefits of the

allowances. In some cases, PUCs have also used their authority to encourage utilities

to protect high-sulfur coal production, even if it is not the most cost-effective control

strategy.24

Allowance Transactions

Internal Transfers

When the 1990 Clean Air Act Amendments were enacted, about 75% of the

allowances were allocated to vertically integrated, ROR regulated entities. Today,

21

Treatment of emission allowances under the Federal income tax is spelled out in Rev. Rul.

92-16, Internal Revenue bulletin, No. 1992-12, March 23, 1992, p. 5 and Rev. Proc. 92-91,

Internal Revenue Bulletin, No. 1992-46, November 16, 1992-13, p. 32-33. See also,

Announcement 92-50, Internal Revenue bulletin, No. 1992-12, March 30, 1992, p. 32.

22

For example, see Kenneth Rose, et. al., Public Utility Implementation of The Clean Air

Act’s Allowance Trading Program, National Regulatory Research Institute, May 1992.

23

Elizabeth M Bailey, Allowance Trading Activity and State Regulatory Rulings: Evidence

from the U.S. Acid Rain Program, MIT, March 1998, pp. 9-10.

24

See Ken-Ichi Mizobuchi, The Movements of PUC Regulation Effects in the SO2 Emission

Allowance Market, Kobe University, May 2004.

CRS-10

that percentage has shifted with more allowances allocated to independent generating

entities as some utilities have divested themselves of their generating assets. This

diversification of ownership is reflected to some degree in the ATS statistics on

official transfers and transactions.25 As indicated by Table 2, in the first two years

of trading, transfers between economically unrelated entities were a small percentage

of total transfers. More recent data suggest that transfers between unrelated entities

account for about 50% of total transfers. However, it is clear that internal transfers

remain a major part of the allowance market, even in a restructured industry, and that

the total number of official transactions occurring is quite modest.

Internal transfers (i.e., transfers within or between economically related entities)

tend to be transacted in accordance with agreements that the utility and/or holding

company has filed with the appropriate state PUC, or FERC, or both.26

25

“Official” here means that the transfer has been recorded by the ATS. The actual transfer

of ownership may have occurred earlier. As noted earlier, parties are not required to notify

the ATS of any transfer within a specific time period and may choose for some reason to

delay informing the ATS of a transfer.

26

For example, see the now terminated agreement AEP System Interim Allowance

Agreement filed with the FERC on August 30, 1996 in Docket No ER96-2213-000

designated as Appalachian Power Company Supplement No. 9 to Rate Schedule FPC No.

20; Columbus Southern Power Company Supplement No. 3 to Rate Schedule FPC No. 30;

Indiana Michigan Power Company Supplement No. 10 to Rate Schedule FPC No. 17;

Kentucky Power Company Supplement No. 6 to Rate Schedule FPC No. 11; and, Ohio

Power Company Supplement No. 9 to Rate Schedule FPC No. 23. Agreement terminated

by FERC, effective January 1, 2002, in accordance with the mutual consent of the parties

thereto.

CRS-11

Table 2. EPA Official Allowance Transfers and Transactions: 1994-2003

Year

Total

Transfers

(millions of

allowances)

Transfers

between

economically

distinct

organizations

(millions of

allowances)

1994

9.2

0.9

9.8%

1995

16.7

1.9

1996

8.2

1997

Transactions

between

economically

distinct

organizations

Percent of

Total

Transactions

215

66

30.7%

11.4%

613

329

53.7%

4.4

53.7%

1,074

578

53.8%

15.2

7.9

52.0%

1,429

810

56.7%

1998

13.5

9.5

70.4%

1,584

942

59.5%

1999

18.7

6.2

33.2%

2,832

1,743

61.5%

2000

25.0

12.7

50.1%

4,690

2,889

61.6%

2001

22.5

12.6

56.0%

4,900

2,330

47.6%

2002

21.4

11.6

54.2%

5,755

2,841

49.4%

2003

16.5

8.1

49.1%

4,198

1,544

36.8%

2004

15.3

7.5

49.0%

20,000

n/a

n/a

2005

19.9

10.0

50.3%

5,700

n/a

n/a

Percent of

Total

Total

Number of

Transfers Transactions

Source: U.S. Environmental Protection Agency, 2007.

Over the Counter: Cash Market, Futures and Options

Beyond restructuring, other entities are emerging as participants in the

allowance markets. This increased diversity of interest in the allowance market is

reflected in the most recent (2007) EPA allowance auction. As indicated by Table

3, several brokerages have created positions in the allowance market, both for

themselves and their clients. This may suggest an increasing importance of

intermediaries to the functioning of the allowance market, the development of a more

liquid market, and to the maturing of that market.

CRS-12

Table 3. EPA 2007 Auction Results

(Winners of more than 20 allowances)

Spot Market Bid Winners

Quantity

Percent of Total

Allowances offered

(125,000)

Morgan Stanley

50,000

40.00%

KS&T, LP

30,575

24.46%

Saracen Energy LP

15,000

12.00%

Transalta Energy Marketing U.S.

9,900

7.92%

South Carolina Public Service Authority

7,500

6.00%

Alpha

5,000

4.00%

Constellation Energy Commodities Group,

Inc.

2,500

2.00%

Merrill Lynch Commodities Inc.

2,500

2.00%

The Detroit Edison Company

2,000

1.60%

124,975

99.98%

TOTAL SPOT

7 Year Advance Bid Winners

Quantity

Percent of Total

Allowances offered

(125,000)

American Electric Power

80,000

64.00%

DTE

30,000

24.00%

Cantor Fitzgerald Brokerage

10,000

8.00%

Bear Energy

4,986

3.99%

124,986

99.98%

TOTAL ADVANCE

Source: Environmental Protection Agency, 2007

The basic market for allowance trading is the Over-The-Counter (OTC) market.

The most common trading structure involves spot sales with immediate settlement

accounting and delivery into EPA’s Allowance Tracking System (ATS) with

payment by wire transfer in three business days.27 Daily spot trading volumes for

immediate settlement are estimated in the 10,000 to 25,000 ton range.28 Forward

27

Peter Zaborowsky, The Trailblazers of Emissions Trading, Evolution Markets Inc. (April

23, 2002).

28

Ibid. In September 2007, the monthly volume was estimated at 175,000-200,000 by

Evolution Markets Inc., who termed it low volume. Evolution Markets Inc., SO2 Markets

(continued...)

CRS-13

settlement transactions are less common and are fairly short-dated — 6 to 18 months

out. Vintage swaps also occur in both markets with the difference in value usually

paid in additional allowances rather than cash.29 This preference for allowances

reflects regulated entities’ desire to keep these transactions non-taxable under current

IRS regulations. Cash market transactions are facilitated in some cases through

available electronic trading platforms, such as Intercontinental Exchange, Inc. (ICE)

and TradeSpark (CantorCO2e), and by the emergence of a number of allowance

brokers. Currently, EPA lists a dozen allowance brokers on its website.30 A similar

list is available from the Environmental Markets Association — a trade association.31

Brokers tend to be registered with the SEC and one or more Self-Regulatory

Organizations, such as FINRA; but participation in this market would not in itself

make a firm subject to SEC regulation. Four brokers — Cantor Fitzgerald,

Evolution, ICAP Energy, and TFS Energy — form the basis of the Platts emission

price index. Argus AIR Daily also produces price indices through daily phone

surveys of active brokers.

Two exchanges provide SO2 future contracts as well as clearing services: New

York Mercantile Exchange (NYMEX) and Chicago Climate Futures Exchange

(CCFE). The availability of exchanges as a trading platform for allowances or to

clear transactions was cheered by traders when established in late 2004 and 2005.

As stated by the Environmental Markets Association with respect to NYMEX’s

decision: “NYMEX does offer information on power, and any time you have them

expanding into our market, that’s going to create opportunities for people who may

be using other products to take a second look at emissions.”32 Both exchanges offer

standardized and cleared futures contracts, along with clearing services for offexchange transactions. As reported by Platts, futures volume on both exchanges

have expanded greatly over the past year. SO2 futures trading on the CCFE was

nearly 1.9 million allowances in the first half of 2007, compared with about 500,000

during the same time in 2006. For the NYMEX, volumes in the first half of 2007

was 665,000 allowances — a more than three-fold increase over the first half of

2006.33 Table 4 summarizes the basic features of the trading instruments.

28

(...continued)

— September 2007 at [http://www.evomarkets.com/assets/mmu/mmu_so2_sep_07.pdf].

29

The first year an allowance may be used for compliance is called its “vintage.” This

situation can result in entities engaging in a “vintage swap.” For example, a “vintage swap”

may occur because one entity has excess allowances in the upcoming year (2008) but

anticipates it will have insufficient allowances in 2009. Another entity may be in the

opposite position because of planning future emission reductions. The two entities agree

to “swap” allowances to improve their allowance streams over these years.

30

EPA Website: [http://www.epa.gov/airmarkets/trading/buying.html].

31

EMA Website: [http://www.environmentalmarkets.org/page.ww?section=About+

Us&name=Company+Directory].

32

Comment of Matt Most, Emissions Market Association, as reported in Platts Emissions

Daily, “Emissions market hails NYMEX move,” February 15, 2005, p. 1.

33

Platts Emissions Daily, “Emissions exchanges continue to grow SO2, NOx futures

markets,” August 10, 2007, p. 1.

CRS-14

Table 4. SO2 Futures Contract Specifications

NYMEX

CCFE

Trading Platform

ClearPort

ICE

Clearing Organization

NYMEX ClearPort

Clearing

The Clearing Corporation

(CCorp)

Self Regulatory

Organization

NYMEX and National

Futures Association

(NFA)

National Futures

Association (NFA)

CFTC Regulatory Status

Designated Contract

Market

Designated Contract

Market

Contract size

100 SO2 allowances

25 SO2 allowances

Minimum Price

Fluctuation

$25 per contract

$2.50 per contract

Settlement

Physical through EPA’s

ATS

Physical through EPA’s

ATS

Symbol

RS

SFI

Source: NYMEX and CCFE.

In April, 2007, the CCFE began offering SO2 options.34 For October 2007, the

CCFE offers European-style options35 on its futures contracts for expiration on the

October 2007, November 2007, December 2007, April 2008, and December 2008

futures contracts.36 As with the futures market, participants are required to settle their

delivery obligations via the ATS. Volume remains light with the CCFE reporting

in July that there were 200 calls on July contracts, 5,315 calls and 411 puts on August

2007 contracts, 740 calls and 46 puts on September 2007 contracts, and 440 calls on

the December 2007 contracts.37 The spike in calls and puts in the August 2007

contracts in July may reflect a peak in allowance prices that occurred in July 2007

and future uncertainty about allowance price direction over the summer.38 The

NYMEX does not offer SO2 options.

34

Chicago Climate Futures Exchange, Chicago Climate Futures Exchange to Launch

Options market on Sulfur Financial Instrument Futures Contracts, Chicago, April 5, 2007.

35

An option that can only be exercised for a short, specified period of time just prior to its

expiration, usually a single day. “American” options, however, may be exercised at any time

before expiration.

36

For current options market data, see [http://www.ccfe.com/mktdata_ccfe/sfi_options.jsf].

37

CCFE Market Report, CCFE SFI Options, (July 2007), p. 3, table 4.

38

Traditional Financial Services (a brokerage firm) noted the peak in allowance prices in

July because of higher than expected storage in the natural gas markets. See TFS, Global

Environmental Markets, August 2007, available at [http://www.tfsbrokers.com/pdf/

global-reports/2007/tfs-ger-08-07.pdf].

CRS-15

Regulation of Allowances as an Exempt

Commodity: Commodity Futures Trading

Commission (CFTC)

Definition

The Commodity Exchange Act provides the basis for federal regulation of

“derivative” transactions in contracts based on commodity prices. Pursuant to the

act, the Commodity Futures Trading Commission (CFTC) regulates the futures

exchanges, such as NYMEX, and certain other derivative transactions that occur offexchange. The CFTC’s authority varies according to the identities of the market

participants and the nature of the underlying commodity. In general, the CFTC does

not regulate spot (or cash) trades in commodities, or forward contracts that will be

settled by delivery of the physical commodity (which are also considered cash

sales).39

In terms of allowances, the CFTC’s jurisdiction is confined to trades that take

place on those markets it regulates. It has no jurisdiction over spot trades in

allowances, full jurisdiction over futures and options trades on regulated exchanges,

and limited jurisdiction over derivatives trades on certain other markets subject to

lighter regulation than the exchanges.

Allowances are regulated by the CFTC as exempt commodities under the

Commodity Futures Modernization Act of 2000.40 The Commodity Exchange Act

defines an exempt commodity as any commodity other than an excluded commodity

(e.g., financial indices, etc.) or an agricultural commodity. Examples include energy

commodities and metals. Emission allowances are related to energy production. This

designation has been supported by other federal entities. In a 2005 Interpretive Letter

approving physically settled emission derivatives transactions, the Office of the

Comptroller of the Currency, Administrator of National Banks, states that physical

settlement of emission allowances do not pose the same risk as other physical

commodities:

The proposed emissions derivatives transactions [e.g., futures, forwards, options,

swaps, caps, and floors] will be linked to three emission allowance markets: the

U.S. SO2 (Sulfur Dioxide) and NOx (Nitrogen Oxide) markets and the European

Union’s CO2 (carbon dioxide) market. These emissions markets are volatile and

price fluctuates considerably. Market participants manage price risk through the

use of derivative structures, such as forwards, futures, options, caps and floors.

These derivatives are generally physically settled, because the current emissions

market is primarily physical in nature. ...

39

The CFTC has occasionally brought enforcement actions for fraud in the spot market, but

these are rare. The legislative history does not suggest that Congress meant the CFTC to be

a regulator of cash commodity markets.

40

See CFTC approval of CCFE application for designation as a Contract Market: Order of

Designation: In the Matter of the Application of the Chicago Climate Futures Exchange,

LLC for Designation as a Contract Market, November 9, 2004.

CRS-16

The OCC has previously concluded in a variety of contexts that national banks

may engage in customer-driven commodity transactions and hedges that are

physically settled, cash-settled and settled by transitory title transfer. ...

Similarly, the OCC permitted a national bank to make and take physical delivery

of commodities in connection with transactions to hedge commodity price risk

in commodity linked transactions. ...

In these decisions, the approved activities were subject to a number of conditions

due to risks associated with physical transactions in certain commodities. Those

risks included storage (e.g., storage tanks, pipelines), transportation (e.g., tankers,

barges, pipelines), environmental (e.g., pollution, fumigation, leakage,

contamination) and insurance (e.g., damage to persons and property, contract

breach, spillage). Physical settlement of emissions derivatives and hedging with

physicals would not pose those risks, however. Emission allowances are not

tangible physical commodities, such as electricity or natural gas. Rather, they are

intangible rights or authorizations. They can be bought and sold like other

commodities, but they exist only as a book entry in an emissions account.41

[footnotes omitted]

The Federal Reserve also considers emission allowances as commodities for

purposes of trading.42

Regulation of Trading Venues

The CFTC identifies four venues for trading exempt commodities under the

Commodity Exchange Act: (1) Designated Contract Markets (DCM), (2)

Commercial Derivatives Transaction Execution Facilities [none currently in

operation], (3) Exempt Commercial Markets (ECM), and (4) Over-the-Counter

(OTC) — not on a trading facility.43 As suggested by the discussion above,

allowances are traded on three of these venues. Futures contracts and clearing

services are provided by NYMEX and CCFE — both DCMs — with options also

available on the CCFE. ICE and TradeSpark — both ECMs — are used by brokers

and principals for allowance transactions. Finally, principal-to-principal transactions

and broker-assisted transactions are occurring OTC without the use of a trading

facility. Table 5 summarizes these venues and their regulation under the Commodity

Exchange Act.

For the three trading venues set out in Table 5, the degree of regulation varies,

most significantly according to the identities of the participants. Small public

investors are allowed to trade only on regulated exchanges (DCMs); these are subject

to extensive self-regulation and CFTC oversight. Electronic trading facilities, where

41

Comptroller of the Currency, Administrator of National Banks, Interpretive Letter #1040:

Emissions Derivatives Proposal, September 15, 2005.

42

Board of Governors, Federal Reserve System, JPMorgan Chase & C. New York, New

York: Order Approving Notice to Engage in Activities Complementary to a Financial

Activity, November 18, 2005.

43

See table entitled: Venues for the Trading of Exempt Commodities under the Commodity

Exchange Act (CEA), available on the CFTC website at [http://www.cftc.gov/stellent/

groups/public/@newsroom/documents/file/exemptcommoditiesvenues_091207.pdf].

CRS-17

small traders are not present, are subject to much less regulation, because traders are

assumed to be capable of protecting themselves from fraud. However, if an

electronic trading facility plays a significant price discovery role (that is, if the prices

it generates are used as reference points by the cash market or other derivatives

markets), the CFTC may require disclosure of certain information about trading

volumes, prices, etc. Where trades are purely bilateral, negotiated, and executed

between principals, the transaction is said to occur in the OTC market, which is

entirely exempt for CFTC regulation, with the exception of certain provisions dealing

with fraud manipulation.

Table 5. Summary of Trading Venues for Exempt Commodities

under the Commodity Exchange Act (CEA)

Designated

Contract Markets

(CEA Sec. 5)

Exempt

Commercial

Markets (CEA

Sec. 2(h)(3)-(5))

OTC — Not on a

Trading Facility

(CEA Sec. 2(h)(1)(2))

Commodities

Permitted

No limitations

Exempt

commodities (e.g.,

energy metals,

chemicals,

emission

allowances, etc.,)

Exempt

commodities (e.g.,

energy metals,

chemicals,

emission

allowances, etc.,)

Method of Trading

Trading can take

place on an

electronic trading

facility or by open

outcry

Electronic multilateral trading (i.e.,

many-to-many

platforms)

Non-multi-lateral

trading (e.g., dealer

markets;

individuallynegotiated,

bilateral

transactions)

Notice

Requirement

Must apply to and

receive prior

approval from

CFTC; must satisfy

various nonprescriptive

designation criteria

and core principles

Yes; simple notice

containing contact

information and

description of

operations

None; exemption is

self-executing

Participants

No limitations

Eligible

Commercial

Entities only —

subset of Eligible

Contract

Participants;

excludes

individuals but

includes funds

Eligible Contract

Participants (i.e.,

institutions, finds,

and wealthy,

sophisticated

individuals)

CRS-18

Designated

Contract Markets

(CEA Sec. 5)

Exempt

Commercial

Markets (CEA

Sec. 2(h)(3)-(5))

OTC — Not on a

Trading Facility

(CEA Sec. 2(h)(1)(2))

Intermediation

Permitted

None; principal-toprincipal trading

only

Limited; only if

done through

another Eligible

Contract

Participant

Types of

Transactions

Futures and

options

Derivatives,

including swaps,

futures and options

(Note: ECMs often

also trade products

outside CFTC

jurisdiction,

including spot and

forward contracts)

Derivatives,

including swaps,

futures, and

options

Standardized

Products?

Yes

Yes, terms set by

the entity

Usually yes when

executed on a

dealer market.

Usually no, when

executed

bilaterally

Cleared?

Transactions must

be cleared through

a Derivatives

Clearing

Organization

(DCO) approved

by the CFTC

Clearing not

mandatory; if

offered, it must be

through an SECregistered clearing

agency or a DCO

(many ICE

transactions are

cleared at LCH;

other ECMs offer

clearing at

NYMEX Clearport

or The Clearing

Corp.)

Can be if a

standardized

contract; many

traders choose to

clear trades at

NYMEX or LCH

Transaction

Prohibitions

Subject to all

provisions of the

CEA

Only antimanipulation and

anti-fraud

Only antimanipulation and

anti-fraud (but

anti-fraud rules do

not apply to

transactions

between Eligible

Commercial

Entities)

CRS-19

Designated

Contract Markets

(CEA Sec. 5)

Exempt

Commercial

Markets (CEA

Sec. 2(h)(3)-(5))

OTC — Not on a

Trading Facility

(CEA Sec. 2(h)(1)(2))

Self-regulatory

responsibility

Yes, significant

self-regulatory

responsibilities;

must comply on a

ongoing basis with

8 designation

criteria and 18 core

principles. Must

have compliance

and surveillance

programs

Minimal and they

include nothing

that goes to the

integrity of trading.

Responsibilities

include a reporting

requirement for

contracts over a

minimum volume

threshold; ensuring

compliance with

exemption

conditions; and

dissemination of

contract activity

information for

“price discovery”

contracts

None

Responsibility to

CFTC

Comply with

designation criteria

and core principles

Provide notice of

operation and

weekly transaction

data for highvolume contracts;

report

manipulations and

fraud complaints;

maintain and

provide access to

records of activity

None

CRS-20

Designated

Contract Markets

(CEA Sec. 5)

CFTC Oversight

Authority

Unlimited,

including

continuous and

ongoing market

surveillance and

trade practice

programs, ability to

intervene in

markets (e.g., force

reduction/liquidati

ons of position,

alter/supplement

DCM rules).

CFTC receives

large trader reports

transaction data

and assesses

DCMs’ compliance

programs via rule

enforcement

reviews.

Exempt

Commercial

Markets (CEA

Sec. 2(h)(3)-(5))

OTC — Not on a

Trading Facility

(CEA Sec. 2(h)(1)(2))

Limited (special

calls); Sec 8a(9)

emergency

authority does not

apply

None

Source: Venues for the Trading of Exempt Commodities under the Commodity Exchange Act (CEA),

available on the CFTC website at [http://www.cftc.gov/stellent/groups/public/@newsroom/documents/

file/exemptcommoditiesvenues_091207.pdf].

Although allowances are regulated like any other commodity by the CFTC, it

should be noted that it is not a deep liquid cash market. As noted by emissions

broker Evolution Markets LLC, the affected source base for SO2 allowances is about

500 companies. The broker also estimated in 2005 that about 20 companies

represented the bulk of trading activities.44 In recommending CFTC approval of the

CCFE as a DCM, the Staff memorandum noted the following:

In futures markets generally, the existence of a liquid market for a particular

contract and the ability of an FCM to liquidate positions therein which it may

inherit from a defaulting customer are important to the financial integrity of such

an FCM and, in turn, its ability to fulfill its obligations to other customers and

to the clearing system. The EPA will facilitate the delivery process of these

contracts in a manner that makes cash positions known and compensates for any

current lack of a developed deep liquid cash market for the contracts as compared

to other futures contracts. Collectively CCorp, NFA, and EPA will carry out

financial surveillance, monitor situations, and provide information the effect of

44

Evolution Markets LLC, “An Overview of Trading Activity and Structures in the U.S.

Emissions Markets,” NYMEX Emissions Futures Seminar, July 28, 2005.

CRS-21

which should counterbalance any disparate effects on financial integrity, which

might be imposed by the initial lack of trading history and prices.45

Observations

Despite the tendency to view the Title IV program as a model for a future

greenhouse gas reduction scheme, there are several important differences. For

example, the Title IV program involves up to 3,000 new and existing electric

generating facilities that contribute two-thirds of the country’s SO2 and one-third of

its nitrogen oxide (NOx) emissions (the two primary precursors of acid rain). This

concentration of sources makes the logistics of allowance trading administratively

manageable and enforceable with continuous emissions monitors (CEMs) providing

real time data. However, greenhouse gas emissions are not so concentrated. In 2005,

the electric power industry accounted for about 33% of the country’s GHG

emissions, while the transportation section accounted for about 28%, industrial use

about 19%, agriculture about 8%, commercial use about 6%, and residential use

about 5%.46 Thus, small dispersed sources in transportation, residential/commercial

and agricultural sectors, along with industry, are far more important in controlling

GHG emissions than they are in controlling SO2 emissions. This diversity multiplies

as the global nature of the climate change issue is considered, along with the multiple

GHGs involved.47 Thus, a carbon market is like to involve far greater numbers of

affected parties from diverse industries than the current Title IV program.

It will also involve far greater numbers of tradeable allowances than the current

Title IV program. Under the current program, about 9 million allowances are

allocated to participating entities annually. In contrast, a greenhouse gas program

that capped emissions in the electric power, transportation, and industry sectors at

their 1990 levels at some point in the future would be allocating about 4.85 billion

allowances annually. This is a two and a half orders-of-magnitude increase over the

Title IV program and double the Phase 2 allocations under the ETS. As suggested

here, trading activities under Title IV has been increasing since 2005. However, it

doesn’t approach the anticipated volumes that would occur if a greenhouse gas capand-trade program was instituted.

Finally, the economic value of a future carbon market is likely to be

substantially greater than the Title IV program. With EPA’s pending implementation

of the Clean Air Interstate Rule (CAIR), the price of a Title IV allowance has

45

The Division of Market Oversight and The Division of Clearing and Intermediary

Oversight, CFTC, DCM Designation Memorandum: Application of Chicago Climate

Futures Exchange, LLC (“CCFE”) for Designation as a Contract Market pursuant to

Sections 5 and 6(a) of the Commodity Exchange Act (“Act” or “CEA”) and Part 38 of

Commission regulations, November 3, 2004.

46

U.S. territories account for the remaining 1%. Data from EPA, Inventory of U.S.

Greenhouse Gas Emissions and Sinks: 1990-2005, April 15, 2007, p. ES-14.

47

The EU addresses this issue by having the ETS cover only 45% of its emissions and no

non-carbon dioxide emissions, as noted earlier. Still, it has 11,500 entities to oversee.

CRS-22

increased to about $500.48 Thus, the annual allocation of SO2 allowances has a

market value of about $4.5 billion. Using estimates of $15 to $25 an allowance, the

annual allocation of 4.85 billion allowances posited above for a greenhouse gas

program would have a market value of $72.8 billion to $121.3 billion.49 Unlike the

Title IV market, a carbon market may be quite liquid.

Despite these differences in scope and magnitude, there are trends in Title IV

trading that are likely to continue in a carbon market.

First, there is a trend toward more diverse, non-traditional participants in the

Title IV market. Like the Title IV market, the economic importance of a carbon

market will likely draw in entities not directly affected by the reduction requirements,

such as financial institutions. The motivations of these entities may be equally

diverse, including facilitating projects involving the need for allowances, portfolio

balancing, and profits earned through intermediary fees or proprietary trading.

Second, there is trend in the Title IV market toward using financial instruments

to manage allowance price risk. This trend is partly the result of the regulatory

uncertainty introduced in the allowance market by CAIR. Given the greater

economic stakes involved in a carbon market, this trend toward more sophisticated

financial instruments is likely to emerge early as a hedge against price uncertainty.

The emergence of entities well-versed in the use of these instruments may reinforce

the trend and make options, collars, strangles, and other structures as common in the

allowance market as they are in other commodity markets. With a more liquid and

dynamic market, a carbon market may look more like other energy markets, such as

natural gas and oil, than the somewhat sedate SO2 allowance market.

48

49

Based on data from Cantor Fitzgerald, October 2007.

Range based on EPA estimates for reducing emissions to 1990 levels by 2020 as required

under S. 280. See EPA, Analysis of The Climate Stewardship and Innovation Act of 2007,

July 16, 2007. For reference, a Phase 2 ETS allowance currently sells for about $32 . Data

from the European Climate Exchange, [http://www.ecxeurope.com/default_flash.asp].