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Journal of Environmental Economics and Management 88 (2018) 180–209
Contents lists available at ScienceDirect
Journal of
Environmental Economics and Management
journal homepage: www.elsevier.com/locate/jeem
The impact of trading on the costs and benefits of the Acid
Rain Program$
H. Ron Chan a, B. Andrew Chupp b, Maureen L. Cropper c,n, Nicholas Z. Muller d
a
University of Manchester, UK
Georgia Institute of Technology, USA
Department of Economics, University of Maryland, Resources for the Future, 3114H Tydings Hall, College Park, MD 20742, USA
d
Carnegie Mellon University, USA
b
c
a r t i c l e in f o
abstract
Article history:
Received 30 March 2017
Available online 8 December 2017
We quantify the cost savings from the Acid Rain Program (ARP) by comparing compliance
costs for 761 coal-fired generating units under the ARP with compliance costs under a
counterfactual uniform performance standard (UPS) that would have achieved the same
aggregate emissions in 2002. In 2002, we find compliance costs to be $200 million (1995$)
lower and health damages to be $170 million (1995$) lower under the ARP. We also
compare health damages associated with observed SO2 emissions from all ARP units in
2002 with damages from a no-trade counterfactual. Damages under the ARP are $2.1
billion (1995$) higher than under the no-trade scenario, reflecting allowance transfers
from units in the western US to units in the eastern US with larger exposed populations.
& 2017 Elsevier Inc. All rights reserved.
JEL nos:
Q51
Q52
Q58
Keywords:
Sulfur dioxide
Acid rain
Performance standards
Health effects
Pollution permits
Cap and trade
Introduction
Motivation
The U.S. Acid Rain Program (ARP), enacted under Title IV of the 1990 Clean Air Act Amendments, is widely cited as an
example of a successful cap and trade program—one that achieved huge reductions in sulfur dioxide (SO2) emissions from
US coal-fired power plants at a lower cost than a comparable command-and-control regulation (Ellerman et al., 2000;
Stavins, 1998; Schmalensee and Stavins, 2013). Ex ante studies of the cost savings from allowance trading predicted large
cost savings from the program compared with a uniform performance standard, especially in Phase II of the program. Phase
I of the ARP, between 1995 and 1999, required the dirtiest 110 coal-fired power plants to reduce their emissions. Beginning

Support for this work was provided by Resources for the Future. This paper has benefited from comments made by seminar participants at Carnegie
Mellon University, the University of Pennsylvania, RFF, the Association of Environmental and Resource Economists, Georgia State University, the School of
Public and Environmental Affairs at Indiana University, the Econometric Society World Congress in Montreal, the Royal Economic Society Conference in
Manchester and the UK Applied Environmental Economics Conference.
We thank Dallas Burtraw, Dick Morgenstern and 3 anonymous referees for their comments.
n
Corresponding author.
E-mail address: [email protected] (M.L. Cropper).
https://doi.org/10.1016/j.jeem.2017.11.004
0095-0696/& 2017 Elsevier Inc. All rights reserved.
H.R. Chan et al. / Journal of Environmental Economics and Management 88 (2018) 180–209
181
in 2000, all electricity generating units (EGUs) greater than 25 MW (MW) were regulated by the ARP. Ex ante studies of the
cost savings from emissions trading predicted much larger cost savings in Phase II of the program, in which all EGUs would
participate, than in Phase I. Carlson et al. (2000) predicted cost savings from trading in Phase I of $250 million annually and
Ellerman et al. (2000) savings of $360 million (1995$) annually compared with a uniform performance standard. In contrast,
annual Phase II savings were predicted to be $784 million (Carlson et al., 2000) and $1.92 billion (Ellerman et al., 2000).1
Were these cost savings realized? There are several studies of Phase I of the ARP which suggest that this was not the case
during the early years of the program. Carlson et al. (2000) estimate that actual compliance costs in 1995 and 1996 were
slightly higher than they would have been under a uniform performance standard. Swinton (2002, 2004) shows that
marginal abatement costs were not equalized across Phase I EGUs, suggesting that the least-cost solution was not achieved.
Arimura (2002) finds that uncertainty in regulation led utilities to focus on fuel-switching and blending rather than depending on the allowance market, thus lowering potential cost savings.
An important question is what cost savings were realized once the program was fully operational—i.e., during Phase II of
the program. Reductions in compliance costs are a key reason for replacing a command-and-control regulation by a capand-trade system. It is, therefore, important, that cost savings be documented. There is, however, no econometric study of
the cost savings achieved by the ARP once the program was fully operational that is based on actual compliance data.
Studies of the cost savings delivered by the ARP in Phase II are ex ante in nature (Carlson et al., 2000; Ellerman et al., 2000).
Carlson et al. (2000) project cost savings based on marginal abatement cost (MAC) functions estimated using pre-ARP
(1985–94) data. Their MAC functions capture the cost of reducing SO2 emissions only through fuel switching (i.e., substituting low- for high-sulfur coal), not through the installation of flue-gas desulfurization units (scrubbers). In calculating
the gains from trade, Carlson et al. assume that no additional scrubbers will be built after 1995. They estimate the long-run
cost savings from the ARP, compared with a uniform performance standard, by assuming that the ARP will achieve the leastcost solution to the SO2 cap. There is, however, no guarantee that allowance trading achieved the least-cost abatement
solution. One goal of our paper is to estimate the cost savings associated with allowance trading during Phase II of the ARP
compared with an equally stringent uniform performance standard.
There are also concerns that health damages under the ARP were higher than they would have been under a uniform
performance standard (Henry et al., 2011). The reason is that, compared with a uniform standard, trading shifted emissions
from low marginal abatement cost plants (sellers of permits) located in sparsely populated areas west of the Mississippi
River to plants in more densely populated areas east of the Mississippi River (buyers of permits). This is supported by the
map in Fig. 1, in which we estimate the difference in 2002 between PM2.5 levels under the ARP and PM2.5 levels that would
have occurred had all EGUs subject to the ARP emitted at a rate equal to their initial allocations of allowances. The map
suggests that trading increased PM2.5 levels along the Eastern Seaboard, especially in densely populated areas in the Middle
Atlantic states.
Our approach
The goal of this paper is to compare compliance costs during Phase II of the ARP with the costs of a uniform performance
standard that would have achieved the same aggregate emissions as the ARP achieved in Phase II. This is a difficult task.
Carlson et al. (2000) project cost savings of the program in the steady state; i.e., once the 8.95 million-ton cap on SO2
emissions was achieved. In fact, the allowance market never reached a steady state (Schmalensee and Stavins, 2013). Once
the health benefits of Title IV were recognized (Burtraw et al., 1998, EPA, 1999), the ARP was replaced by more stringent
regulations.2 In 2003, EPA issued a draft of the Clean Air Interstate Rule (CAIR), which set a cap on SO2 emissions that was
57% lower than the cap under the ARP. We view compliance decisions made after 2003 as responding to a different regulatory regime. For this reason, our analysis focuses on the year 2002.
In measuring cost savings, we concentrate on the EGUs that were the focal point of the ARP: units that were not already
covered by EPA’s New Source Performance Standards (NSPS). The NSPS effectively required all EGUs built after 1970 to
achieve SO2 emissions reductions as least as stringent as those enacted by the ARP (see Section Title IV and Other SO2
Regulations Facing Coal-Fired Power Plants below). There were 838 coal-fired EGUs in operation in 2002 not covered by the
NSPS. We model the compliance behavior of 761 of these units (hereafter, modeled units).3
To estimate the cost savings from the ARP we estimate an econometric model of compliance behavior based on compliance choices observed in 2002. The main methods used to reduce SO2 emissions are to purchase low-sulfur coal or install
a flue-gas desulfurization unit (FGD or “scrubber”).4 Our model is a mixed logit model of the choice of whether to install a
scrubber and what type of coal to buy, described by geographic location of coal purchases. This model allows us to predict
1
EPA (1992) predicted cost savings of $9.6 billion to $13.8 billion over the period 1993–2010, or annualized savings of $689 million to $973 million
(1990$).
2
As Schmalensee and Stavins (2013) note, the original motivation for reducing SO2 under Title IV was to reduce acidic deposition, which can reduce
soil quality (through nutrient leaching), impair timber growth, and harm freshwater ecosystems (EPA, 2011). Subsequent research demonstrated the
significant health benefits associated with reduced secondary particle formation from lower SO2 emissions.
3
As described more fully below, of the 77 EGUs dropped, 36 have no data on coal purchases, 27 purchased coal primarily outside of the United States,
and 14 changed to NSPS status shortly after 2002.
4
Unless otherwise indicated, we use the term low-sulfur coal to refer to coal from the Powder River or Uinta basins.
182
H.R. Chan et al. / Journal of Environmental Economics and Management 88 (2018) 180–209
Fig. 1. Difference in PM2.5 concentrations in 2002: ARP minus no-trade scenario. This map shows the difference in estimated PM2.5 concentrations under
the Acid Rain Program and the No-Trade counterfactual. PM2.5 concentrations under the ARP are estimated using 2002 emissions from EPA’s CEMS
database; emissions under the No-Trade Counterfactual assume that each unit emits SO2 according to its 2002 permit allocation, plus any 2002 drawdown
of the allowance bank. Green values indicate lower concentrations under the ARP than under the No-Trade counterfactual, while red values indicate higher
concentrations under the ARP. This geographic pattern suggests that trading moved emissions from the West to the East of the US. (For interpretation of the
references to color in this figure legend, the reader is referred to the web version of this article.)
compliance choices under the ARP and under a uniform performance standard (UPS) that achieves the same aggregate
emissions as our modeled units emitted under the ARP. After estimating the model, compliance choices, compliance costs,
and emissions are predicted for each EGU under the ARP and under our counterfactual scenario, for the year 2002.
We acknowledge the limitations of our approach. The ARP was a multi-year program. Allowance trading under the ARP
gave firms flexibility in achieving emissions reductions: purchasing an allowance is, in effect, an option to install a scrubber
or fuel switch at a later date. A fairer comparison to a UPS would involve modeling compliance as a dynamic decision and
comparing a multi-year UPS to the ARP, rather than using a static model.
We also acknowledge that a comparison of the ARP and a UPS in 2002 is likely to understate the cost savings that would
ultimately have been achieved by the ARP, for two reasons. The first is that the aggregate emissions of our 761 modeled
units in 2002 are 40% higher than allowances issued to these units for the year 2002. This implies that our 2002 UPS is much
less stringent than the UPS needed to achieve the long-run emissions goal of the ARP. With a less stringent cap, we would
expect lower gains from trade than those estimated by Carlson et al. (2000). The second reason is that we ignore the benefits
of the banking provisions of the ARP. By letting plants bank allowances for future use, the ARP allowed compliance costs to
be postponed. Calculating cost savings under the ARP in a single year fails to capture these benefits.
We also wish to ask whether the health damages associated with SO2 emissions were lower under the ARP than under a
regulatory regime that did not allow trading. We do this using two scenarios. In the first, we compare damages under the
ARP and the counterfactual UPS for the 761 coal-fired generating units used to estimate cost savings under the ARP. Although a natural comparison, the counterfactual UPS in fact incorporates trading. As noted above, the emissions of our 761
modeled units in 2002 exceeded their allocated emissions for the year 2002 by 40%; two-thirds of this difference was
covered by allowances purchased through trading. Even if damages under the ARP and the UPS counterfactual are approximately equal, trading could have had an impact on health if the allowances obtained by our modeled units came from
plants with lower marginal damages.
To examine the full impact of trading on health damages, we construct a no-trade scenario and compare damages under
the no-trade scenario with damages under the ARP. The no-trade scenario includes all EGUs covered by the ARP and forces
them to emit at the rate prescribed by their initial allocation of allowances, plus any drawdowns of their allowance banks
observed in 2002. The impetus of this comparison is to isolate the impact of trading per se, rather than compliance with a
uniform performance standard, on health damages.
H.R. Chan et al. / Journal of Environmental Economics and Management 88 (2018) 180–209
183
To compare health damages under the ARP and our counterfactual scenarios, we estimate pollution damages associated
with emissions using AP2, an integrated assessment model that links emissions from each power plant to changes in
ambient air quality, changes in population exposures to PM2.5, and associated health effects. The model (Muller, 2011),
which is an updated version of the APEEP model (Muller and Mendelsohn, 2009; Muller et al., 2011), uses the PM2.5
mortality dose-response function estimated by Pope et al. (2002) and values changes in mortality risks using a $6 million
(2000$) value of a statistical life (VSL).
Our findings
We estimate the cost savings from emissions trading to be approximately $200 million (1995$) in 2002. This is a much
smaller estimate than that of Carlson et al. (2000). There are at least two reasons for this. One reason, suggested above, is
that the emissions cap in our simulations, which equals actual emissions of our modeled plants in 2002, is much less
stringent that the steady-state cap facing these units. With a less stringent cap and a less stringent UPS we would expect
lower gains from trade. The second reason is that Carlson et al. (2000) assumed that cost minimization would preclude the
installation of scrubbers at coal-fired plants not covered by the NSPS. In fact, the number of EGUs with scrubbers at these
plants increased by 50% between 1995 and 2002.
Regarding health impacts, we estimate that in 2002, health damages associated with emissions from our modeled plants
would have been slightly (0.18%) higher under the UPS than under the ARP. This is not surprising. EGUs that are below the
UPS under the ARP increase their emissions; those above the UPS under the ARP reduce their emissions. Although emissions
under the ARP and the counterfactual UPS occur in different places, the exposed populations are high in both cases.
This does not mean, however, that the ARP had no impact on health. In 2002, our modeled units emitted approximately
7 million tons of SO2, 2 million tons more than their allowance allocations for the year 2002 of 5 million tons. Two-thirds of
these allowances were purchased from other EGUs. The health effects of the ARP depend on the location of sellers versus
buyers of allowances. To capture the health impacts of trading, we estimate the health damages associated with the observed emissions of all units participating in the ARP and compare them with the damages that would have resulted had
units emitted SO2 at a rate determined by the initial distribution of allowances. We find that damages under the ARP
exceeded damages under the no-trade counterfactual by $2.1 billion (1995$) (1.8% of damages under the ARP). This is
because under the ARP, NSPS units and non-coal units transferred or sold allowances to coal-fired units not covered by the
NSPS. Sellers of allowances were more likely to be located in sparsely populated areas to the west of the Mississippi River,
whereas buyers were located in the US Midwest and East.
The damages under our no-trade counterfactual should not be compared with the cost savings experienced by our
modeled plants: the former are based on all units covered by the ARP; the latter are based on only 761 EGUs. It would
therefore be inappropriate to conclude that trading under the ARP yielded negative net benefits. The no-trade counterfactual does, however, suggest the importance of considering differences in marginal damages when designing a cap and
trade system, a point made by Muller and Mendelsohn (2009). We emphasize that the difference in compliance costs
between the UPS and the ARP for our 761 modeled units indicate significant cost savings from cap and trade. Our estimate of
$200 million (1995$) is a lower bound to cost savings from trading for the reasons given above.
The paper is organized as follows: Section Background discusses the ARP and other regulations affecting SO2 emissions
from coal-fired power plants and describes compliance behavior in Phase II of the ARP. We present our cost model and
estimation results in Section Modeling Compliance Behavior under the ARP. In Section Simulation Results we simulate compliance behavior under a uniform performance standard and compare compliance costs and emissions under the standard
and the ARP for modeled units. In Section The Health Impacts of Trading we estimate health damages under the ARP and
contrast them with damages under a UPS and a scenario in which all units emit SO2 at a rate determined by the initial
distribution of allowances. Section Conclusions discusses the policy implications of our results.
Background
Title IV and other SO2 regulations facing coal-fired power plants
The objective of the Acid Rain Program was to reduce sulfur dioxide emissions from fossil-fueled power plants in the
United States by 50% from 1980 levels. The program was implemented in two phases: In Phase I (1995–99), the most
polluting 263 generating units (termed “Table A” units) were required to participate. In Phase I Table A units were allocated
allowances equal to an emissions rate of 2.5 pounds of SO2 per million Btu (MMBtu) of heat input times the unit’s heat input
in the 1985–87 reference period. Units were also allowed to voluntarily enroll in Phase I, either as substitutes for Table A
units or to compensate for reductions in output at Table A units.5 In Phase II, beginning in 2000, the program was extended
5
As Ellerman et al. (2000) note, “substitution and compensation” units tended to be units with low marginal abatement costs that were enrolled to
increase the number of allowances their owners received. Over 150 EGUs were enrolled as “substitution and compensation” units in the first three years of
the ARP, with 138 units enrolled in all three years.
184
H.R. Chan et al. / Journal of Environmental Economics and Management 88 (2018) 180–209
to all generating units with a capacity exceeding 25 MW, approximately 1100 coal-fired units. All ARP-regulated units were
allocated annual permits in Phase II equal to the product of the target emissions rate—1.2 pounds …
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