PRELIMINARY EVALUATION OF ALTERNATIVE PREVENTION OF
SIGNIFICANT DETERIORATION POLICIES: A CASE STUDY OF
OIL SHALE DEVELOPMENT IN COLORADO AND UTAH
FINAL REPORT
Prepared by
Putnam, Hayes and Bartlett, Inc.
50 Church Street
Cambridge, Massachusetts 02138
Prepared for
Don Ryan
Economic Analysis Division
U.S. Environmental Protection Agency
Washington, D.C.
and
Ken Lloyd
Region VIII
Office of Policy and Management
U.S. Environmental Protection Agency
Denver, Colorado
May 1982
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C?02-
USES AND LIMITATIONS OF THE ANALYSIS
This report was prepared under contract for the U.S.
Environmental Protection Agency by Putnam, Hayes and
Bartlett, Inc. The study represents a joint effort
between EPA's Region VIII office in Denver, Colorado and
the Office of Policy and Resource Management in
Washington, D.C. and focuses on a critical environmental
and energy issue, having both national and regional
significance. Though prepared under the direction of EPA,
the report's opinions and findings contained within are
those of the authors and do not necessarily represent
Agency policy.
The purpose of this study is to examine alternative
PSD increment allocation and management approaches that
are potentially available to the states of Colorado and
Utah. Several national parks, wilderness areas, and
national monuments that warrant special protection under
the Clean Air Act are located in these states.
Considerable energy development scheduled to take place in
the area may consume the short-term SO- increment in
several mandatory and potential Class I areas, indicating
that PSD requirements may constrain potential energy
development in the area. Since the state of Colorado is
in the process of developing its own PSD program, this
study is intended to assist the state in evaluating PSD
management approaches that can be adopted at the outset of
the state1s program ¦to mitigate any constraints on future
energy development.
The analysis focuses on options that represent
variations to the standard first-come, first-served
approach that has been used heretofore by EPA and some
states. The study does not recommend any one solution but
instead offers several options, pointing out their
relative strengths and weaknesses. The best option for
either Colorado or Utah will be determined by the states
based upon their individual needs and circumstances,
political constituencies, growth patterns, and air quality
management capabilities.
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Due to the many uncertainties and limitations
surrounding the data and air quality modeling associated
with the analysis, the results for individual sources in
Class I areas should be viewed with caution. The various
estimates and modeling procedures that are crucial to the
analysis are very crude at this stage of development.
Current estimates of production capacities, emission
rates, effectiveness of control technology, and the rate
and pattern of development are only speculative at this
time, even on the part of industry, and may change
considerably as the oil shale industry develops. The air
quality impacts are only rough approximations because of
the inability of existing models to accurately estimate
impacts in complex terrain areas over long distances,
which are typical in the study area. Before credible
estimates can be made that serve as the basis for actual
permitting decisions, more advanced modeling procedures
and more extensive meteorological data bases will have to
be developed.
As a result of these limitations, the results of this
analysis serve to illustrate the relative impacts of
alternative allocation methods and do not represent
precise results for the area. Even though the analysis
offers informative .comparisons among options, no
conclusions should be drawn as to which facilities might
obtain permits or the ultimate air quality impact of the
potential development. The analysis should be used only
for its intended purpose of judging the relative
effectiveness and efficacy of the various management
approaches.
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TABLE OF CONTENTS
Chapter 1
EXECUTIVE SUMMARY 1
Chapter 2
THE CURRENT PSD PROGRAM AND ITS
IMPLICATIONS FOR INDUSTRIAL DEVELOPMENT 11
Chapter 3
INCREMENT ALLOCATION OPTIONS . . . 16
Chapter 4
APPLICATION OF CURRENT PSD POLICY TO
THE OIL SHALE REGION 34
Chapter 5
EVALUATION OF ALTERNATIVE OPTIONS
ALLOWED BY THE CURRENT PROGRAM 45
Chapter 6
EVALUATION OF ALTERNATIVE APPROACHES
TO THE CURRENT PSD PROGRAM 77
Chapter 7
SUMMARY AND CONCLUSIONS 34
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TABLE OF CONTENTS (Continued)
Appendix A
DESCRIPTION OP SOURCES A-l
Appendix B
S02 CONTROL COSTS B-l
Appendix C
UTILITY S02 CONTROL COSTS C-l
Appendix D
AIR QUALITY IMPACTS OF EMISSION SOURCES AT
BACT CONTROL D-l
Appendix E
AIR QUALITY IMPACTS OF EMISSION SOURCES AT
A MOST STRINGENT TECHNOLOGY LEVEL E-l
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ACKNOWLEDGMENTS
In carrying out this effort, Putnam, Hayes &
Bartlett, Inc. (PHB) received guidance and assistance from
many Environmental Protection Agency (EPA) staff and other
officials. Overall supervision of the effort was provided
by EPA's project officers: Don Ryan (Energy Policy
Division) and Ken Lloyd (Region VIII Analytic Center). In
addition to these project officers, a number of
individuals made contributions of time, data and ideas to
the effort. These people include:
John Dale
Richard Fisher
Douglas Latimer
George Lauderdale
EPA Region VIII
EPA Region VIII
Systems Applications, Inc.
Colorado Department of Health
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EXECUTIVE SUMMARY
CHAPTER 1
This report is a case study addressing EPA's policy
for granting permits to new sources of air pollution
locating near national parks and wilderness areas. The
granting of permits is governed by the Prevention of
Significant Deterioration (PSD) regulations. PSD
regulations establish maximum allowable levels of ambient
air quality deterioration for total suspended particulate
(TSP) and sulfur dioxide (SO-)* These allowable levels of
ambient degradation are called "increments." Under this
air quality management approach, national parks and
wilderness areas are allowed only small increases in
pollution over baseline air quality levels. Because a
number of this country's parks are located in areas having
rich energy resources, many believe that the PSD
regulations could constrain energy development in some
areas.
This study addresses methods that can be used by
states and in some cases the federal government to
allocate the increment among sources in a manner that will
maintain industrial development. its purpose is to
present an d assess alternative increment allocation
options. The focus is on options that represent
variations to the first-come, first-served allocation
approach which is commonly used by EPA and state agencies.
This study also evaluates alternatives which would require
changes in the Clean Air Act. This assessment can be
used by individual states in determining the options that
are preferred given their individual needs and
circumstances.
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To obtain quantitative results on the relative
implications of the various options, a case study was
developed to assess the options within the context of an
actual The oil shale region of western Colorado and
eastern Utah was targeted for this case study. The reaion
includes eight mandatory and three potential Clasl ?
areas. This region has abundant shale oil reserves
will likely be the site of significant development ^tf
all oil shale facilities proposed to date are built
production of nearly 1.2 million barrels per day of oil
could be achieved by the end of the century.
Air quality modeling was conducted to evaluate the
ambient axr quality impact of the major emission sources
in the study area. This modeling showed that the 24-hou?
sulfur dioxide (SO.) increment for Class 1 areas would bl
the most constraining PSD standard for the recion
However, in some areas TSP Class II increments may be
exceeded and along with the SO, Class I increments could
constrain oil shale development. The options that are
evaluated in this report are judged in relation to the so
Class I standard. A study of TSP Class IX increments ma$
be warranted if Class II protection remains in the Clean
Air Act.
The case study evaluates allocation options that are
available under the current program, it also considers
some options that are not currently allowed but could
result from amendments to the Clean Air Act. Any changes
in the PSD program are speculative at this time, but the
case study provides useful data on the implications of
possible changes and their relation to the current
approach. Throughout the report it has been assumed that
the states of Utah and Colorado would collaborate and
enact complementary PSD management strategies. This
assumption is important because emission sources in one
state can have an air quality impact on Class I areas in a
neighboring state.
The remainder of this chapter describes each option
that has been analyzed, data limitations, and the findings
and conclusions for the case study.
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OPTIONS ALLOWED UNDER CURRENT LAW
• Require Most Stringent Technology ~ The
permitting authority could require that sources
apply very stringent control when demand for the
increment was great. This option would allow
more sources to site before the increment is
consumed.
• Air Quality Offsets -- Offsets can be obtained
either from existing sources or sources pre-
viously granted PSD permits which would enable
the applicant to site without causing am incre-
ment to be exceeded.
• Retrofit Existing Sources — Once the increment
is consumed, the permitting authority could
require existing sources to retrofit additional
controls to provide a PSD "growth margin" for
new sources.
• Retrofit PSD Permitted Sources — This option is
*-h<» prttxHmis approach except
that it would include the retrofit of sources
that have previously obtained PSD permits.
• Variance — A variance to the increments could
Be obtained according to the procedures pre-
scribed by Section 165(d) of the Clean Air Act.
• Site Elsewhere — Once the increment is consumed
sources may choose to alter their site location
to avoid violating the increment.
• Reserve the Increment — The permitting
authority could reduce the chances of an
increment violation occurring by allowing PSD
sources to use only a portion of the remaining
increment, thus reserving some of the increment
for future growth.
• Rely on Local Preferences — State and local
authorities could grant permits to facilities
that would provide the greatest benefits to the
region. Criteria for granting permits could
include employment, tax revenue, and air quality
impact.
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OPTIONS THAT REQUIRE CHANGES
IN THE CLEAN AIR ACT
• Annual Air Quality Increments Only — This
option abandons the short-term Class I
increments while retaining the annual increment.
• Abandoning Short-Term Increment Tracking
Under this approach, annual increments would be
retained. However, each PSD applicant would be
required to evaluate their emissions against the
short-term increments instead of evaluating the
cumulative emissions of all PSD sources against
the increment.
e BACT Control with No Class I Increment —
Sources would receive permits after compliance
with BACT requirements. The air quality impact
of tEfe source in Class I areas would not be
considered in permit decisions.
0. iftwiqsion Density Zoning (EDZ} — An EDZ approach
Is a land-use-based air quality strategy which
requires that emissions of a pollutant be
limited to prescribed levels for a selected unit
area.
• Economic Approaches — A marketable permits or
om-i asion fee system could be instituted.
Marketable permits and emission fees have
advantages in that they can alloc'ate the burden
of control in an efficient manner.
There are several significant limitations to this
study In particular, because there are no full-scale oil
shale facilities that are operational, the database of
information on oil shale processes is extremely limited.
Information in the following areas was difficult to
quantify:
« SO emission rates are uncertain since they are
baled on engineering studies of pilot plants and
not actual emissions from commercial scale
facilities.
• Air quality impacts are rough approximations
because of the inability of existing models to
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accurately estimate impacts in complex terrain
areas, such as the study area.
• Production processes that will eventually be
employed for the facilities are uncertain since
companies continue to evaluate various tech-
nologies and vary their processes accordingly.
• The order in which plants will apply for
permits, whether the plants will even be built,
and the ultimate size of the plants are subject
to speculation. The timing and size of
development by individual companies continue to
change.
• Secondary emissions (e.g., road dust) were not
included in the analysis.
• Uncertainties in the actual sulfur removal
technology that will be employed and their
design uncertainties make estimation of pollu-
tion control costs difficult and approximate.
As a result of these limitations, this study should
not be construed to indicate which sources would obtain
permits, rather, the focus is to indicate which PSO
management alternatives have the potential to facilitate
oil shale development and maintain air quality in Class I
areas.
CONCLUSIONS
Exhibit 1-1 illustrates the maximum potential shale
oil production levels allowed by each PSD alternative.
Based on an analysis of each option the following
conclusion can be made.
OPTIONS ALLOWED BY CURRENT LAW
• Preliminary air quality modeling indicates that
all of the proposed oil shale facilities in the
Colorado/ Utah study area could not receive PSD
permits without violating the Class I increments
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Exhibit 1-1
POTENTIAL OIL SHALE PRODUCTION
UNDER PSD ALTERNATIVE OPTIONS
Alternative*
Current FCFS Policy
Most Stringent
Technology
Offsets
Retrofit Existing
Retrofit Permitted
Sources
Variance
Variance/Offset
Annual Increment
Annual—Elimination
of Short-Term
Tracking
BACT
Potential Production
Including Mandatory
Class I Areas
(Thousands bbl/dl
465
515
635
635
515
1190-1240+
990
1240+
1240+
1240+
Potential Production
Including Mandatory
and Potential
Class I Areas
(Thousands bbl/d)
315
365
485
485
365
1190-1240+
535
1240+
1240+
1240+
* Chapter 3 includes a detailed summary of each PSD manaaement
alternative.
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at one or more Class I areas. Under the current
first-come, first-served (FCFS) policy, only
465,000 bbl/d of oil shale development (seven
sources) could obtain PSD permits when the
mandatory Class I areas are considered. If the
Dinosaur National Monument, presently a Class II
area, is ultimately included as a Class I area,
only 315,000 bbl/d of development (five sources)
could obtain permits.
• The Flat Tops Wilderness area could constrain
oil shale development in the Parachute Creek and
Piceance basins. The Mt. Zirkel Wilderness area
could constrain development in the Uinta basin.
Two power plants (one in Colorado and one in
Utah) may combine to consume the Class I
increment at Mt. Zirkel. Thus, any further
development of Unita basin may require sources
to obtain variances or offsets.
• Allowing sources to obtain air quality offsets
but not variances from Class I increments would
increase the maximum allowed development com-
pared with the current FCFS policy. Oil shale
development would therefore be 635,000 bbl/d or
485,000 bbl/d if Dinosaur is included as a Class
I area.
• If the state required existing emission sources
to retrofit SO. controls, the maximum oil shale
production woxfld be identical to the offset
approach. The primary differences between the
two options are: 1) distribution of costs
between new and existing sources and 2) the
timing of incremental pollution control costs.
From an equity perspective, an offset trading
program would be preferable to the retrofit
option because offsets would require the sources
that need permits to pay for the offset. A
retrofit approach would require the existing
sources to pay for the additional equipment.
Furthermore, the regulatory authorities may not
require retrofit of the most cost-effective
sources. In addition, the implementation of a
retrofit strategy may require extensive
collaboration between Utah and Colorado because
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sources in one state impact Class I areas in the
adjoining state.
A most stringent technology policy would limit
oil shale development and place significant
additional costs on the sources that could
obtain permits. For example, if more stringent
technology were required for all sources, only
one additional source (beyond the current
first-come, first-served strategy) would receive
a permit. The costs o£ installing most
stringent technology would approximately double
the costs of installing BACT control. Total
annualized costs for pollution control for the
oil shale sources would increase from $92.6 to
$200.9 million. .
A final option allowed under current law, the
granting of Class r variances, would allow the
majority of proposed oil shale sources to obtain
PSD permits. This development would be
accompanied by higher SO, concentrations at the
Class I areas. It is difficult to quantify how
much growth could take place under a variance
approach since Section 165(d) calls on the
federal land manager of the Class I area, and in
certain cases, the governor of the state or the.
president, to make subjective decisions
regarding the proposed plants effects on air
quality values in these areas. However, under
the basic requirements of Section 165(d), a
iwjtimhb of nearly 1,200,000 bbl/d of oil shale
development could take place. This amount of
growth would correspond to a 24««hour SO-
concentration of approximately 9.6 ug/tn3 at Plat
Tops, 10.9 ug/m3 at the Dinosaur Park National
Monument and 5.7 ug/rn3 at the Mt. Zirkel
Wilderness area.
An alternative which would allow substantial
development would be to grant a variance from
the Class I increments at Flat Tops and use
offsets to maintain the air quality at Mt.
Zirkel. Under this alternative, one million
bbl/d of development (sixteen of the eighteen
total sources) could obtain PSD permits. If the
Dinosaur Monument is included as a Class I area,
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this alternative would allow development of only
535,000 bbl/d. Additional variances for sources
violating the increment at Dinosaur would be
required or further development would be
constrained.
OPTIONS WHICH REQUIRE CHANGES
IN THE CLEAN AIR ACT
• Elimination of short-term increments while
retaining the annual increment would also allow
more energy development to take place in the
region. If all the proposed sources were to
obtain PSD permits, the highest annual SO.
increment reading would be 0.62 ug/m3 at Flat
Tops. The coinciding 24-hour SO- value at Plat
Tops would be 9.6 ug/m3.
• The elimination of short-term increment tracking
would^have no effect because no individual PSD
source' has a 24-hour SO, impact of over 5.0
ug/m3 in Class I areas. Thus, this option would
have the same impact as the annual increment.
• A policy which would eliminate PSD increments
and require sources to comply with BACT would
degrade air quality at the parks compared with
other alternatives but would allow development
to the secondary NAAQS. If this approach were
implemented, the 24-hour increment would be 9.6
ug/m3 and 10.9 ug/m3 at the Flat Tops and
Dinosaur areas, respectively, if all the
proposed sources were constructed. The control
costs for the sources would also be less because
no offsets or additional control would need to
be purchased.
SENSITIVITY ANALYSIS
Sensitivity analyses were conducted on the results of
the first-come, first-serve analysis. One sensitivity
analysis included increasing emissions from several
facilities that may have on-site refining. Another
analysis involved changing the order in which plants
applied for permits so air quality impact would be
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minimized. In each case the oil shale development
estimates were not significantly altered. '
A final sensitivity analysis included the relaxing of
the increment ceiling for sources in the Uinta basin. The
air quality modeling conducted for this study indicates
that two power plants may consume the increment at Mt
Zirkel, and, therefore, oil shale facilities in the Uinta
basin may be unable to obtain PSD permits. The air
quality contribution for all Uinta oil shale sources at
Mt. Zirkel is so small (about 0.7 ug/m3) that any
refinement in the modeling may change the results
considerably. If these sources could obtain PSD permits
they would represent an additional 280,000 bbl/d of
growth. Under the first-come, first-served approach
maximum growth would increase from 465,000 to 745 000
bbl/d when the mandatory Class I areas are considered.'
FORMAT OF REPORT
The next two chapters describe the current PSD policy
and alternatives for allocating the PSD increment.
Chapter 2 describes the current program and associated
problems. Chapter 3 provides a description of each option
to be analyzed and contains a general discussion of how
each option would work. Chapters 4 through 6 are
concerned with the analysis and results of the case study.
In Chapter 4 the study area is described. Chapters 5 and
6 present the results of the analysis and an evaluation of
the potential of each alternative increment allocation
option. Chapter 7 compares the SO- control costs, air
quality impact, and growth potential between these
alternatives and the current policy. Five appendices at
the conclusion of this report include a description of
each emission source, a description of the SO, control
cost data that was used, and a summary of the air quality
results.
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THE CURRENT PSD PROGRAM AND ITS
IMPLICATIONS FOR INDUSTRIAL DEVELOPMENT
CHAPTER 2
THE CURRENT PSD PROGRAM
The 1977 Congress specified the basic framework of
the current PSD program in Sections 160 through 169 o£ the
Clean Air Act. Since then, EPA has promulgated
regulations at 40 CFR 51.24 and 52.21 which implement the
basic framework.
The fundamental principle for the current program is
that air quality in any clean air area may not signifi-
cantly deteriorate. With respect to emissions of total
suspended particulate matter (TSP) and sulfur dioxide
(SO-), Congress defined how much deterioration would be
significant by means of an area classification scheme.
Congress classified certain national parks and other
special areas as Class I and the rest of the country as
Class II.* It then authorized any state or Indian
governing body to reclassify its Class II lands to Class I
or, with some exceptions Class III. Finally, Congress
specified "maximum allowable increases" (increments) in
concentrations of TSP and SO. over a baseline level for
each of the three classes. The increments for Class I
areas are small; for Class II areas, of moderate size; and
for Class III areas, larger still. In addition, the
Class I areas include international parks, national
wilderness areas which exceed 5,000 acres in size,
and all national parks which exceed 6,000 acres.
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increments are based on different averaging periods,
specifically, 24 hours and one year for TSP and 3 hours,
24 hours and one year for SO- Exhibit 2-1 lists the
increment values for TSP an
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Exhibit 2-1
PREVENTION OP SIGNIFICANT DETERIORATION
AIR QUALITY INCREMENTS
Maximum Allowable Increase*
(ug/m3)
Pollutants Class I Class II Class III
Particulate Matter
Annual Geometric Mean 5 19 37
24-Hour Maximum 10 37 75
Sulfur Dioxide
Annual Arithmetic Mean 2 20 (15) 40
24-Hour Maximum 5 91 182
3-Hour Maximum 25 512 700
SOURCE: Clean Air Act Amendments of 1977, Title I, Part C,
Section 163, August 7, 1977.
Maximum allowable increases over baseline concentrations
not to be exceeded more than once per year except for
annual where allowable increases over baseline may not
be exceeded.
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account energy* environmental, and economic
costs, determines is achievable" for the
project. BACT must be at least as stringent as
any applicable standard under Section 111 (NSPS)
or 112 (NESHAPS);
3. Show that the project, given the proposed
limitation or standard, would neither cause nor
contribute to a violation of any PSD increment
or NAAQS;
4. Provide an analysis of air quality in the area
where the project would have a significant
impact. This analysis must generally include
monitoring data over a period of one year for
any criteria pollutant.
5. Provide an analysis of the effect that the
project would have on soils, vegetation and
visibility in the area where the project would
have a significant impact;
6. Provide an analysis of the effect that growth
associated with the project would have on air
quality? and
7. Provide such post-construction monitoring data
as the • permitting authority determines is
necessary.
Even if an applicant shows that its proposed project
would neither cause nor contribute to a violation of an
increment over a federal Class I area, the permitting
authority could deny the application if the federal land
manager (FLM) of the area shows to the satisfaction of the
permitting authority that the project would impact the air
quality-related values of the area adversely. Conversely,
even if a project would violate an increment over a
federal Class I area, the permitting authority could still
issue a permit if the FLM certifies that the project would
not affect the air quality-related values of the area
adversely or, in certain cases, if the applicant otherwise
obtains a variance.
There are some perceived problems with the approach
to preventing significant deterioration defined above.
The permitting procedure is often tedious and time
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consuming. If permits are allocated on a first-come,
first-served (FCFS) basis, as is normally the case, the
distribution of permits and therefore industrial develop-
ment in the region could be undesirable. For example,
national interests, such as energy development, may not be
satisfied by a first-come, first-served allocation
procedure. Furthermore, once the increment is consumed,
without some form of emission trading or a variance, no
further development could occur in the region.
Within the current program there are options that can
overcome these problems. The next chapter describes the
options available to state authorities under the current
program and several* options which would require changes in
current law.
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INCREMENT ALLOCATION OPTIONS
CHAPTER 3
As mentioned in the previous chapter, the current
approach to air pollution control could potentially limit
energy development near Class I areas. This chapter
describes several options for allocating the PSD increment
that may serve to alleviate this limitation. These
options are separated into two categories: those that
could be employed under the current Clean Air Act and
those that would require changes to the Clean Air Act.
This final category includes several economic and zoning
approaches that would require significant restructuring of
the current law. In all cases, it is assumed that the
states of Colorado and Utah would implement similar PSD
management strategies. This assumption is necessary
because emission sources in one state can affect Class I
areas in adjoining states.
OPTIONS ALLOWED UNDER CURRENT LAW
Most Stringent Technology
Under the most stringent technology option, state
officials would require new sources to install more
stringent technology after there appeared to be pressure
on the increment ceiling. Most stringent technology would
correspond to additional pollution control requirements
beyond those normally required to meet BACT. Under this
approach air quality would deteriorate more slowly than
with the FCFS approach. New sources would bear a greater
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financial burden than under the current aoam»r.h
offset option. One disadvantage ofthTs approach
K ttFSizsrsL *£sa
£^iT„rjs?s*
Offset Approach
Under current policy, a new source seeking to locate-
j£ " ?atiV£* ,P-SD increment has been consumed coSld
be denied a permit if its emissions resulted in an air
quality impact which exceeded the allowable limits ill
quality offsets are one way to avoid this problem bv
allowing new sources to offset the impact of their
sions by persuading existing sources to reduce emissions'
When a prospective source purchases an offset from »A
existing source, the existing source agrees to control iS
amissions so that the new source can produce some emis-
sions. Thus, total air quality would not deteriorated
economic growth in the region could continue.
In order to receive a PSD permit using the offset-
option, the proposed facility must first apply BACT The
applicant must then be able to purchase offsets* from
existing sources so that air quality increments would not
06 6XC66u6Q•
Offsets can occur within one company (internal) or
among different companies (external). The majority of
transactions to date have been internal, in the case of
external offsets new sources would bear the financial
burden of control because they would have to purchase
offsets from existing sources to receive a permit. To the
extent that offsets are purchased, the offset sellina
sources would benefit from having located in an area
before the increment ceiling is reached.
One advantage of this approach is that a market for
the purchase and sale of offsets would develop The
market would assist sources in purchasing the least-cost
(and therefore cost-effective) pollution controls. These
incentives for economic efficiency are not found" in all
the other options. The only disadvantage would be if
there were not enough sources to establish a significant
market.
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Retrofitting Existing Sources
Another option would be for state officials to
require existing emission sources to retrofit additional
control equipment once the increment has been consumed.
Officials could mandate that all sources uniformly
rollback their emissions or could mandate retrofit of the
lowest cost sources. The uniform rollback approach was
not evaluated because it would be more costly than the
least cost retrofit option.
Under the least cost retrofit approach, the costs of
installing additional pollution controls would be borne by
the retrofitted sources. This is in contrast to the
offset approach where the sources seeking to obtain PSD
permits would be required to pay additional pollution
control costs when purchasing air quality offsets. If the
existing facilities can install additional control and if
the available offset potential from these sources were
quite large, then air quality in the region could be
maintained without curtailing development. However, the
retrofit of existing sources may not provide an ample
margin for growth, and other options would have to be
considered to accommodate proposed oil shale facilities.
Retrofitting Oil Shale Facilities
This approach is similar to the previous retrofit
option except that the retrofit would be mandated for oil
shale sources that had already received a PSD permit.
This option would be implemented after the increment
ceiling had been reached. The advantage of this approach
compared with the most stringent technology option is that
current facilities would not have to install additional
control until the increment ceiling is reached, and
therefore additional costs would be postponed. A second
advantage is that this approach would allow officials
flexibility in controlling oil shale plant emissions.
Because of the tremendous uncertainty involved in the
current emission estimates, a policy which allows
officials to require additional control may be advisable.
This retrofit option will be evaluated separately from the
retrofit of existing sources strategy.
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Variance Approach
Another option for new sources that wish to locate in
an area in which the increment has already been consumed
is provided by Section 165 (d) of the Clean Air Act. It
contains two mechanisms by which sources may be granted
waivers to Class I increments•
The first provision, Section 165(d)(2)(C), states
that a source that violates the Class 1 increments may
obtain a permit if it demonstrates to the satisfaction of
the federal land manager (FLM) that it will have no
adverse impact on the air-quality-related values of the
Class X area.* If the FLM so certifies, maxI imam allowable
increments ares
Concentration Over
Baseline Levels
(ug/m3)
Particulate Matter
Annual Geometric Mean ig
2 4-Hour Maximum 37
Sulfur Dioxide
Annual Arithmetic Mean 20
2 4-Hour Maximum 91
3-Hour Maximum 325
If a source is not granted a waiver under Section 165
(d)(2)(C), a second waiver provision is available to the
source under Section 165(d)(2)(D). However, this provision
is available only for waivers of short-term SO-
increments. The source must first demonstrate to thS
state that a variance would not adversely affect an
air-quality-related value. If the governor is satisfied
* Conversely, if the FLM finds that a source would have
an adverse effect on the "air-quality-re1ated values"
of a Class 1 area, and demonstrates this "to the
satisfaction" of the permitting state, the permit
must be denied even if there would be no increment
violation.
-19
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with this demonstration and if the FLM concurs the
governor nay grant a variance.*
If a variance is granted by the governor or the
president, the source is allowed to violate the existing
short-term increments 18 days per year and must comply
with the following increments:
Concentration Over
Baseline SO. Levels
(ug/m3T
Low Terrain Areas
24 Hour 36
3 Hour 130
High Terrain Areas
24 Hour 62
3 Hour 221
Both the variance options' allow economic growth in
the area after the PSO increment is consumed. They axe
also attractive in that they allow a case-by-case judgment
as to whether the air quality deterioration is significant
given other factors. The financial burden on new sources
will be smaller than under the offset option since the
purchase of offsets would not be needed.
Alternative Siting
An option that would be available to plants that are
denied a PSO permit would be to locate at another site
where their air quality impact would be minimized. While
this alternative may be successful near some Class I
areas, this option is not a reasonable approach for this
study due to the site-specific characteristics of the oil
However, if the FLM does not concur, then both his
recommendation and that of the governor's are
transmitted to the president, who may approve the
governor's recommendation if he finds that a variance
is in the national interest.
-20-
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shale processes. From a local perspective, this option
development. 38 attractive as ^ others, that allow
Reserving the Increment
If there appears to be pressure on the PSD increment,
a portion of the increment could be reserved for future
emission sources. This option could require new sources
early in the queue to incur additional control costs
relative to those costs which would be incurred by the
current FCFS policy. The additional cost occurs because
sources are forced to apply more stringent control sooner
rather than later. For example, if only a portion of the
increment were available each year but a number of sources
apply for permits in that year, some of the applicants
would need to reduce their air quality impact by applying
additional control or possibly purchasing offsets. These
additional costs of obtaining a permit would occur even
though a portion of the increment was still available for
later years.
This option can be evaluated with the use of a simple
example. In this example, it is assumed that after 3.0
ug/m3 of increment, had been consumed, state officials
would allow only 0.25 ug/m3 of increment to be consumed
annually. If there were demand for 0.5 ug/m3 per year,
this policy would require sources to purchase offsets,
reduce their emissions, or pursue another strategy to make
up for the additional 0.25 ug/m3. If, for simplicity, it
is assumed that each 0.25 ug/m3 of additional reduction
would cost a constant $5 million annually, then the
sources would have to spend $5 million each year until the
5.0 ug/o3 ceiling was reached. Exhibit 3-1 illustrates
the costs to future sources during each year for a 10-year
period assuming that the 3.0 ug/m3 level had been reached
at the start of the first year. After 8 years the
increment ceiling of 5.0 ug/m3 is reached, and 0.5 ug/a3
would be needed by new sources each year. The total cost
of this approach over this time period would be $60
million in 1980 dollars.
Exhibit 3-2 illustrates the costs of the current
first-come, first-served policy using the offset approach
when the increment is consumed. The same assumptions as
those in the previous example apply. No increment
-21-
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1
2
3
4
5
6
7
8
9
10
TO'
*
Exhibit 3-1
COST OF RESERVING THE PSD INCREMENT
OVER A 10—YEAR PERIOD
Alternative
Air Quality Air Quality Control
Increment Available* Increment Demanded Strategy
(uq/m3) (ug/m3) (mm$)
2*00 5.0 60.0
It is assumed that the 3.0 ug/m4 level has been reached
and therefore only 0.25 ugVm3 can be used annually.
-------
1
2
3
4
5
6
7
8
9
10
Exhibit 3-2
COSTS OF FCFS/OFFSET APPROACH
OVER A 10-YEAR PERIOD
Air Quality
Increment Available
(uq/m3)
Air Quality
Increment Demanded
(ug/m3)
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Control
Strategy
(mm$)
0.0
0.0
0.0
0.0
10.0
10.0
10.0
10.0
10.0
10.0
5.0
5.0
60.0
-23-
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reductions are required during the first four years
because there is enough increment available to meet the
demand. After the fourth year the increment is totally
consumed and sources have to reduce their impact or
purchase offsets in order to obtain permits. The total
cost of offsets over the ten-year period would also be $60
million. This total cost is identical to the cost of the
offsets in the reservation of the increment example,
except that costs are not incurred until the fifth year.
As all .other components of the two approaches (the
air quality, number of sources seeking permits and the'
distribution of costs) are identical at the end of the
10-year period, a net present value analysis is the best
indicator of the preferable alternative. Regardless of
the discount rate assumed, the current FCFS policy with
offsets would always have lower total costs than the
increment reservation option. The only possible advantage
of the reservation approach would be to change the
distribution/equity advantages enjoyed by those sources
first in the queue.
Local Preference
The local preference option involves local and/or
state officials making decisions, based on a number of
criteria, about which facilities should be able to receive
PSD permits. These criteria can include the employment,
economic and air quality Impacts of the different plants
that would like to site in the area. Once it is apparent
that .there would be pressure on the increment ceiling,
local officials could require sources seeking PSD permits
to be reviewed so that the needs and priorities of local
residents could be taken into account in the permit
process.
There axe many reasons why the residents of an area
would desire some influence in the development that takes
place within their jurisdiction. A primary reason would
be to prevent unwanted development that could exhaust the
PSD increment and make it more difficult for desired
industry to locate in the area. Another reason for a
local preference option is that industrial development can
have a significant impact on the character of the area.
Oil shale facilities can employ large numbers of transient
construction workers for many years who are then replaced
-24
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by a smaller permanent workforce. Small communities have
a particularly hard time absorbing short-term population
growths, and their areas may prefer a larger permanent
workforce. The importation of construction workers and a
small permanent workforce does little to help employment
problems that many communities face.
The local preference option could be implemented in
an auction format. Companies could bid for a portion of
the remaining increment by offering to provide certain
amenities to the area. The local and/or state authorities
could then choose which sources could locate in the area,
based on criteria determined to be most important. This
option could change the rate of development of an area and
the amount of increment that is consumed. This option has
certain obvious advantages for the local community and it
may be a reasonable method for controlling consumption of
the increment and the pattern of industrial growth. It
should be noted that local officials have considerable
authority to control growth through zoning ordinances and
so forth. Use of PSD policy to control growth may not be
the most direct planning method; however, it could be
attractive if it is viewed as a revenue generating
measure. Because the impact of this alternative cannot be
quantitatively evaluated it will not be included in the
following chapters.
OPTIONS THAT REQUIRE CHANGES TO
THE CLEAN AIR ACT
Annual Increments Only
This approach would remove the short-term 24-hour
increment ceiling and retain only an annual increment.
The justification for the approach is twofold; 1) the
annual increment would protect the long-term air quality
at Class I areas without prematurely constraining new
industrial development, and 2) the uncertainties
associated with modeling short-term air quality impacts
would be alleviated.
In itself, this option is not a complete solution
because although the ceiling is not reached as early as it
is with a 24-hour increment, development may still be
constrained at some point in time.
-25
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Annual Increments — Elimination
of Short-Term Tracking
This option is similar to the annual increment option
since cumulative impacts from all sources are measured
against the annual increment. However, instead of
abandoning the 24-hour increment entirely, each individual
source may not have an air quality impact on Class X areas
greater than the current 24-hour increment.
The effect of this option would usually be similar to
the annual increment approach. It would be stricter
(result in better air quality and higher control costs)
when one source has an impact that exceeds the 24-hour
increment on its second worse day because that source
would be required to add further emission control before
it could receive a permit. This option is particularly
applicable to power plants which can have a greater than
5.0 ug/m* impact on an area even when they comply with
USPS control levels.
BACT Control with No
Class I Increment
Under this option there would be no Class I PSD
increments. Instead, new sources could receive permits by
complying with BACT determinations. Costs of control
would probably decrease under this option and the burden
of control would be distributed more equally among all
permitted sources. Economic development could continue
until constrained by the secondary 24-hour SO^ NAAQS.
Emission Density Zoning
The term emission density zoning (EDZ) has been used
to define a number of different land-use-based air quality
management strategies. For the purposes of this study EDZ
is defined as an air quality management strategy which
requires that emissions of a pollutant be limited to
prescribed levels for a selected unit area. This limit
could vary depending on the size and location of each land
area. One technique would be to allow decreasing amounts
of pollution per land area as land areas become situated
closer to the park. Air quality modeling would be needed
to set the specific pollution limits.
26
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A primary advantage of an emission density approach
is that once the policy is established, regulatory
decisions would be based on plant emissions instead of the
air quality impact from the plant. This system would
facilitate offset trading and streamline the p^SJi?
process since air quality models would not have to be run
for individual sources. Sources and officials could
evaluate the pounds of emissions that would be allowed
instead of the more ambiguous air quality impact
Clearly, the disadvantage of this program is that itwould
be difficult to determine the appropriate level of emis-
sions for each area, Since little experience has been
gained with this system, substantial administrative costs
could be incurred in implementing this approach.
Economic Approaches
Economic approaches use market mechanisms to achieve
desired results rather than traditional command and
control approaches. Economic theory views frHo market
mechanism as an "invisible hand" that efficiently allo-
cates resources to their most productive use. In a free
market, when large numbers of private enterprises compete
to buy factors of production, the scarce resources go to
those who can pay the highest price. Thus in the simplest
analysis, prices allocate resources to their socially
optimal uses.
Some resources, such as air, however, are not owned
and are therefore not priced in a free market. Without
government intervention, companies could emit pollutants
into the air at no cost. The cost of a polluted
environment is paid by society through health problems and
reduced aesthetic benefits, but this cost is external to
the firm imposing the cost. Thus, economic theory views
pollution as a "market externality." Economic approaches
to pollution control attempt to internalize this external-
ity. Marketable permits and emission fees are two such
approaches. These options and the emission density zoning
approach just described are not evaluated in this case
study since a detailed implementation plan would be needed
to assess their impact. The marketable permits approach
is discussed at length because EPA and the state of
Colorado have expressed considerable interest in this
program.
-27
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Emission Fees
Emission fees, on the other hand, are set charges
that sources must pay for every unit of emission they
produce. Under this option, the price of pollution would
remain constant (or could be adjusted for inflation) but.
air quality levels would vary with the magnitude of the
fee as well as with changes in economic conditions and
pollution control costs.
Air quality levels could exceed the increment ceiling
if emission fees were set too low and companies found it
cheaper to pay than to control emissions. Since new
sources would be allowed to locate in the area as long as
they paid the emission fees, economic development would
not be severely constrained. One advantage to this
approach is that companies would have an incentive to
develop new, more efficient control technologies that
would reduce their costs.
Marketable Permits*
A marketable permit would have a specific face value
that would entitle the owner to emit a given level of
pollution over a given period of time in a particular
location. The permit might also include other restric-
tions, obligations 'or instructions. Permits would be
issued in denominations that would allow firms to buy and
sell various quantities of permits. Specific trading
rules would be needed to account for different contribu-
tions various emission sources may have on air quality.
These trading rules would assure that air quality would
not deteriorate as a result of permit trading. Trading
For a more detailed discussion, see: Putnam, Hayes &
Bartlett, Inc., Application of a Marketable Permit
System to the Control of Air Pollution, October 1980.
28-
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could be facilitated through an "exchange" which could be
operated by local or state pollution control authorities.
Enforcement and compliance could be monitored simply by
determining if actual emissions, averaged over an appro-
priate time, exceed the number of permits held by the
source.
The design of a marketable permit system requires
specification of the following:
• Number of permits (emissions) issued,
• Allocation of permits,
• Denomination of the permit/
• Duration of the permit,
• Periodic revisions in the permit system,
• Operation of a trading exchange, and
• Role of federal, state and local air pollution
authorities.
Each of these components will be discussed with reference
to the PSD program.
Number of Permits
The number of permits to be issued in an area depends
on the number of emissions and the desired air quality
goal. Permits could be issued to existing sources and
sources which have already obtained PSD permits at no
charge. The number of permits would equal the compliance
emission level. If the PSD increment is not consumed,
then a number of additional marketable permits would be
available. For each new source the state would issue
permits based on a formula that would consider BACT
requirements. For each area the total number of permit
sources would depend on the baseline air quality level,
the PSD increments, and the ambient standards.
-29
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Allocation of Marketable Permits
The initial allocation of permits to existing sources
would probably be implemented on the basis of a regulatory
proceeding and could involve the revision of State Imple-
mentation Plans (SIP). The initial distribution of
permits should provide for:
• Implementing the current pollution control
standards for sources which have already
obtained federal and state permits,
• Incentives for the trading of permits which
would result in lower regional pollution control
expenditures, and
• Implementing the program in as equitable a
maimer as possible.
Auctioning permits, selling permits at a fixed price,
or distributing permits free of charge are several options
for the initial distribution of permits. Selling or
auctioning permits would transfer income from pollution
sources to the government, requiring pollution sources to
incur an additional expense over and above expenditures
for installing and operating pollution control equipment.
Distributing permits free of charge results in income
transfers only among pollution sources.* Allocation of
permits free of charge seems to be the most appropriate
method for the initial distribution of permits to existing
sources.
In a PSD area, such as the oil shale region, sources
which have already obtained the necessary state and
federal permits could be allocated marketable permits that
reflect their compliance emission levels. The options for
allocating permits to new sources are: first-come,
first-served; a flat fee per permit; or an auction. The
latter two options may promote more efficient use of a
scarce PSD increment. An analysis of the effect of these
three options would be needed to select the appropriate
approach.
Sources with high costs of pollution control would
purchase permits and compensate sources with lower
costs of pollution control.
-30-
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Once the new sources have obtained permits, they
would trade with other sources in the area providing they
follow the usual trading rules. When the PSD increment is
consumed, new sources wishing to locate in the area would
have to purchase permits from sources which already have
permits.
Permit Denomination
The units of denomination selected for marketable
permits should facilitate trades among sources and assure
that greater emission loadings do not result from permit
trading.
The characteristics of a particular area will dictate
the appropriate permit denominations. A pounds-per-day
unit would be applicable if the short-term standard is
binding and a pounds-per-week unit is appropriate if a
long-term standard is binding. In the oil shale area, a
pounds-per-day unit would be appropriate since the 24-hour
S02 standard is binding.
Duration of Permits
The duration of the permit will have a major impact
on its market value. Investment in pollution control
equipment normally involves long-term capital commitments.
Decisions on such investments are best made in a climate
of predictability concerning the number and value of
marketable permits. Permits of short duration may hinder
capital investment planning since firms will be uncertain
as to whether more or fewer permits will be issued in the
future and what the future value of the permits might be.
Permanent permits appear to provide the greatest certainty
and stability for capital investment planning.
Periodic Revisions
Revisions in the number of marketable permits may
occasionally be needed to correct for imprecise air
quality modeling/ imprecise estimates of emissions for oil
shale sources, or because of changes in PSD increments. A.
concerted attempt should be made to minimize revisions as
much as possible as they cause uncertainty in the value of
31
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the permit, affect market liquidity, and will tend to
discourage an active market.
However, when revisions are required, the face value
of each permit could be discounted. For example, the
state could indicate that all permits would be worth 90
percent of their face value after a certain date. Before
issuing such an order the state would have to examine the
technical feasibility of obtaining the required region-
wide emission reduction. If the technical feasibility
analysis indicated that the emission reductions were
possible then the state could implement the discounting
procedure. This procedure could be phased in over a
period of several years to allow sources to obtain the
needed emission reductions.
Operation of Trading Exchanges
A trading exchange would be required to provide a
method for matching buyers and sellers of permits. A
marketable permit system contains a number of unique
characteristics that must be considered in designing a
trading system. First, the market will contain only a few
participants. Second, the value that sources place on
permits will vary widely and probably relate somewhat to
their pollution control costs. Finally, the market will
not be very active. Once the initial trading has been
accomplished (ahd sources begin to commit to pollution
control equipment), the only participants in the market
will be: (1) new firms entering the area, and (2) sources
which either by design (improved pollution control
efficiency) or by accident find a discrepancy between the
number of permits they hold and their emission level.
The objective of the trading exchange is to provide a
mechanism where buyers and sellers are matched in such a
way that the least-cost control sources install equipment
and the high-cost sources buy permits. A centrally
organized exchange staffed by private entrepreneurs or
regulatory authorities would facilitate this objective.
The management of the trading exchange would require
dissemination of information on the supply and demand for
permits. Such information might include clearing prices
and transaction quantities. It is expected that the
exchange would not be as constantly active as a stock
exchange.
-32-
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The Role of State and Local Air
Pollution Authorities
To operate a marketable permit system, the state and
local air pollution authorities will have to assume some
new responsibilities. The operation of this system will
require these authorities to:
• Issue and initially allocate permits,
e Develop permit trading rules to account for
emissions with different air quality impacts,
• Review permit trades and possibly manage the
trading exchange, and
e Determine compliance status of air pollution
sources.
With the possible exception of managing the trading
exchange, the state and local authorities should have the
skills in house required to carry out these tasks. The
most resource-intensive task would be to issue and
initially allocate the permits. This would involve
translating current emission limitations into specific
allocations of permits to sources. A number of technical
issues must be determined, including the appropriate
averaging time, actual emission levels, the method of
allocation, and so forth. A regulatory proceeding would
probably be needed for this task. The other tasks could
probably be carried out with little additional effort.
To facilitate the development of markets in market-
able permits, a guidance document might be helpful. This
document would assist firms in determining the value of
marketable permits to facilitate the evaluation of
alternatives, and would assist state and local air
pollution authorities in designing and operating a
marketable permit system.
-33-
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APPLICATION OF CURRENT PSD POLICY
TO THE OIL SHALE REGION ,
CHAPTER 4
A case study of the PSD program in western Colorado
and eastern Utah was undertaken to evaluate the PSD
increment allocation options. This area was selected foif
the following characteristics:
• The oil shale resources in the area are abundant
and the possibility of extracting oil from shale
has already attracted the interest of major
energy companies. Some critics of the PSD
program contend that future energy development
in this area may be constrained by the PSD
requirements.
• EPA and the state are interested in determining
the extent to which energy development may be
constrained by current PSD policy ( and the
viability of alternative PSD management options.
• In contrast to a previous PHB study, there are a
small number of existing emission sources in the
oil shale region which could provide air quality
offsets once the increment had been consumed.*
Putnam, Hayes & Bartlett, Inc., Preliminary
Assessment of Alternative PSD Management Approaches:
A Case Studv Based on the Experiences in Western
North Dakota, April 1982.
-------
Thus r permit allocation options which seemed most viable
in the previous study may be less attractive here. Other
options are analyzed which may be more applicable to this
region-
STUDY AREA DESCRIPTION
The area of eastern Utah and western Colorado is
cnarselv populated and is characterized by rugged terrain:
cliffs and high plateaus. The terrain influences
wallUr patterns making air quality modeling difficult.
-------
Exhibit 4-1
LOCATIONS OF EMISSION SOURCE AREAS RELATIVE
TO EXISTING MANDATORY AND POTENTIAL
CLASS I AREAS IN THE STUDY REGION
0URC2: Systems Applications, Inc., September 1981.
-------
Mandatory Class i Ajeaa Potential class I »r...
Dinosaur Natl. Monument
Arenas NdbionAi p&rk Bisci? ..
Maroon Bells Wilderness Gunnison Wilde™a««
Mount Zirkel Wilderness Colorado n»fi ! „
West Elk Wilderness Colorado Natl. Monument
Rawah Wilderness
Eagles Nest Wilderness
Rocky Mountain National Park
Onder the Clean Air Act. the thr«« ,
considered in this study are currantlv , 1, areas
but can be reclassified a^ c?a , s T £ X! Clafa.11
Currently, only the federal land manaaar h»^ „ state.
these three areas be reclassified B«aJS?F° ^
wilderness areas in the state are also potential Claw*!
areas, but they are.not included in thf? •
their status is more uncertain. 8 analysis 3xnce
Exhibit 4-2 lists the utilitv .
oil shale facilities in the stud/ area POte??i*
indicates, the maximum projected oil* shaia J!
level is estimated to be 1 j Slion Llf® production
approximately the year 2000. This esti^t* • per < y
based on information supplied to th^SvnilJi?^ t"Y
Corporation by oil shale companies filina ^l , ^Uelf
grants and loan guarantees.* Appendix A L»?h J. J
source in detail. A describes each
The sources in each basin have an
Class I area, albeit a small impact i^«oL>°n ®
Moreover, under some weather conditions casef*
more Uian one basin can combine and simitMeou,^ affert
and potential Class I areas. In deteSnJg toe S?eot°Sf
* ¦ After the analysis in this report ua*
several companies altered their conducted,
For example, Union is now forac^?1CLti0£ estiniates •
bbl/d facility. At toe b® a 90'000
undertaken, the production levels ah^n 3tVidJ, .s
4-2 were the most accurate available. ln Exlu,i5it
37
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Exhibit 4-2
PRODUCTION CAPACITIES OF PSD SOURCES
IN THE COLORADO/UTAH STUDY AREA
Oil Shale Projects
Parachute Creek Area
Naval Oil Shale Reserve
Union
Colony
Chevron Oil
Mobil Oil
Cities Service
Pacific
Subtotal
Piceance Creek Area
Occidental
Rio Blanco
Exxon
Superior
Multimineral
Subtotal
Uinta Basin Area
TOSCO/Sand Wash
White River
Paraho
Magic Circle
Syntana
Geokinetics
Subtotal
Total
Utility Projects
Moonlake 1 & 2 (Uinta Basin)
Craig 1 & 2
Craig 3 (under construction)
Total
Projected
Production Level
(bbl/d)
200,000
50,000
48,300
100,000
50,000
50,000
50,000
117,000
135,000
60,000
50,000
50,000
50,000
100,000
30,000
30,000
50,000
20,000
820 mw
894 mw
447 mw
548,300
412,000
280.000
1,240 ,300
2,161 mw
SOURCE: Synthetic Fuels Corporation ar.d PSD permits.
-38-
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Exhibit 4-3
BASINS WHICH COMBINE TO
IMPACT MANDATORY AND POTENTIAL CLASS I AREAS*
Mandatory and Potential
Basin
or
Source
Class I Areas
Uinta
—
Piceance
Plat Tops
Uinta
Parachute
Maroon Bells
Uinta
—
Piceance
Rocky Mountain
Uinta
—
Craig and Hayden**
Mt. Zirkel
Uinta
—
Craig and Hayden**
Rawah
Uinta
—
Parachute
Eagles Nest
Piceance
— Craig and Hayden**
Arches
Piceance
-- Parachute
West Elk
Piceance
— Parachute
Dinosaur
Piceance
— Craig and Hayden**
Colorado National
Monument
* This exhibit includes all of the basins or sources
which combine to impact a Class I area. Although
every basin or source may have an impact on
individual Class I areas, in several cases, basins
will have cumulative effects because pollution will
overlap and impact an area.
** The Craig and Hayden power plants have air quality
impacts on Class I areas even though they are not
located in the three oil shale basins.
39
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a new source on a Class I area the contribution of all PSD
sources in the area needs to be taken into account.
EMISSION ESTIMATES*
Emission data for the oil shale plants are difficult
to estimate because there are no commercial facilities in.
operation. Instead, emissions have to be estimated based
on pilot plant emissions and laboratory studies. To
estimate emissions (and control costs) for each plant,
five general process categories were identified. For
these five categories, either PSD permits or EPA technical
studies on alternative oil shale technologies that
provided emission estimates were available. Emission
estimates will likely become more refined as full-scale
plants are tested and developed. The categories are as
follows:
• Union B process — External indirectly heated
retort; Source — Onion PSD permit application
(7/31/79).
• TOSCO II process — Internal indirectly heated
retort? Source — EPA technical studies . on
alternative oil shale technologies.
• Modified-in-Situ (MIS) Process; Source ~
Cathedral Bluffs-Occidental PSD permit applica-
tion (4/13/81).
e Rio Blanco process — Modified-in-Situ and
Lurgi? Source — EPA technical studies on
alternative oil shale technologies.
• Paraho process — Direct heated retort; Source
— EPA technical studies on alternative oil
shale technologies.
Emission estimates for oil shale facilities are
continually under review and are subject to
significant change. The most up-to-date emission
data may be obtained from the EPA Region VIII Axr
Branch.
-40
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Exhibit 4-4 lists each proposed oil shale facility
with the process category to which it has been assigned
for emission and cost purposes and the assumed SO, removal
efficiencies. Sources were grouped by process technology
because pollution control cost and emission data were not
available on an individual plant basis. The reports
permit information used contained the most consistent data
available. Appendix B contains a more detailed
description of these categories. The category assignments
have been reviewed by EPA personnel in Cincinnati
responsible for oil shale emission studies.
These data are rough and preliminary; however, they
are. the best data currently available. Emission and
control cost estimates can be refined once commercial-
scale plants are in operation. As the results in this
study depend on these estimates, any conclusions drawn
from the case study should be re-examined when more
accurate information is available.
PSD POLICY IN THE STUDY AREA
As mentioned earlier, the authority for implementing
the PSD program still rests with the federal government.
The Hayden power plant is the only source existing prior
to implementation of the PSD program which is expected to
have an impact on air quality in Class I areas. The Craig
unit 3 and Moonlake power plants and two full-scale oil
shale facilities have already received PSD permits. Two
oil shale facilities have received permits for pilot
operations. Several other oil shale facilities have
applied for PSD permits. Exhibit 4-5 lists the oil shale
sources and their PSD permit application status. Sources
which have not filed PSD permit applications are listed
according to the estimated date of initial production.
The order in the queue is important to determine which
sources will receive PSD permits before the increment is
consumed. This queue was developed with data from a
variety of sources and the dates of initial production are
used as a proxy for PSD permit application dates. The
study is mainly concerned with the total amount of
production as opposed to particular sources that can
obtain permits, thus, the queue is unimportant to the
final results. The queue is used in the next chapter to
determine the magnitude of the constraint to energy
-41-
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Exhibit 4-4
OIL SHALE FACILITIES BY PROCESS TYPE*
Oil Shale Facility
Assumed
Process Tvpe
Approximate BACT
SO, Removal
Efficiency f%)
Union
Union
98.0
Colony/TOSCO
TOSCO II
96.9
TOSCO/Sand Wash
TOSCO II
96.9
Occidental
MIS
95.0
Geokinetics
MIS
95.0
Multimineral
Union
98.0
White River
Union
98.0
Superior
TOSCO II
96.9
Pacific
TOSCO II
96.9
Paraho
Paraho
96.4
Magic Circle
Union
98.0
Rio Blanco
Rio Blanco
99.8
Exxon
TOSCO II
96.9
Chevron Oil
Union
98.0
Mobil Oil
Union
98.0
Syntana
TOSCO II
96.9
Naval Oil Shale Reserve
Paraho
96.4
Cities Service
MIS
95.0
rrrouned bv process technology because
Sources were 9* pcost 'and emission data were not
pollution f°^r° dividuai plant basis. The reports and
p«^if infonSion used contained th. most consistent
data available.
-42-
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Exhibit 4-5
PRODUCTION QUEUE FOR OIL SHALE FACILITIES
(Estimated Start-up Dates)*
Estimated
Initial
Company/Project Permit Status Production
Union Pilot Permit Granted 7/79 1983
Pilot Upgrading Permit
Granted 6/81
SiJSL ^ „ Permit Granted 7/79 1985
TOSCO/Sand Wash Permit Granted 12/81 1587
occidental Permit Withdrawn** 1988
, Pilot Permit Granted 11/80 1984
Multiaiaeral 1984
White River Permit Pending 1986
Superior 1986
Pacific
Paraho Permit Pending 1986
Magic Circle 1986
Rio Blanco Pilot Permit Granted 12/81 1987
5«on — 1987
Chevron Oil 19gj>
Mobil oil
Syntana ?
Naval Oil Shale
Reserve ?
Cities Service ?
* Facilities are ranked according to estimated
production dates except when PSD permits have already
been granted or filed. * The plants with pending
permits are ranked in order of their application
dates. The Moonlake and Craig unit 3 power plants
received PSD permits before any of the oil shale
facilities received pilot permits and thus are ranked
first in the queue.
** Occidental is currently assessing whether to alter
its proposed oil shale process technology.
-43—
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development caused by the psd
the queue may occur7" 0i9nificant changes in the order of
sources which may have d±£#f 7rogram and not to identify
One might expect that si£i«2"* obtaining PSD permits.
-44-
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EVALUATION OF ALTERNATIVE OPTIONS
ALLOWED BY THE CURRENT PROGRAM
CHAPTER 5
AIR QUALITY MODELING
To develop the oil shale case study, PSD-permitted
sources, sources with pending PSD applications, and
proposed oil shale facilities must be modeled to determine
the amount of air quality increment consumption. Existing
sources need to be modeled to determine the available pool
of offsets. Proposed oil shale facilities and sources
with pending applications were also screened for possible
visibility impacts. These impacts were not determined to
be a major deterrent to growth in the study area.* It is
expected that the 24-hour Class I SO- increment would be
the binding constraint on future growth.
One of the main limitations of this ease study is
associated with air quality modeling. Predicting the air
quality impact of sources in high-terrain areas is
extremely difficult because of the lack of appropriate
long-range, complex terrain models. Even though modeling
is the cornerstone for any evaluation of PSD increments/
this study is not intended to have air quality modeling as
its focus. The Bureau of Land Management is currently
conducting extensive modeling using high-terrain models in
an effort that may improve modeling techniques used in
future PSD permit decisions.
The air quality modeling for this study was conducted
by Systems Applications, Inc. (SAI). See Prevention
of Significant Deterioration Policy Implications for
Projected Oil Shale Developmentr November 1981.
-------
The air quality modeling for this study was reviewed
by EPA Region VTII staff. Several sources in the area
have been modeled previously in the course of PSD
permitting decisions. These analyses did not include
existing sources that could be potential sources of
offsets, and they did not include all the proposed oil
shale facilities. SPA contracted with Systems
Applications, Ine (SAX) to conduct original air quality
modeling to support this study. The result of this
analysis may differ from previous and ongoing air quality
analyses of the area.*
SAX used generic screening models that take into
account the drainage and upslope flow conditions that were
observed in the study region. There" are a number of
important caveats regarding the SAI results. These
caveats include:
• The characteristics of future oil shale
facilities are not certain. The design,
capacity, and precise location of many of the
facilities are not known? emission estimates and
stack parameters -{height, velocity, etc.) are
very uncertain. This uncertainty, is primarily
due to the changing nature of the shale
processing technology and because a number of
companies have not fully committed to a certain
technology.
• The models used for the study are not EPA-
approved models and thus should not be"used for
making actual permit decisions. SAI's model
generally predicts smaller concentrations than
EPA's VALLEY model, which is commonly used in
high-terrain situations.
• Worst-case meteorological conditions are based
on limited observational data and SAI
professional judgment regarding plume transport
SAX and state authorities may use different SO,
emission rates, meteorological parameters and air
quality models in doing their analyses. Variations
in these three factors may lead to different air
quality estimates.
46-
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dispersion, and ground-level impacts in the
complex terrain typical of this area. Gathering
field data would have been an expensive and time
consuming task.
PHB made several adjustments to the SAI air quality
estimates. These adjustments were necessary because the
emission estimates that SAI used were outdated in compari-
son to the more recent emission data that is included in
PSD permit applications and internal EPA documents.
Chapter 4 discusses the sources of data used by PHB to
-develop emission estimates. Exhibit 5-1 summarizes the
SO- emissions used by SAI, which were based on previous
studies, and the estimates that PHB used in the analysis.
For each process, a different emission estimate was used.*
The Paraho, MIS, and Rio Blanco processes have substan-
tially higher emissions than originally used by SAI.
These new emission estimates were used to adjust the SAI
air quality estimates.** The remainder of the analysis is
conducted using the scaled air quality impact figures.
THE BASE CASE
The* base case scenario evaluates the current PSD
program which issues PSD permits on a first-come,
first-served basis until the Class I increment is con-
sumed. This section describes the results of the air
quality modeling for each source in the study area. A
discussion of the alternatives available under the current
law follows the base case description.
Existing Sources
SAI determined that only one existing SO, source has
an impact on any of the mandatory or proposed Class I
* SAI based their S02 emission estimates on a 1979
DOE/DRI study.
** Air quality estimates can be linearly scaled because
of the type of modeling that SAI conducted. There-
fore, if emission estimates are doubled, the air
quality impact of the particular source may be
doubled.
-47-
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Exhibit 5-1
SAI AND ALTERNATIVE S02 EMISSION ESTIMATES*
Process
(size-bbl/d)
Union
(10,000)
Paraho
(55,000)
MIS
(117,000)
TOSCO II
(47,000)
Rio Blanco
(63,000)
SAI Emission Alternative
Estimate Emission Estimate
(lbs/1000 bbl) (lbs/1000 bbl)
293
60
115
158
53
216
153
381
136
190
These emission levels correspond to assumed BACT
control levels. Alternative estimates are based on
EPA technical reports and PSD oermit information.
BarSel^,per *sti?*tes nay* differ from the
production estimates listed in Exhibit 4-2. The
fu?U^eS „• e*hij3it are those that correspond to
the facility size analyzed in SPA technical reoorts
or PSD permits.
-48-
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areas in the study area. This source is the Hayden
electric generating station. The total 24-hour S07
concentration for this source ranges from 0.5 ug/m3 at
Arches National Park to 7.9 ug/m3 at Mt. Zirkel. Exhibit
5-2 summarizes Hayden*s impact on each Class I area.
Currently, the Hayden plant has no SO- control
equipment. Appendix C includes a description of this
plant, including the quantity of coal burned at the plant
and the average sulfur content of the coal.
PSD Permitted and Proposed Sources
Exhibits 5-3, 5-4, and 5-5 illustrate the air quality
impact of the facilities in Parachute Creek, Piceance
Creek, and Uinta Basin, respectively. The exhibits show
the cumulative impact of the potential sources in each
basin on the mandatory and potential Class I areas. The
impact of the three basins {Parachute, Piceance, and
Dinta) on thft Class I areas are discussed separately
because, in general, the impact of the sources in one
basin do not interact with the plumes of sources in
separate basins. Therefore, each basins' impact on the
Cl&ss X areas is independent of one another, and in some
cases these basins have cumulative effects when their
pollution overlaps at a Class I area. Exhibit 4-3 in the
last chapter lists the areas which combine to input a
Class I area. These special cases will be discussed later
in this section.
Individual sources and basins have varying impacts
depending upon the Class I area consider^. For
the cumulative impact of the Parachute Creek facilities
ranges from 1.2 ug/m3 at Rawah to 9.2 ug/m3 at Plat Tops.
If all the proposed Parachute Creek facilities were built,
increment violations would occur at Flat Tops (9.2 ug/m3),
Maroon Bells (6.0 ug/m3) and the Colorado National
Monument (7.7 ug/m3).* The cumulative impact of the
* PSD regulations specify that the Class I SO- incre-
ment ceiling is violated when the second highest
24-hour reading for the permitted sources exceeds 5.0
ug/m3.
-49
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Exhibit 5-2
IMPACT OF HA YD EN GENERATING STATION ON
CLASS I AREAS
24-Hour SO- Impact
of Hayaen*
Mandatory Class I (u
-------
Exhibit 5-3
AIR OUALITY IMPACT OF PARACHUTE CREEK FACILITIES
ON THE CLASS I AREAS
Mandatory
Class I
Flat Tops
Mt. Zirkel
Maroon
Bells
West Elk
Arches
Rawah
Eagles Nest
Rocky Mount.
Parachute Creek Facilities
(uq/m3)
Cities
gnion colony Pacific Chevron Mobil NOSR Service Total
0 7
0.4
0.9
1.4
0.7
2.0
3.1
9.2
W • '
0.1
0.1
0.2
0.3
0.1
0.5
0.7
2.0
0 4
0.3
0.6
0.9
0.4
1.3
2.1
6.0
w • ~
0 4
0.2
0.5
0.7
0.4
1.0
1.7
4.9
W I ~
0 2
0.1
0.3
0.4
0.2
0.5
1.0
2.7
V • •
0 1
0.1
0.1
0.2
0.1
0.3
0.1
1.2
V • *
0 2
0.1
0.3
0.4
0.2
0.5
1.0
2.7
w • «
0.1
0.1
0.2
0.2
0.1
0.3
0.7
1 • 7
Potential
Class I
Dinosaur
0.4
0.2
0.5
0.7
0.4
1.0
1.7
4.9
Black
Canyon
0.4
0.2
0.5
0.7
0.4
1.0
1.7
4.9
Colorado
Mbn.
0.6
0.3
0.8
1.1
0.6
1.5
2.8
7.7
-51-
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Exhibit 5-4
«, QUALITY FACILITIES
Mandatory
glass I
Plat Tops
Mt. Zirkel
Maroon
Bells
Ifest Elk
Arches
Rawah
Eagles Nest
Rocky Mount <
pirpaiice Creek Facilities.
Multi-
Occidental mineral Superior
1.7
0.7
0.7
0.7
0.3
0.3
0.3
0.3
0.7
0.2
0.3
0.2
0.1
0.1
0.1
0.1
2.2
0.6
0.8
0.7
0.5
0.3
0.6
0.4
1.8
0.4
0.7
0.4
0.4
0.4
0.4
0.4
Exxon
0.9
0.3
0.3-
0.3
0.2
0.2
0.3
0.2
Total
7.3
2.2
2.8
2.3
1.5
1.3
1.7
1.4
Potential
Class I
Dinosaur
Black
Canyon
Colorado
Mon.
1.4
0.7
1.0
0.6
0.2
0.4
1.8
0.7
1.2
1.4
0.4
1.1
0.8
0.3
0.5
6.0
2.3
4.2
52
-------
Exhibit 5-5
AXS QUALITY IMPACT OPaiSTABASIN FACILITIES
ON THE CLASS I AREAS
Mandatory
Class I
Plat Tops 0.9 0.1
Mt. Zirkel 0.4 0.1
Maroon
Bells 0.5 0.1
West Elk 0.5 0.1
Arches 1.1 0 •2
Rawah 0.3 0.0
Eagles Nest 0.4 0.1
Rocky Mount. 0.3 0.0
Uinta Basin Facilities
"" white
M---1alce wnxte Magic
Power TOSCO Seokinetics River Paraho Circle Syntana
0.3
0.0
0.0
0.0
0.3
0.0
0.0
0.0
0.1
0.1
0.1
0.1
0.1
0.0
0.1
0.0
0.5
0.3
0.3
0.3
0.5
0.3
0.3
0.3
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.3
0.1
0.2
0.2
0.3
0.1
0.1
0.1
Total
2.3
1.1
1.3
1.3
2.6
0.8
1.1
0.8
Potential
Class I
Dinosaur 2.9
Black
Canyon 0.6
Colorado
Mon. 1.4
0.4
0.1
0.2
0.7
0.0
0.3"
0.3
0.1
0.1
1.5
0.3
0.8
0.4
0.1
0.2
0.8
0.2
0.4
7.0
1.4
3.4
-53
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Piceance Creek facilities is slightly less than that of
the Parachute sources. The range of impacts varies from
1.3 ug/m3 to 7.3 ug/m3 and only the impacts at Plat Tops
and Dinosaur exceed the 24-hour SO- increment. Finally/
as Exhibit 5-5 illustrates, the Uinta facilities have a
minor impact on the mandatory Class I areas but they do
combine to violate the increment at the Dinosaur National
Monument (7.0 ug/m3).
One PSD source that has an air quality impact, the
Craig electric generating station, is not located in any
of the three basins. This station's impact on the Class I
areas ranges from 4.6 ug/m3 at both Flat Tops and Mt.
Zirkel to 0.6 ug/m3 at the Arches National Park.
As indicated in Exhibit 4-3 in the last chapter,
there are several cases where plumes from two air basins
or one of the basins and the Craig power plant will
overlap to impact a Class I area. This interaction occurs
because under certain conditions the winds cause the
plumes to travel in similar directions. The interactions
between sources must be taken into account when
determining the cumulative air quality impact in each
Class I area.
Increment Violations
Exhibit 5-6 summarizes the cases where the 24-hour
SO. increment would be violated. These violations
represent the air quality impact of all the PSD permitted
and proposed sources if they are constructed at their
proposed locations. The highest 24-hour S02 increment
reading is 10.9 ug/m3 when the Parachute and Piceance
Creek sources impact the Dinosaur National Monument. The
Flat Tops Class I area constrains the oil shale
development in the Parachute, Piceance, and Uinta Creek
basins. The highest 24-hour air quality impact at Flat
Tops would be 9.6 ug/m3 when the plumes from the Uinta and
Piceance Creek sources interact. Four other areas (Maroon
Bells, Mt. Zirkel, Colorado Monument and West Elk) would
have impacts that exceed the increment ceiling. The air
quality at the remaining mandatory and potential Class I
areas would not exceed the 5.0 ug/m3 increment when all
the sources are permitted.
-54
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Exhibit 5-6
VIOLATIONS OF THE 24-HOUR
S02 AIR QUALITY INCREMENT
Basin
Parachute
Uinta — Piceance
Piceance
Parachute — Uinta
Parachute
Uinta — Craig
Piceance — Parachute
Uinta
Piceance
Parachute
Piceance — Parachute
Class I Area
Flat Tops
Flat Tops
Flat Tops
Maroon Bells
Maroon Bells
Mt. Zirkel
Dinosaur
Dinosaur
Dinosaur
Colorado Monument
west Elk
24-Hour Air
Quality Impact
(ucr/m3)
9.2
9.6
7.3
7.3
6.0
5.7
10.9
7.0
6.0
7.7
7.2
-55-
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Growth Constraints Under FCFS Policy
To evaluate the growth that may be accommodated in
this area, it is necessary to estimate the impact of
individual sources on each Class I area where violations
occur. Assuming that the sources are granted permits in
the order of the queue shown in Exhibit 4-5 in Chapter 4,
it is possible to estimate how many sources could site
before the 5.0 ug/m3 increment is exhausted. An example
of this methodology is shown in Exhibit 5-7. The first
and second columns list the sources in the Parachute Creek
basin in the order in which they are assumed to apply for
PSD permits.* The final two columns illustrate the air
quality impact of individual sources and their cumulative
impact on Flat Tops. The impact of NOSR and Cities
Service would push the increment beyond the 5.0 ug/m3
ceiling. Under a FCFS policy these two facilities would
not be able to site. Even if the NOSR plant applied SO-
control beyond the BACT level/ it would not sufficiently
reduce its air quality impact to obtain a PSD permit.
However, if this facility scaled down its operations it
could obtain a permit.
The type of evaluation shown in this exhibit was
conducted for each mandatory and proposed Class I area.
Appendix D includes the calculations that were conducted.
Thirteen sources may not be able to obtain permits due to
one or more of the Class I areas. Two of these sources
(Mobil and Chevron) would be able to obtain permits if the
Dinosaur Monument were -not considered a Class I area.
Eight sources violate the increment at Flat Tops.
Although a number of these sources violate the increment
at other Class I areas, it is apparent that the Flat Tops
Wilderness area may be a major constraint to growth.
A third area, the Mt. Zirkel Wilderness area, might
constrain development in the Uinta basin, though accurate
air quality projections are not currently possible with
the state-of-the-art modeling procedures. The approximate
Chapter 4 established the order in which PSB assumes
the oil shale facilities would apply for PSD permits.
This list is established for illustrative purposes
only and is not intended to indicate which sources
would be able to obtain PSD permits.
56
-------
Exhibit 5-7
SOURCES WHICH CANNOT SITE DUE TO
PARACHUTE BASIN FACILITIES' IMPACT ON FLAT TOPS
Parachute Creek Order in Air Quality Impact Cumulative
Facilities Permit Queue on Flat Tops Impact
Union
Colony
Pacific
Chevron
Mobil
NOSR
Cities Service
1 0.7 0.7
2 0.4 1.1
9 0.9 2.0
14 1.4 3.4
15 0.7 4.1
17 2.0
18 3.1
©
©
Circled values represent facilities that violate the
24-hour Class I increment.
57-
-------
results from the air quality modeling conducted for this
study indicate the increment at Mt. Zirkel may be consumed
by the Craig power plant in Colorado and the Moonlake
power plant in Otah. While the Moonlake plant and unit 3
at Craig have both obtained PSD permits, units 1 and 2 at
Craig do not have PSD permits but count against the PSD
increment nonetheless.*
Even though the air quality modeling for this
analysis suggests that Uinta basin development may be
limited by possible consumption of the increment in Mt
Zirkel, one should be cognizant that this may not be the
case in reality. The Uinta basin sources are such great
distances from Mt. Zirkel that current modeling
capabilities are severely limited in predicting accurate
concentrations. The air quality contributions from these
sources at Mt. Zirkel are so small (about 0.1 ug/m*) that
any refinements^ in the modeling for either the power
plants or the oil shale facilities may change the results
considerably. Nonetheless, this analysis makes no
judgment on the validity of the modeling since there are
currently no better models available for this area.
Hence, the results from the modeling are used as is in
assessing the relative impacts of various management
option's without making arbitrary adjustments.
All six proposed oil shale sources in the Uinta basin
would violate the increment at Mt. Zirkel. The Maroon
Bells, West Elk, and Colorado Monument Class I areas also
constrain one or two of the proposed oil shale facilities.
The thirteen sources that could not obtain permits
represent nearly 75 percent of the total barrels per day
(bbl/d) of proposed shale oil development. if only
mandatory Class I areas are included, the Chevron and
Mobil facilities which would exceed the increment only at
Dinosaur would be able to obtain PSD permits. Therefore
465,000 bbl/d of production (7 of the 18 proposed sources)
could obtain PSD permits. If Dinosaur is included as a
Class I area, the allowed production would drop to 315,000
bbl/d.
. i and 2 commenced, construction before the
licable date for PSD review but after the
appiic aate for inclusion of sources in the
baseline concentration for PSD purposes.
-58-
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SO2 Control Costs
Exhibit 5-8 lists the SO- removal efficiencies and
annualized SO- control costs for the ei|£*|®n ahjJ®
facilities that are proposed for this study area. The
SSiciencies are based on BACT control
nations, and the percentages vary depend^g uj»n the
process employed. The percent removals vary from 95.0
percent for the modified-in-situ process to 99.8 percent
for Rio Blanco, annualized control costs for individual
-sources ranoe from $5.6 million at Colony to $27.6 million
11 Qcciden^l. Appendix B includes^ that
was used to derive pollution control costs for the
individual plants. Total SO- control costs would be
$192.2 million for all the facilities at a BACT control
level.
The so control costs under a FCPS policy would be
dependent o& the number and types of
that cpp site in the study area. With just the mandatory
Class I areas considered in the analysis, seven sources
can obtain PSD permits. aese sources would have armual
SO- control costs of $92.6 million. If Dinosaur is
considered a Class I area, only five sources can obtain
PSD permits and their annual S02 control costs would be
$61.9 million'.
BASE CASE SUMMARY
The first-come/ first-served PSD management approach
could constrain development of some oil shale facilities
inthe Colorado/Utah study area. The oil shale facilities
have ait cuality impacts on a number of Class X areas and,
in narticSltr, 6 of the 11 mandatory or proposed Class I
areas would exceed the increments if all sources were
located at the proposed sites.*
The Mt. Zirkel increment may have already been
consumed by two sources (Craig and Moonlake). This
situation may constrain future development in the Uinta
* The six Class I areas are: Flat Tops, Mt. Zirkel,
Dinosaur, West Elk, ifarocn Bells and Colorado
Monument.
-59-
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Exhibit 5-8
ANNUALIZED SO, CONTROL COSTS OP
PROPOSED OIL SHALE FACILITIES
AT ASSUMED BACT LEVELS
Source
Union
Colony
TOSCO
Occidental
Geokinetica
Multimineral
White River
Superior
Pacific
Paraho
Magic Circle
Rio Blanco
Exxon
Chevron
Mobil
Syntana
NOSR
Cities Service
Total
Percent of SO-
Emissions Removed
98.0
96.9
96.9
95.0
95.0
98.0
98.0
96.9
96.9
96.4
98.0
99.8
96.9
98.0
98.0
96.9
96.4
95.0
Annualized SO.
Control Coat*
(am mid-1985$)
11.5
5.6
5.7
27.6
7.9
11.5
19.2
5.7
5.7
4.6
7.8
3.5
6.5
19.2
11.5
5.7
17.8
15.2
192.2
Annualized costs include the annualized cost of the
capital to build the plants and the annual operating
costs for the plant.
-60-
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basin. Fortunately, Parachute and Piceance basin sources
do not affect Mt. Zirkel on the 3^
Moonlake plants, hence, growth in these basins is not
constrained by consumption of Mt. ZirJcel s increment.
If Dinosaur is included as a Class I area, only
315,300 bbl/d of development (five 4®|U^Q°^^2
PSD permits. If Dinosaur is not 111eluded, 465,:300 bbl/d
of development {seven sources) could PSD PJ^mits.
These seven sources could obtain permits by installing
$92.6 million (annual) in S02 pollution control equipment.
Under the current law, if more sources are to obtain
PSD permits, the following options are available to the
plants and the states:
e States could require all sources to comply with
more stringent pollution control technology,
thereby providing more increment available to
new s<56u?ces.
• Once the increment was consumed, new sources
could purchase air quality offsets to assure
that the cumulative air quality impact does not
exceed the increment ceiling.
• States could require existing sources to
retrofit SO, control, thereby lowering baseline
concentrations and providing a growth margin for
new sources.
e States could require oil shale facilities with
PSD permits to retrofit S02 control.
• New sources could obtain a variance from the
Class I increments.
MOST STRINGENT TECHNOLOGY
This option involves the application of stringent SO,
control to all sources with pending PSD permit applica-
tions. This option would allow more sources to site
before the 5.0 ug/m3 increment is consumed, but it will
increase SO, control costs for .the sources obtaining PSD
permits. Sources which have already received PSD permits
would not be required to install additional control.
-61-
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For the purposes of this analysis most stringent
technology is defined as the maximum amount of SO, removal
technically feasible. Most stringent technology is
equivalent to 99 percent SO. removal for plants utilizing
the TOSCO process, 98 percent removal for the Paraho,
Union and MIS processes, and 99.8 percent removal for the
plants using the Rio Blanco process. Stringent technology
levels for Rio Blanco and Union are the same as BACT
levels.*
Exhibit 5-9 illustrates the air quality impact of the
proposed sources on Plat Tops after they have been
adjusted for the application of more stringent technology.
Plat Tops was chosen because over half of the proposed
oil shale sources would violate the increment ceiling
under the PCPS policy. The exhibit includes the air
duality impact of the sources in each basin. The plumes
for the sources in the Uinta and Piceance basins combine
to affect Plat Tops.
The application of stringent technology to all of the
tarooosed oil shale facilities reduces the cumulative air
Quality impact of the sources in comparison to the impact
under the PCPS policy. Table 5-1 compares the air quality
impact on Plat Tops under the PCPS and a stringent
technology approach.
Table 5-1
AIR QUALITY IMPACT OF PROPOSED SOURCES ON
PLAT TOPS UNDER FCPS AND STRINGENT TECHNOLOGY
Air Quality Under Air Quality Under
Source FC^S Stringent Technology
Basin(s) (ug/m ) (uq/m3)
Parachute 9.2 6,8
Piceance 7.3 5.7
Uinta 2.3 1.7
Piceance/Uinta 9.6 7.4
The Rio Blanco and Union processes are not known t-r,
^Vr0lBiS"n contr?1 optiOM -
62
-------
Exhibit 5-9
CUMULATIVE AIR QUALITY IMPACT OF PROPOSED
SOURCES ON FLAT TOPS WITH MOST
STRINGENT TECHNOLOGY POLICY
Source
Moonlake
Union
Colony
TOSCO
Occidental'
Geokineti.cs
Multimineral.
White River
Superior
Pacific
Paraho
Magic Circle
Rio Blanco
Exxon
Chevron
Mobil Oil
Syntana
NQSR
Cities Service
Parachute Piceance
0.7
0.8
1.7
3.1
3.8
0.7
1.4
3.6
Uinta
0.9
0.9
1.0
1.1
1.5
1.6
1.7
Uinta/
Piceance
0.9
0.9
1.6
1.7
2.4
2.5
4.7
Q
Q
Circled values represent the sources which cause the 5.0
uar/si3 24-hour increment, to be exceeded.
-63
-------
The cumulative axr quality impact at Flat Tops decreases.
This is also found to be the case at other Class I areas.
However, when the air quality impact at all Class I areas
is considered, only one new oil shale facility would
obtain a permit under the most stringent technology
approach than using the FCFS policy. This one source, the
Superior 50,000 bbl/d facility, would no longer violate
the increment at the Flat Tops Class I area, if only the
mandatory Class I areas are included, this policy would
allow 515,000 bbl/d of oil shale development. This
compares to 465,000 bbl/d under the FCFS management
approach. The inclusion of Dinosaur as a Class I area
would reduce development tp 365,000 bbl/d as opposed to
315,300 bbl/d under the FCFS approach. Appendix E
includes a review of the cumulative air quality impact of
all the proposed sources on each of the mandatory, and
potential Class I areas.
Although some additional increment is available to
sources under this policy, the plants that must install
stringent control incur extra SO, control costs. Exhibit
5-10 illustrates the costs that sources would have to pay
beyond what they would spend on SO- pollution control
under the current FCFS policy. Half 6f the sources would
incur extra costs due to the most stringent technology
policy.
As the exhibit indicates, the additional costs would
be about $108.3 million annually. From a cost perspective
this policy requires that sources install additional
equipment at an earlier date than would otherwise be the
case so that there can be more air quality increment
available for future sources. The benefit of these
additional costs is extremely small? only one additional
oil shale facility can obtain a PSD permit.
AIR QUALITY OFFSETS
In many areas of the countrv
permitted emission sources can anrjlv PSD-
control that would allow more increment +¦« k S02
for new sources. In this study area the w^/Vailabl
plant and the Craig plant (units 1 4 2) P°wer
sources of potential offsets for the oil * .®. "^or
s«aie facilities.
-64-
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Exhibit 5-10
ANNUALIZED COST COMPARISON BETWEEN FCFS PSD POLICY
AND MOST STRINGENT TECHNOLOGY POLICIES*
(mm oid-1985$)
Source
Cost of SO, Cost of SO- Additional
Control Under Control Under Costs of
FCFS PSD Most Stringent Most Stringent
Policy Technology Technology Policy
Union
Colony
Occidental
Multimineral
Superior
Pacific
Chevron
Mobil
11.5
5.6
27.6
11.5
**
5.7
19.2
11.5
11.5
11.7
111.5
11.5
12.0
12.0
19.2
11.5
6.1
83.9
12.0
6.3
92.6
200.9
108.3
* This exhibit includes the sources that can obtain
permits when the mandatory Class I areas are
evaluated. The inclusion of Dinosaur as a Class I
area would cause the Chevron and Mobil facilities to
exceed the 24-hour S02 increment at Dinosaur.
** Superior cannot obtain a permit under the FCFS
policy.
-65-
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Unit 3 of the Craig plant and the Moonlake generating
station cannot install additional control.* The Colony
oil shale facility has received a PSD permit and could
install additional control but the accompanying reduction
in air quality impact at all Class I areas would be
minimal. Hence, Colony is not a likely offset supplier.
An analysis of SAI's air quality modeling results
indicates that the Hayden and Craig plants could provide
substantial offsets to sources in the Uinta basin if the
need arises.
The PSD policy of choosing the second worst day to
calculate an increment violation complicates the offset
trading process. Concentrations in excess of 5.0 ug/m3
can occur at both different Class I areas and on different
days. Thus, offsets axe both time and location dependent.
For example, the Hayden plant has a significant impact on
Flat Tops but little impact on Arches. A PSD applicant,
on the other hand, might have an impact on both Class I
areas. By purchasing emission reductions from Hayden, the
applicant could offset its impact on Flat Tops, but would
have to find a different source of offsets for it's impact
on Arches.
The situation is further complicated by the day on
which the increment is exceeded. A given location might
experience three days per year when concentrations exceed
5.0 ug/m3. An existing source might have an impact on a
Class I area during one of these days, but not on the
other two. Therefore, the existing source could serve as
a source of offsets on only one of the three days of
violation. Furthermore, the location and day of the
second highest concentration may change as new sources are
added to the area. To obtain a permit a new source must
ensure that the SO. increment on the second worst day at
all locations wilr not exceed 5.0 ug/m3. When a new
source would cause increments to be exceeded on a number
of days and at several locations, offset trading may
involve several sources and could become quite
complicated.
Unit 3 at the Craig plant plans to install dry
scrubbing at 88 percent SO. removal efficiency. The
Moonlake PSD permit states that this plant will
comply with 94 percent control. These requirements
represent maximum control capabilities.
-------
Nevertheless, an offset policy may provide the needed
air quality reductions to enable additional sources to
obtain PSD permits. As discussed previously, Flat T?£®'
Mt. Zirkel, and Dinosaur are the critical ^eas that
constrain the majority of the oil sihale development. No
source in the area could provide offsets for Flat Tops or
Dinosaur. This conclusion is based on the fact that the
Hayden and Craig plants could
when sources in the Parachute and Piceance basins would
exceed the increment at these two Class I areas.
offsets can be an effective strategy for the Uinta
basin sources which would exceed toe Mt. Zirkel increment
ceilino This is due to the interaction of the Uinta
sources'and two power plants. ^e_5"hlve 1ShaistedS the
2, and 3) and the Moonlake plant may have exhausted the
allowable increment at Mt. frkel^* ^
facilitv located in the Uinta basin which had an impact on
theMt.Zirkel Class I area could alVP!2d
If Craig or the Hayden plant were to install additional
SO, control this would ^
enlble new oil shale facilities to ob^in PSD permits.
Table 5-2 illustrates the increments that could be
available for offset purchases.
Source
Hayden
Craig
Table 5-2
AVAILABLE OFFSETS FROM HAYDEN AND
CSAIG AT MT. ZIRKEL
Current
SO
Current Air
Quality Potential
Impact on SO.
SO, impact ou su.
Control Mt. Zirkel Control
<11
0
75
(ug/m3)
7.9
4.6
(%)
60
85
Potential
Offsets
(ug/m3)
4.7
1.8
* As has been noted, the Colony plant in the Parachute
Creek basin can install additional control, but this
additional control would not decrease the increment
significantly in these three Class I areas.
** See Appendix D, Exhibit D-4.
67-
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The Hayden plant currently has no SO- control equip-
ment in place. It is assumed that tnis plaint could
retrofit control equipment that would operate at a 60
percent rate of removal efficiency. The cost of this
equipment would be $11.8 million on an annual basis.
Hayden could also install control to meet less strict
removal rates. For example, Hayden could install 30
percent control at an annual cost of $5.7 million.. The
Craig unit has proposed SO- control of 75 percent SO.
removal. The plant could upgrade its scrubber to operate
at 85 percent efficiency. The cost of additional control
would be $5.45 million annually. Appendix C describes the
methodology used to estimate pollution control costs for
utility plants.
If it is assumed that the Hayden or Craig plants
would require a 10 percent return on the cost of any
pollution control equipment they installed,*- then oil
shale sources could reduce their air quality impact on Mt.
Zirkel by purchasing offsets that would be equivalent to
the pollution control costs and the required return. In
this case the Hayden plant could provide the least-
expensive offsets. At 60 percent control, Hayden could
supply 4.7 ug/m3 of offset for $13 million, or $2.77
million per microgram of increment. The Craig plant would
provide offsets at an incremental cost of $3.33 million
per microgram.
The purchase -of offsets from the Hayden or Craig
plants by the Uinta oil shale sources would alleviate the
pressure on the increment ceiling at Mt. Zirkel. In fact,
the Hayden plant would only have to install 30 percent
control ($5.7 million) to accommodate all six of the oil
shale sources. However, several of these oil shale
sources would still contribute to a violation at other
Class I areas. For example, if the Paraho facility
purchased an offset from the Hayden plant so that its
impact on Mt. Zirkel would be below the increment ceiling
PHB recognises that a 10 percent return may be a
conservative estimate of the actual premium that
offsets may command. If the demand is high or the
supply small, offsets may require a much higher
premium.
68-
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it would still exceed the increment at Flat Tops. Thus,
Paraho would not be able to obtain a permit without
another offset at Flat Tops. Three Uinta basin sources
have increment violations at only the Ht. Zirkel Class I
area. Therefore, if these sources purchased offsets, they
would be granted PSD permits because they would no longer
violate a Class I increment.
Table 5-3 illustrates the difference between the FCFS
policy and a FCFS with offsets.
Table 5-3
COMPARISON OF FCFS POLICY
WITH OFFSET OPTION
SO, Control Costs
(mm 1985$)
Air Quality Impact
(ug/m3)
Number of Sources
Permitted
(Thousand bbl/d)
FCFS Policy
92.6
5.0
7
(465)
FCFS with Offsets
126.7
5.0
10
(635)
The SO- control cost increases by $39.1 million due to the
cost df the offsets and the SO- control cost of the
additional sources that can obtain PSD permits. The air
quality would be maintained under each approach. The SO-
increment would be consumed at the Flat Tops and Mt:
Zirkel Class I areas, and additional increment would be
available at the other parks and wilderness areas. The
significant difference is that three additional oil shale
facilities could obtain PSD permits if an offset trading
market were implemented. This table is based on the
sources that could be permitted with only the mandatory
Class I areas in the analysis. If Dinosaur were consid-
ered a Class I area, five sources (315,000 bbl/d) instead
of eight sources (485,000 bbl/d) could obtain PSD permits.
69-
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RETROFIT OF EXISTING SOURCES
Existing emission sources can retrofit SO- control
equipment on their plants and increase the available SO-
air quality increment* Individual sources would install
this equipment if an air quality offset is purchased or if
the additional control is mandated by the state. As
illustrated previously, the only major existing SO.
emission source in the oil shale area is the Hayden power
plant. This source currently has no SO- control. Hayden
could retrofit SO- control equipment are several control
levels. As indicated, a 60 or a 30 percent removal
efficiency could be achieved at an annual cost of $11.8
and $5.7 million, respectively.
Reducing the air quality impact of the Hayden plant
would provide additional increments for oil shale
development, Hayden and the following sources interact to
impact different Class I areas:
• Uinta basin sources and Hayden impact Mt.
Zirkel,
• Uinta basin sources and Hayden impact Rawah, and
• Piceance Creek sources and Hayden impact Arches.
Exhibits 5-3, 5-4, and 5-5 showed that, even with all
of the proposed sources permitted, the increment ceiling
is not violated at either Rawah or Arches. Therefore, the
only sources that would require, and could obtain, offsets
would be the Uinta basin sources when they impact Mt.
Zirkel. By retrofitting 30 percent control the Hayden
plant would provide the necessary additional increment for
the sources in the Uinta basin.
This PSD management option allows the same sources to
receive permits as the offset approach. The difference
between the options is that the cost of installing retro-
fit control is borne by the Hayden facility and not by the
sources who would purchase offsets. Three additional
sources would be allowed to obtain PSD permits if this
option were implemented.*
Three sources (Paraho, Magic Circle, and Syntana)
also would no longer violate the increment at Mt.
Zirkel, however they would not receive a permit
because they violate the increment at Flat Tops.
-70-
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RETROFIT OF OIL SHALE SOURCES
A second retrofit option would be to mandate that
additional pollution control be retrofitted to oil shale
facilities that had already received PSD permits. This
option would be implemented after the increment was
consumed. The rationale for this approach is that the
current facilities should not have to install excessive
control until the increment ceiling is reached. Second,
there is tremendous uncertainty involved in the current
emission estimates for the oil shale facilities. If the
estimates have been incorrect, it may be necessary for the
state to require that additional control be added. This
option, particularly if the ceiling were never reached,
would be preferable to a most stringent technology
approach because the facilities would not be forced to
over control their SO2 emissions.
The retrofit of oil shale facilities would provide
the same outcome as.the most stringent technology option,
namely that one additional source could obtain a permit.
However, if the retrofit were not implemented until the
PSD increment was consumed, it may be preferable to the
most stringent technology option since additional
investment and annual operating costs would be delayed.
This option would be cheaper as long as the discounted
cost of retrofitting sources is less than the incremental
cost of most stringent technology.
VARIANCE APPROACH
In the event that the Class I increments do pose a
constraint on energy development, the Act does provide two
mechanisms in Section 165(d) by which sources may be
granted waivers to Class I increments.
It is difficult to predict with any certainty how
much additional growth would be possible under the var-
iance approach because many decisions involve discre-
tionary judgment by the FLM or the governor. However, it
should be noted that the 24-hour SO- increment of 91 ug/m3
specified in Section 165(d)(2)(dl is 18 times less
stringent than the Class I SO, increment of 5.0 ug/m3.
This implies that as long a& Gie FLM certifies that new
sources do not adversely affect air-quality-related
values, emissions in the oil shale region could grow
71-
-------
substantially while the air quality would still remain
well below the health-based primary standard.
Analysis of Section 165(a)(2)(d) showed that the
requirement which would allow the increment to be exceeaea
18 days per year (rather than just once per year) wouia oe
more restrictive than the special increments for
high-terrain areas.
A log normal distribution was fit to air quality
modeling data to estimate the impact on the eighteentn
highest day for the proposed sources. When the increment
reaches the 5.0 ug/m* ceiling on the eighteenth worst day/
the air quality on the second worst day ran
-------
Summary of the PSO Management Options
Allowed Under Current Law
The analysis of the base case or current PSD policy
indicates that a first-come/ first-served approach,
without any variations, may constrain oil shale
development. The air quality impact of eleven of the
proposed eighteen oil shale facilities would exceed the
allowable increment at one or more of the mandatory Class
I areas. These plants would be denied a PSD permit and
only 465,000 bbl/d of development could be sited. If the
proposed Class I areas are included in the analysis,
thirteen sources would exceed the allowable increment.
The five facilities that could receive permits would
account for 315,000 bbl/d of oil shale production.
Under current law individual plants and the state
have a number of options once the increment is consumed.
Exhibits 5-U. and 5-12 compare these options on the basis
of SO. control cost, air quality impact and the number of
sources that could be permitted. Exhibit 5-11 compares
the options when the mandatory Class I areas are con-
sidered while Exhibit 5-12 compares the options when the
potential Class I areas are included with the mandatory
areas.
Only one option under the current law (variances)
would allow all (or most) of the proposed oil shale
facilities to obtain PSD permits. The application of
most stringent technology would more than double the SOj
control costs from the current policy but only one
additional source would be able to obtain a PSD permit.
Several additional conclusions can be highlighted as a
result of this analysis:
• The current FCFS policy will maintain air
quality at or below the Class I increment. But
some oil shale facilities may need to receive
variances to obtain PSD permits.
• If an offset trading market is developed, an
additional three sources could receive PSD
permits. The offsets required could be obtained
from the Hayden power plant.
-73
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Exhibit 5-11
COMPARISON OF ALTERNATIVE MANAGEMENT OPTIONS TO
CURRENT FCFS POLICY IN THE MANDATORY CLASS I AREAS
Alternatives Under
Current Lav
Allowed
Air Quality Oil Shale
Coats (mm Impact* Production**
mid-1985$) (uq/a*) (000)
SO.
Control
Current FCFS Policy
without Offsets
offsets
Retrofit Existing
Variance
92.6
126.7
126.1
177.0-192.2
5.0
5.0
5.0
9.30-12
465 (7)
635 (10)
635 (10)
1190-1240+
(17-18+)
Most Stringent
Technology
200.9
5.0
515 (8)
* The increment shown in this table represents the air
quality at the Class I area with the highest so
concentration. 2
** The figure in parentheses represents the number of
oil shale facilities that could obtain permits.
-74-
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Exhibit 5-12
COMPARISON OF ALTERNATIVE MANAGEMENT OPTIONS
TO CURRENT FCFS POLICY IN THE
MANDATORY AND POTENTIAL CLASS I AREAS
Alternatives Under
Current Law
SO,
Control
Costs (mm
mid-1985$)
Allowed
Air Quality Oil Shale
Impacts* Production**
(uq/m3) (000)
Current FCFS Policy
Offsets
Retrofit
Variance
Most Stringent
Technology
61.9
101.0
98.8
177.0-192.2
170.2
Increment Reservation, NQ
and Local Preference -
5.0
5.0
5.0
9.70-12
5.0
NQ
315 (5)
485* (8)
485 (8)
1190-1240+
(17-18+)
365 (6)
NQ
NQ * Not Quantifiable.
The increment shown in.this table represents the air
quality at the Class I area with the highest SO,
concentration. 2
The figure in parentheses- represents the number of
oil shale facilities that could obtain permits.
-75-
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The retrofit of existing sources, assuming a
coordinated Utah-Colorado policy, would result
in the same air quality impact and number of
sources permitted as the offset option. Tne
difference in the approaches is that an offset
policy forces the sources needing the increment
to pay for the offset while a retrofit approach
forces the existing facility to pay the retrofit
costs.
Two additional sources would not be able to
obtain PSD permits if the Dinosaur National
Monument is included as a Class I area. These
two sources represent 150,000 bbl/d of lost
production. Under all of the alternative manage-
ment options (except the variance approach) the
inclusion of Dinosaur as a mandatory Class I
area results in two fewer permitted oil shale
-76-
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EVALUATION OF ALTERNATIVE APPROACHES
TO CURRENT PSD PROGRAM
CHAPTER 6
Changes in the Clean Air Act may allow for some
alternative approaches to the prevention of significant
deterioration. Such changes are only speculative at this
time, and the approaches studied here include only a few
possible alternatives. They are:
• Eliminate short-term increments but retain the
annual increment,
• Eliminate short-term increment tracking, and
• Replace the Class I increment with BACT require-
ment.
ANNUAL AIR QUALITY INCREMENT
This approach would do away with the short-term
increments and retain only an annual increment. This
approach would require that the Clean Air Act be amended.
The justification for this change is: 1) the annual
increment would protect the long-term air quality at the
park without needlessly constraining new industrial
development; and 2) modeling short-term increments is
difficult and uncertain.
SAI, Inc. conducted the air quality modeling required
to estimate the impact of existing sources, PSD permitted
sources and proposed sources for the study area. Exhibit
6-1 lists the annual average SO^ concentrations for each
-------
Exhibit 6-1
ESTIMATED ANNUAL AVERAGE SO, CONCENTRATIONS
AT MANDATORY AND POTENTIAL CLASS I AREAS
PROM PROJECTED ENERGY DEVELOPMENT
Mandatory Annual Average Concentrations
Class I Areas tug/a3)— —
Plat Tops
Mt. Zirkel ?•"
Maroon Bells u.13
West Elk
Arches
Rawah
Eagles Nest . ..
Rocky Mountain u.n
0.10
0.04
0.09
0.12
Potential
Class I Areas
Dinosaur
0.07
Black Canyon 2*?!
Colorado Monument
0.16
-78
-------
$L2L^nd4t.°rL^'?,^nti™ C.la,s 1 »•" totals
represent the cumulative impact of all of the PSD and
proposed sources. The basins in whiiE"-these sources are
located are combined in this analysis because all sources
will impact the Class I areas during the course of the
year.
n « Th®/ W* ann^f1 S02. concentration would be
0.62 ug/m3 the Plat Tops Class t area. The remaining
Class I areas have annual concentrations ranoino from 0.04
at Arches to 0.33 ug/m3 at Mt. Zirkel. Because the annual
increment ceiling is 2.0 ug/m*, it appears that all of the
proposed oil shale facilities and substantial future
growth could be accommodated if the Clean Air Act were
changed to eliminate the short-term increments.
While this alternative represents a substantial
relaxation to the existing program, it still would result
in the sources contributing very low absolute concentra-
tions to the mandatory and potential Class I areas. If
all of the sources obtained permits, maximum total
average SO- concentrations, including the existing Hayden
facility, Vould be 0.68 ug/m3. The highest second day
24-hour concentration would be 13.6 ug/m3.*
ELIMINATION OF SHORT-TERM
INCREMENT TRACKING
A similar option which is currently under
consideration by Congress would be to evaluate the
cumulative air quality impact with respect to the annual
increment and eliminate the comparison of cumulative air
quality impact with short-term increments. However, the
impact of any source would be evaluated with respect to
the short-teem increments. No source examined in this
study (with their currently proposed controls) would have
an air quality impact exceeding 5.0 ug/m3 — the 24-hour
* This 24-hour SO, air quality impact occurs when the
Uinta Basin, Craig and Hayden sources interact to
impact Mt. Zirkel. Hayden is responsible for 7.9
ug/m3 of this total impact.
-79-
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SO, increment.* Hence, the impact of this option would be
the same as the annual increment option.
BACT CONTROL WITH MO
CLASS I INCREMENT
This option assuaes there would J1® no ^ *S
increments. To receive a permit, sources wov* emalitv
comply with BACT requirements. Obviously no would nQt
offsets would need to be purchased and plants receive
have to apply for air quality vari^f! be denied a
permits. Under this option no source would ae
permit provided it met the BACT requirements.
Exhibit 6-2 summarizes the difference xnA*the BACT
current first-come, first-served PSD „nir"
policy. Their differences include the aimual SO,«n^roi
costs * deterioration of air quality "d the aunoer
sources that can receive a permit.
If no PSD Class I increment policy
control costs would be increased by clos® t permits]
However, all sources^ would ^ ^ deterioration of the
Accompanying this growth would be a amfTxa _. QSaur ig
air quality in the Class I areas. . * litv impact
considered a Class I area the maximum air qu . .
would be 10.9 ug/»>. The xap
mandatory Class I area would be ug/»
The BACT alternative requires uali ®?urces W «j*«t a
technology standard. This places 8 J** a individual
on all sources. The current FCFS policy fort:es i>ndlvldaal
sources to pay for additional control beyond BA¦
ments once the increment is consumed. .Hence, the
incremental costs of the current policy are b°fjV £.15
sources seeking to obtain permits. On the otiwr hand,
existing sources incur no costs due to the cjj**• P
and could actually benefit since they nay era a return b/
selling offsets. Therefore, it appears that the BACT
policy is more equitable than the current policy.
impact* wfaict^ Jc«dt 5 , but o"y*M»
are included in this analysis.
-80
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Exhibit 6-2
COMPARISON OF BASE CASE AND BACT
POLICY OPTION FOR PROPOSED SOURCES
IN THE STUDY AREA
Current FCFS Current FCFS
Policy Policy
(only mandatory (mandatory and
Class I potential
Areas) Class I areas)
Annual Cost
(mm$)
92.6
61.9
BACT
Policy**
192.2
Maximum Deteri-
oration of
Class I Air
Quality (ug/m3) 5.0
Oil Shale
Production 465
Permitted* (7)
(M bbl/d)
5.0
315
(5)
10.9
1240
(18)
* The figures in parentheses represent the number of
sources which could obtain PSD permits.
** The BACT policy would allow for development until the
secondary NAAQS. The cost, air quality and production
estimates are representative of just the currently
proposed facilities.
-81-
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However, the drawback is that a certain amount of air
quality is sacrificed.
As additional sources are added , the cost and air
quality differential will increase. Given the existing
number of sources that are seeking to develop oil shale
reserves, the 24-hour SO, increment would increase to 9.6
ug/m3 at Plat Tops and TO.9 ug/m3 at Dinosaur. The BACT
policy would allow for future growth up to the secondary
HAAQS in the area while the current PSD policy may limit
growth but would not allow air quality in Class I areas to
exceed the increment.
SUMMARY
Exhibit 6-3 summarizes the differences.
current first-come, first-served 5SD n?H ™
alternatives to the Clean Air Act. The current P°1
would allow for the fewest sources to become permitted and
therefore the SO, control costs would be low. Tne annual
increment approach and the elimination of jm rt-term
tracking approach would allow for additional sources to
become penStted, while a BACT policy would allow for
unlimited growth.
All three of these alternatives would
quality to exceed the 24-hour increment. "I.
currently proposed sources, short-term air quality could
deteriorate to 9.6 ug/m* at Flat Tops and 10.9 ug/m at
Dinosaur. There is a clear tradeoff between the number of
sources that can be granted permits and the short-term air
quality in Class I areas.
-82-
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Exhibit 6-3
COMPARISON OP ALTERNATIVES TO THE CLEAN AIR ACT WITH
THE FCFS PSD POLICY FOR THE PROPOSED
OIL SHALE FACILITIES
SO- Control
Cost
(mm 1985$)
FCFS Policy 92.6
Annual Increment 192.2
Elimination of
Short-Term
Tracking 192.2
BACT 192.2
Deterioration of
Class I Air Quality Sources
(uq/m3) Permitted
5.0 1
9.60 - 10.9 18+
9.60 - 10.9 18+
9.60 - 10.9 18+
83-
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SUMMARY AND CONCLUSIONS
CHAPTER 7
This report has focused on alternative policies for
granting permit#- to new sources of air pollution located
near national parks and wilderness areas. The current PSD
policy may limit the development of energy sources that
are located near these areas. This chapter includes a
review of the caveats and limitations of the analysis, a
summary of the results of the analysis and a strategy that
may reconcile the tradeoff between oil shale development
and air quality deterioration. The results of the
analysis will be illustrated by comparing the SO. control
costs, air quality impact and development implications of
the alternative management options to the current
first-come, first-served policy approach.
CAVEATS AND LIMITATIONS
OF THE ANALYSIS
The major limitation to this analysis is that the
database of information on oil shale processes is
extremely limited. Information in the following areas was
difficult to quantify:
• The SO. emissions and air quality impact of the
individual oil shale facilities,
• The pollution control costs for oil shale
facilities, and
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• The proposed development of oil shale sources
and the order in which individual plants would
apply for permits.
This section will discuss each of these data problems and
illustrate how the uncertainty would affect the conclu-
sions of the study.
SO. EMISSIONS AND
AIR QUALITY
At this time, so. emission estimates for individual
oil shale facilities are very difficult to determine.
Because no full scale plants have been built, estimates of
air emissions must be based on design information, pilot
plant tests and laboratory studies. Furthermore, many
sources have not chosen the exact shale-processing
technology they will use. Where possible, PHB used
emission-based design information from the PSD permits or
from information supplied by EPA personnel. This appears
to be the most current and dependable data that is
available. Emission estimates, though still somewhat
uncertain, have been refined through studies by the
companies and EPA.
An example of the uncertainty associated with SO.
emission estimates concerns the question of whether oil
shale facilities will include refinery operations on site.
Virtually all reports on emission estimates have indicated
that full-scale refining of shale oil will occur off site
and these emissions are not included in the oil shale
estimates. However, available PSD permit information
indicates that the Union facility will have a full-scale
refining operation on site. This same information
indicated that SO, emissions from the refinery would
account for approximately 10 percent of total plant SO.
emissions. Increasing emissions by 10 percent at all
plants using the Union process would not change our
conclusions regarding the impacts of the current PSD
policy. If all oil shale plants were to include
full-scale refining emissions, and the refinery emissions
were larger than expected, this could alter several of the
conclusions.
As discussed in Chapter 5 there are a number of
caveats pertaining to the air quality modeling that was
85-
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J™ SAI-. caveats illustrate that, even using
5?? 52 sophisticated air quality models, the results are
far from certain. The combination of the uncertain stack
parameters for the facilities along with the complex
terrain in this study area makes any air quality results
speculative Coupling the preliminary emission estimates.
Yuj cru^e quality modeling is a serious handicap for
this analysis.
POLLUTION CONTROL COSTS
The lack of data on individual plant SO- control
costs is due to an absence of operational experience with
control equipment for this new technology. PHB attempted
to obtain cost estimates for several control levels for
each type of oil shale process. Estimates were obtained
from PSD permit information and EPA documents. This data,
although limited, was used to illustrate the cost
differences between options. This information helps
determine the relative differences in cost between options
but should not be used to base any decision regarding the
cost of control at individual sources.
PROPOSED DEVELOPMENT AND
ORDER OP PRODUCTION QUEUE
_ results of this study are most useful for
comparing alternative PSD management options and not for
determining which sources would be able to obtain PSD
permits. This caveat is based on the fact that it is
nearly impossible to determine in what order individual
sources will file for permits and in fact whether some
sources will ever commence construction. Because of the
tremendous uncertainty involved in process technology and
financial structure of this industry it is purely
speculative to develop any type of production forecast and
permit queues. The conclusions of this study should not
be construed to indicate which sources would obtain
permits, rather, the focus is to indicate which
alternatives would facilitate oil shale development and
maintenance of air quality in Class I areas.
These three general limitations of the analysis ar®
substantial but they do not detract from the overall
86-
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conclusion of the analysis. The exact number of oil shale
barrels per day which can be permitted cannot be
accurately predicted. However, alternative PSD management
options can still be compared and an optimal permitting
strategy can be devised.
RESULTS OP THE ANALYSIS
Exhibit 7-1 lists the PSD management alternatives
that PHB has evaluated. These alternatives can be grouped
into those that are allowed under current law and those
that require changes to the Clean Air Act. As can be seen
in the exhibit, only four options allow for the majority
of the eighteen oil shale sources to obtain a PSD permit
in the study area: variance, annual increment/ elimina-
tion of short-term tracking, and BACT. This exhibit
summarizes the results of each option in relation to the
mandatory Class I areas. Exhibit 7-2 reviews the same
alternatives but it includes the potential Class I areas
along with the mandatory areas, tinder current law only
the variance approach would allow for the majority of
facilities to obtain permits. Each of the t
approaches and the BACT option would also allow all
sources to receive a permit. Exhibit 7-3 lists the
barrels per day of production that could be accommodated
under each alternative.
The BACT approach would offer growth potential until
the secondary NAAQS was reached, while the most stringent
technology, offset and retrofit options would allow for a
limited amount of production beyond the current FCPS
policy. It is apparent from evaluating Exhibits 7-1 and
7-2 that no options would accommodate all the proposed
development and maintain the air quality at the Class I
areas. The options that facilitate the permitting of all
source# allow the air quality to deteriorate. Conversely,
the alternatives that maintain air quality limit growth,
in an effort to reconcile this conflict PHB evaluated a
combination of the variance and offset management options.
VARIANCE/OFFSET COMBINATIONS
The three mandatory and potential Class I
constrain the majority of the oil shale
Plat Tops, Mt. Zirkel and Dinosaur (proposed) ^arks, \cne
-87-
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Exhibit 7-1
COMPARISON OF ALTERNATIVE MANAGEMENT
OPTIONS IN THE MANDATORY CLASS I AREAS
Alternatives Allowed
bv Current Law
Current FCFS Policy
without Offsets
Most Stringent
Technology
Offsets
Retrofit Existing
Retrofit Permitted
Sources
Variance
Increment Reservation/
Local Preference
SO.
Control
Costs* (mm
mid-1985$)
92.6
200.9
126.7
126.1
200.9
177.0^192.2
NQ
Number of
Air Quality Oil Shale
Impact Sources
(ucr/a») Permitted
5.0 7
5.0
5.0
5.0
5.0
9.30-12.05
NQ
8
10
10
8
17-18+
NQ
Alternatives Requiring
Changes to Current Law
Annual Increment
Annual—Elimination of
Short-Term Tracking
8ACT
192.2
192.2
192.2
9.6
9.6
9.6
18+
18+
18+
NQ ¦ Not quantifiable.
Annulls* co.t» inciud. - th. ,7^^' °;it^
capital to build the plants and the annual operating
costs for the plant.
-88
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Exhibit 7-2
COMPARISON OF ALTERNATIVE MANAGEMENT
OPTIONS TO CURRENT FCFS POLICY IN THE
MANDATORY AND POTENTIAL CLASS I AREAS
Alternatives Under
Current Law
Current FCFS Policy
without Offsets
Most Stringent
Technology
Offsets
Retrofit Existing
Retrofit Permitted
Sources
Variance
Increment Reservation,
Local Preference
Control
Costs* (mm
mld-1985$)
61.9
170.2
101.0
98.7
170.2
177.0-192.2
NQ
Number of
Air Quality Oil Shale
Impact Sources
(ug/m*) Permitted
5.0 5
5.0
5.0
5.0
5.0
9.70-12.05
NQ
6
8
8
6
17-18+
NQ
Alternatives Requiring
Changes to Current Law
Annual Increment
Annual—Elimination of
Short-Term Tracking
BACT
NQ ¦ Not quantifiable.
192.2
192.2
192.2
10.9
10.9
10.9
18+
18+
18+
Annualized costs include . the annuaH
capital to build the plants and coat of
costs for the plant. annual operating
-89
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Exhibit 7-3
POTENTIAL OIL SHALE PRODUCTION
UNDER PSD ALTERNATIVE OPTIONS
Alternative
Potential Production
Including Mandatory
Class I Areas
(Thousands bbl/d)
Potential Production
Including Mandatory
and Potential
Class I Areas
(Thousands bbl/d)
Current FCFS Policy
Most Stringent
Technology
Offsets
Retrofit Existing
Retrofit Permitted
Sources
Variance
Annual Increment
Annual—Elimination
of Short-Term
Tracking
BACT
465
515
635
635
515
1190-1240
1240+
1240+
1240+
315
365
485
485
365
1190-1240
1240+
1240+
1240+
90-
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of the alternatives allowed under current law except the
variance option would allow for more than ten oil shale
facilities to receive permits. Zf variances were allowed
for sources at Flat Tops only, the air quality would be
maintained at the remaining ten mandatory and potential
Class X areas and no sources would be denied due to Flat
Tops. The maximum 24-hour SO. concentration with all
sources permitted would be 9.6 ug/m3 at the park.
The Ht. Zirkel Class I area may constrain the
development of the oil shale plants that are located in
the Uinta basin. Those sources can obtain air quality
offsets at a relatively low cost from either the Hayden or
the Craig electric generating stations. If offsets were
purchased by these sources, the Mt. Zirkel Class I area
would not act aft a constraint to development.
If this combination approach were implemented, and
only the mandatory Class 1 areas were included in the
evaluation, sixteen of the eighteen oil shale plants
representing 990 Mbbl/d could obtain PSD permits and only
the air quality at Flat Tops would deteriorate beyond the
5.0 ug/m3 increment.* This alternative helps to form a
compromise between the goal of allowing development and
maintaining the air quality at Class I areas.
A problem arises when the proposed Class I areas are
included in the evaluation. Although Black Canyon and the
Colorado Monument do not act as constraints to growth, the
Dinosaur National Monument would constrain half of the
proposed sources under a FCFS option. No offsets or
retrofit of sources would allow for additional growth.
Therefore, even with variances allowed for Flat Tops and
offsets purchased for sources impacting Mt. Zirkel, the
inclusion of Dinosaur would limit oil shale development to
nine sources and 535,000 bbl/d. If variances were granted
for the sources that violate the increment at Dinosaur or
if Dinosaur were not considered a Class I area, this
combination of options would allow sixteen sources to
obtain permits with an annual production of nearly one
million barrels per day.
The Maroon Bells and West Elk Class I areas would act
as a constraint to the remaining two. No offsets or
retrofit of sources would alleviate this constraint.
-91
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CONCLUSIONS
Having discussed the combination variance/offset
approach and after evaluation of the other alternatives,
the following conclusions can be mades
e Air quality modeling indicates that all of the
proposed oil shale facilities in the Colorado/
Utah study area could not receive PSD permits
without violating the Class Z increments at one
or more Class I areas. Under the current FCFS
policy, only 465,000 barrels per day of
development (seven sources) could obtain PSD
permits when the mandatory Class I areas are
considered. If the Dinosaur National Monument
is included as a Class I area, only 315,000
bbl/d (five sources) could obtain permits. Two
power plants which have already obtained psd
permits have consumed the Class X increment at
the Mt. Zirkel Wilderness area. Future oil
shale development in the Uinta basin will be
constrained unless variances or offset can be
obtained.
• The combination of the variance and offset
approaches would help to maintain the air
quality at the majority of the Class X areas and
it would allow substantial development. If
variances were allowed for only the Flat Tops
Class X area and offset trading was encouraged
for the sources that violate the increment at
Mt. Zirkel, sixteen oil shale sources (one
million bbl/d) could obtain PSD permits. This
conclusion assumes that the Dinosaur area is not
considered a Class I area. If the Dinosaur
Monument is included as a Class X area, it would
constrain development to 535,000 bbl/d even with
variances and offsets at Flat Tops and Mt.
Zirkel. Additional variances for sources
violating the increment at Dinosaur would be
required or development would be constrained.
e Due to the small number of sources in the area,
there is a limited amount of air quality offsets
available for new sources. The purcha*e of
offsets would allow three additional oil shale
facilities to obtain PSD permits. Oil shale
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development would therefore be 635,000 bbl/d or
485/000 bbl/d if Dinosaur is included as a Class
Z area.
If the state required existing emission sources
to retrofit SO- controls, the maximum oil shale
production would be identical to the 'offset
approach. The primary difference between the
two options is that under an offset approach the
sources that require permits pay for the pollu-
tion control, while under a retrofit strategy
the existing source must pay for the necessary
equipment. The evaluation of this retrofit
approach assumed that the states of Colorado and
Utah would enact a consistent retrofit .strategy.
Other PSD management approaches allowed by
current law, including most stringent technology
and increment reservation, would also limit oil
shale development and would place significant
additional costs on the sources that could
obtain permits. For example, if more stringent
technology were required for all sources, only
one additional source (beyond the current
first-come, first-served strategy) would receive
a permit. The costs of installing stringent
technology ^would approximately double the costs
of installing BACT control. Total annualized
eosts for pollution control for ^ the permitted
souraes would increase from $92.6 to 5200.9
million.
A final option allowed under current law, the
granting of Class I variances, would allow the
majority of proposed oil shale sources to obtain
IS© permits. This development would be
aceeopaaied by higher SO, concentrations at the
Class I areas. It is difficult to quantify how
much growth could take place under a variance
approach since Section 165(d) calls on the
federal land manager of the park, and in certain
cases, the governor of the state or the presi-
dent, to make subjective decisions regarding the
impact on air-quality-related values in these
areas. However, under the requirements of the
variance procedures, * minimum of nearly
UloSrSo- bbl/d of oil shale development could
•£ke place. This - amount of growth would
-?3
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correspond to a 24-hour SO- concentration of
approximately 9.6 ug/ma at Plat Tops and 10.9
ug/m3 at the Dinosaur National Monument.
• Elimination of short-term increments while
retaining the annual increment would also allow
more energy development to take place in the
region. If all the proposed sources were to
obtain PSD permits, the highest increment
reading would be 0.62 ug/m3 at Flat Tops. The
coinciding 24-hour increment at Flat Tops would
be 9.6 ug/m3. The elimination of short-term
increment tracking would have no effect because
no individual PSD source has a 24-hour impact of
over 5.0 ug/m3. Thus, this option would have
the same impact as the annual increment.
• A policy which would eliminate PSD increments
and require sources to comply with BACT require-
ments would degrade air quality at the park but
would allow for unlimited development. If this
approach were implemented, the 24-hour increment
would be 9.6 ug/m3 and 10.9 ug/m3 at the Flat
Tops and Dinosaur areas, respectively. The
control costs for the sources would also be less
because no offsets or additional control would
need to be purchased.
ADDITIONAL RESEARCH
FBB has evaluated the impact of alternative PSD
management options in this study area as well as in a
previous report that focused on alternatives for the state
of North Dakota.* Sash of these studies was hampered to a
degree by a lack of reliable and consistent air quality
modeling data. In particular, the current modeling of air
quality in high terrain areas, such as Colorado and Otah,
is very unsophisticated. Because the PSD permitting
process relies so heavily on modeling results it is
crucial that further research be conducted to jtake' the air
quality modeling as accurate as possible.
* Putnam, Hayes 6 Bartlstt, Inc., Preliminary
of Alternative PSD Manaeemeat AperSaciws*
as sesame axser lences iFtfestira
North Dakota, April 1552.
-?4-
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DESCRIPTION OF SOURCES
APPENDIX A
The Class I areas in western Colorado and eastern
Utah will probably be impacted by emissions from the 18
oil shale facilities and 3 electric utilities modeled in
this study. This appendix describes each oil shale
source: its location, production characteristics and
permit status.
OIL SHALE FACILITIES
Parachute Creek
The Parachute Creek basin lies to the west of Rifle,
Colorado, in Garfield County, approximately 60 kilometers
from the Flat Tops Wilderness area and about 100
kilometers from the Dinosaur National Monument. Seven oil
shale plants are proposed for the basin.
Naval Oil Shale Reserve/Navy and DOE
The Naval Oil Shale Reserve (NOSR) site is located in
the eastern part of the basin. It is owned jointly by the
Navy and the Department of Energy. Although an initial
production date has not been announced, the proposed plant
is expected to produce 200,000 bbl/d using the Paraho
surface retorting technique. Applications for a PSD
permit have not been filed.
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Union/Union Oil Company
The Union project, also known as the "Parachute
Creek" or "Long Ridge" project, is owned by the Union Oil
Company of California and located in the eastern part of
Parachute Creek Basin. Initial production of 10 000 bbl/d
is projected for 1983, scaling up to full production of
50,000 bbl/d in 1987. The Union-B surface retorting
process will be used. A PSD permit was granted in 1979
for the initial production of 9,000 bbl/d. in June 1981 a
second PSD permit was granted for a 10,000 bbl/d shale oil
refining operation.
Colony/TOSCO and Exxon
Owned by TOSCO Oil Shale Corporation and Exxon, the
Colony Project was the first commercial oil shale facility
to prepare a final environmental impact statement (EIS)
and to receive all critical federal and state permits
necessary to commence construction. The project, located
about 15 miles north of Parachute Creek, will employ the
TOSCO II surface retorting process and on-site hydro
treating of raw shale oil. Initial production is expected
in 1987, and will eventually reach 48,300 bbl/d.
Chevron Oil
Chevron Oil Shale Company owns a 43,000-acre site in
the Roan Plateau area of northwestern Colorado.
Feasibility studies are being conducted to evaluate
retorting technologies and environmental impacts but no
information exists on the proposed technology and an
environmental impact statement has not been submitted.
The site is expected to begin producing 50,000 bbl/d in
1988 and reach full production of 100,000 bbl/d by 1992.
Mobil Oil
The Mobil Oil Shale Project is owned by Mobil Oil
Corporation and is located about 10 miles west of Rifle.
Mobil plans to use underground mining and one or more
different retorting processes to produce 50,000 bbl/d by
1990. They are involved in preliminary discussions with
state officials to clarify permitting requirements and
have not yet applied for a PSD permit.
A-2
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Cities Service
The Cities Service Corporation has not begun
development on its Parachute Creek Basin site nor has it
applied for any permits. They are expected to use an MIS
process to produce 50,000 bbl/d but no production date has
been set.
Pacific/Standard
The Pacific Oil Shale Project is jointly owned by
Standard Oil of Ohio (60 percent), Cleveland-Cliffs Iron
Company (20 percent) and Superior Oil Company (20
percent). The first module is expected to be completed in
1986, producing 15,000 bbl/d. By 1990 the project will
produce 45,000 to 50,000 bbl/d using the Superior Oil/Davy
McKee surface retorting technology: Environmental impact
statements are currently underway.
Piceance Creek
Piceance Creek basin is in Rio Blanco County and lies
to the north of Parachute Creek, about 40 miles west of
Flat Tops and 45 miles south of the Dinosaur National
Monument. The basin is the site of five proposed oil
shale projects.
Occidental
Owned jointly by Occidental and Tenneco, Cathedral
Bluffs has already received a PSD permit (December 1977)
for preliminary production of 5,000 bbl/d. The
application for a permit allowing 118,000 bbl/d was
submitted in April 1981 but has subsequently been
withdrawn. The project is expected to produce 55,000
bbl/d by 1988 and 94,000 bbl/d by 1990. The Oxy-modified-
in^situ technology combined with surface retorting will be
employed.
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Rio Blanco
The Rio Blanco Oil Shale Company has secured PSD
permits to test two technologies at this site. A permit
was granted in December 1977 for a modified-in-situ
project producing 1,000 bbl/d. In July 1981 another PSD
permit was granted to test the Lurgi surface retorting
process at a production level of 2,000 bbl/d. The
commercial project will have a maximum production capacity
of 135,000 bbl/d and is expected to begin producing at a
level of 76,000 bbl/d in 1987 using the Lurgi technology.
Exxon
Exxon Corporation's Love Ranch project will be
developed in two modules, each producing 30,000 bbl/d.
Room and pillar mining with surface retorts (TOSCO II) are
expected to be in operation for the first module in 1987.
Exxon has not yet applied for a PSD permit for the
project.
Superior
The Superior Oil Company owned project will employ a
proprietary retort process, known as traveling grate,
combined with retorted shale leaching. Initial production
of 11,600 bbl/d is expected to begin in 1986, eventually
increasing to 50,000 bbl/d. A PSD permit application has
not been submitted.
Multimineral
The Multimineral Corporation (MMC) plans to use a new
mining process, "intensive in situ," in the Horse Draw
project to recover several minerals as well as shale oil.
MMC is in the first of three stages demonstrating their
variation of the modified-in-situ technology. The stages
are: experimental mining, modular testing, and commer-
cialization. Production of shale oil is expected to begin
in 1984 and reach 50,000 bbl/d in 1986. Environmental
impact statements are not yet prepared.
A-4
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Uinta Basin
Located in Uinta County, Utah, the Uinta Basin is
about 50 miles south of the Dinosaur National Monument and
100 miles west of Flat Tops Wilderness area. Six oil
shale facilities are planned in the region.
Geokinetics
Owned by Geokinetics, Inc. and supported by DOE, this
project has already received a PSD permit (November 1980)
for a 100 bbl/d field test of the true in-situ method.
Permit applications for commercial production are pending
approval. Horizontal modified-in-situ will be used to
produce 20,000 bbl/d commercially.
TOSCO/Sand Wash
The Oil Shale Corporation (TOSCO) applied for a PSD
permit in August 1981 to produce 45,000 bbl/d at this
site. TOSCO II surface retorting operations are expected
to begin in 1983 and be producing at full capacity in
1990.
White River/Phillips and Sunoco
Phillips Petroleum Company and Sunoco Energy
Development Corporation jointly own this project. They
applied for a PSD permit for a pilot plant in August 1981
and expect initial production of 16,000 bbl/d in 1985.
Superior and Union surface retorting technology is
expected to produce 100,000 bbl/d at full sale.
Paraho
Paraho Development Corporation and design program
sponsors own this site and plan to begin construction in
1982. Full operation in 1986 will produce 30,000 bbl/d
using the Paraho surface-retorting technique. PSD permit
applications have not been submitted.
A-5
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Magic Circle
Owned by the Magic Circle Energy Corporation, the
Cottonwood Wash Project is expected to begin production
late in 1986 and be producing 30,000 bbl/d at full scale
in 1988. Magic Circle plans to employ a Union-type
process for the recovery of shale oil. As yet, no permit
application has been filed.
Syntana
The Syntana project is jointly owned by the Synthetic
Oil Corporation and Quintana Mineral Corporation.
Construction will begin in 1984 and initial production is
not expected until the 1990s.
A-6
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SO2 CONTROL COSTS
APPENDIX B
Since there are no facilities that commercially
produce oil from shale in the world today, the cost and
emission estimates are not based on actual experience.
Instead, cost estimates have been evaluated from a variety
of sources including published reports, internal EPA
documents, and oil shale PSD permit applications. The
figures provided by these different sources differ,
sometimes dramatically, indicating much uncertainty with
regard to expected costs. Three major categories of
uncertainty are responsible for most of the discrepancies
in cost estimates and the difficulties encountered in
selecting costs for this report.
• Uncertainty associated with production
processes:
In some cases the process that will be
employed has not been chosen or has not
been analyzed.
- Whether or not refining facilities exist at
each site is uncertain.
• Uncertainty associated with shale:
The sulfur content of shale and the
composition of emissions vary across the
region. Two similar processes handling
different qualities of shale could have
different control costs.
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• Uncertainty associated with control processes:
The BACT control levels used in this
analysis are assumed only for purposes of
this study. Actual BACT determinations for
individual sources will be determined on a
case-by-case basis.
These uncertainties are mentioned throughout this appendix
along with the assumptions used to estimate costs.
PRODUCTION PROCESSES
Oil shale can be processed in one of three basic
ways:
• In-situ: The deposit is fractured and pyrolized
while in the earth. The shale oil and gases are
recovered through wells. This process is not
currently commercially feasible.
• Modified-in-situ (MIS): A fraction of the shale
is mined to create a void for blasting. Then,
heat is applied to the rubblized deposit and oil
and gases are recovered through wells.
• Mining and Surface Retorting: Shale is mined
and brought to the surface for retorting.
Several variations on the latter two process types
are being proposed for the eighteen oil shale sites.
Since cost and emission information is not available for
each specific process, each facility has been classified,
for purposes of this study, into five process categories.
These five categories were chosen because they are
representative of most currently proposed processes and
because either a PSD permit application or an internal EPA
document exists which describes applicable control
technologies, costs and emissions. The five categories
are listed below. The processes in parentheses are
B-2
-------
representative processes for which information was
available.*
• External Indirectly Heated Retort (Union B) :
Heat is transferred by gases that are heated
outside of the above-ground retort vessel.
• Internal Indirectly Heated Retort (TOSCO II) :
Heat is transferred by mixing hot solid
particles with the oil shale in a surface
retort.
• Modified-in-situ (Occidental): As described
earlier.
• Modified-in-situ and Lurgi (Rio Blanco)s MIS is
used in combination with a Lurgi Batch surface
retorting technology.
• Directly Heated Retort (Paraho): "Heat is
transferred by hot gases generated within the
retort by combustion of retorted shale and
pyrolosis gases."
Exhibit B-l lists each proposed oil shale facility with
its process classification. Several of the companies are
uncertain of the process they will use and some of the
processes were difficult to categorize neatly. Thus, the
costs obtained using these classifications may prove to be
incorrect ex poste. Yet, they are the best estimates
g^ven limited available information.
With the exception of the Union permit application,
upgrading facilities were not mentioned in the cost and
emission literature. The figures used in this analysis
therefore do not normally include emissions from upgrading
facilities. Sensitivity analysis was performed which
included emissions from upgrading facilities for Union B
type processes.
* PSD permit applications
process and Occidental's
documents were used for
Paraho.
were used for the Union B
MIS process. Internal EPA
TOSCO II, Rio Blanco, and
B-3
-------
Exhibit B-l
OIL SHALE FACILITIES BY PROCESS TYPE
Oil Shale Facility
Union
Colony
TOSCO/Sand Wash
Occidental
Geokinetics
Multimineral
White River
Superior
Pacific
Paraho
Magic Circle
Rio Blanco
Exxon
Chevron
Mobil
Syntana
Naval Oil Shale Reserve
Cities Service
Assumed
Process Type
External Indirect Heat
Internal Indirect Heat
Internal Indirect Heat
Modified-in-Situ
(MIS)
MIS
External Indirect Heat
External Indirect Heat
Internal Indirect Heat
Internal Indirect Heat
Direct Heat
External Indirect Heat
MIS and Lurgi
Internal Indirect Heat
External Indirect Heat
External Indirect Heat
Internal Indirect Heat
Direct Heat
MIS
B-4
-------
CONTROL TECHNOLOGIES
EPA technical studies on alternative oil shale
technologies discuss pollution control equipment that
would be suitable for TOSCO II, Rio Blanco, and Paraho.
PSD permit applications for Occidental (MIS) and Union
provide surveys of control technologies that would be
applicable to those processes. The Colony facility, using
the TOSCO II process, has already been granted a PSD
permit to use amine absorption for S02 control. There-
fore, amine absorption is, by definition, BACT. BACT is
not defined for the other four process categories,
however, nor is stringent BACT. Exhibit B-2 lists each
category with the control technologies this analysis
assumes to be BACT and stringent BACT.
CONTROL COSTS
Capital costs and annual operating costs are
available for each process category.* Capital recovery
factors (CRFs) were taken from EPA source literature for
four of the five categories. Since the CRFs were very
similar for these four categories, an average CRF was
applied to the fifth category (Union B) to estimate its
annualized costs. The costs are listed in Exhibit B-3 and
the CRFs for each process are listed in B-4.
The costs in Exhibit B-3 were derived for five
specific facilities. The sizes of the facilities are
listed in parentheses on the table. To assign costs to
facilities of different sizes, the costs in Exhibit B-3
were scaled according to the engineering cost equation
discussed in Exhibit B-5.
Costs are from Occidental and Union PSD permits and
internal EPA documents.
B-5
-------
Exhibit B-2
Process Category
External Indirect
Heat (Union B)
Internal Indirect
Heat (TOSCO II)
MIS (Occidental)
MIS and Lurgi
(Rio Blanco)
Direct Heat
(Paraho)
Control
Level Control Technology
BACT
Stretford Treating
BACT Amine/Claus/Scot
Stringent
BACT Stretford Treating
BACT Stretford Treating
Stringent
BACT Organic Sulfur
Converted Stretford
BACT
Stretford Treating
Stretford Treating
BACT
Stringent
BACT Amine/Claus/Scot
Removal SO,
Efficiency''
98.0%
96.9%
99.0%
95.0%
98.0%
99.8%
96.4%
97.1%
B-6
-------
Exhibit B-3
S02 CONTROL COSTS FOR OIL SHALE FACILITIES*
Size (bbl/d)
S°2
Removal
Efficiency
Internal Indirect Heat
(47,000)
BACT 96.9
Most Stringent
Technology 99.0
External Indirect Heat
(10,000)
BACT
MIS
7TT7,000)
98.0
BACT
Most Stringent
Technology
95.0
98.0
MIS and Lurgi
(63,06(1)
BACT
Direct Heat
T5TTMS1
99.8
BACT
Most Stringent
Technology
96.4
98.0
Capital Annual Annualized
Cost
($mm)
15.00
25.70
13.30
98.40
378.30
6.86
22.80
26.54
Cost
($mm)
3.03
7.33
1.37
12.0
50.6
0.97
3.23
19.38
Cost
($mm)
5.49
11.54
3.55
27.84
111.50
2.08
7.08
23.87
* Costs are taken from EPA control cost estimates for
the TOSCO, Paraho, and Rio Blanco processes and from
the Union and Cathedral Bluff (MIS) PSD permit appli-
cations .
B-7
-------
Exhibit B-4
CAPITAL RECOVERY FACTORS*
Process Category CRF
External Indirect Heat 16.4% (average)
Internal Indirect Heat 16.4%
MIS 16.13%
MIS and Lurgi 16.23%
Direct Heat 16.9%
SOURCE: EPA Internal Documents.
B-8
-------
Exhibit B-5
POLLUTION CONTROL COST SCALING METHODOLOGY
"2 " "ft)
where:
Y.^ » Cost of facility 1 (known)*
Y2 = Cost of facility 2 (unknown)
= Size of facility 1 (known)
X2 = Size of facility 2 (known)
b = 0.8**
Operating and/or annualized capital costs.
EPA engineers in Cincinnati suggest that since
oil shale facilities are often built in modules,
an appropriate scale factor for pollution
control capital costs is 0.8.
The scaling factor for operating costs is 0.6.
B-Q
-------
UTILITY S02 CONTROL COSTS
APPENDIX C
This appendix illustrates the methodology that was
used to calculate the SO- control costs for the existing
Hayden utility plant and the Craig plant/ which has three
units. These costs are used to establish th® cost of
purchasing offsets which would allow for the siting of the
proposed oil shale facilities. PHB has not estimated
control costs for the Moonlake plant. This utility has
agreed to install scrubbing units at 94 percent removal
efficiency. PEDCo's cost model is not accurate for
calculating costs at this percent removal. Because of
this, and because the plant could not install any further
So, control technology, the costs for this
bein estimated.* The control costs for the Hayden and
Craig plant are important for the analysis.
To calculate the costs of SO, font*°i
and Craig electric generating plants,_ ronmental
cost models. One model, developed by PEDCo ^nviro^ental.
Inc. was used to estimate costs for wet
systems.** Another model developed in used to
Commission on Air Quality (NCAQ) reP° . , 2 have
estimate dry scrubbing costs. Craig un
Moonlake's control costs will be obtained from its
PSD permit.
Simplified Procedures for Estimating Flue Gas
Desulfurization System Costs, PEDCoEnvironmental,
BPA-600/2-76-150.
-------
wet scrubbing units installed, while unit 3 will be
equipped with a dry scrubber. It is assumed that the
Hayden plant, if it were to retrofit control, would
install a wet scrubbing system.
DESCRIPTION OF S02 CONTROL COST MODELS
PEDCo Model
The PEDCo model breaks capital costs into costs for
lime preparation, SO- scrubbing, sludge disposal, and
miscellaneous indirect costs. Annual costs include raw
materials, labor, maintenance, overhead, fixed costs and
trucking.* To run this model a number of inputs are
required.
Exhibit C-l lists the inputs that were assumed for
each plant. The cost figures for labor, electricity and
lime were taken from a recent PEDCo publication, while the
capacity factors and distance to disposal sites were
estimated using permit information from various
utilities.
Besides these constant parameters, four plant-
specific inputs are needed. These factors include the
tons of SO, that must be removed per hour, the number of
scrubber trains at the facility, and the plant's duct
factor and flue-gas rate. To determine the tons of sulfur
removed per hour, the quantity and type of coal for each
plant need to be determined, and emissions for each
alternative emission limitation should be calculated. The
cost calculations follow procedures outlined in PHB's
North Dakota case study.**
Fixed costs include taxes, insurance, and interim
replacement.
Putnam, Hayes & Bartlett, Inc., Evaluation of
Alternative Prevention of Significant" Deterioration
Policies: A Case Study of Energy Development in
Western North Dakota, Draft Report, October fgai
C-2
-------
Exhibit C-l
CONSTANT INPUTS
Input
Value
Source
Labor Cost
Electricity Cost
Lime Cost
Capacity Factor
(new plants)
Capacity Factor
(existing plants)
Distance to Disposal
Sites
$15/hour
23.19 millAwh
$4Q/ton
70%
60%
3 miles
PEDCo Environmental
PEDCo Environmental
PEDCo Environmental
Estimate
Estimate
Permits
-------
Dry Scrubbing Costs
Dry scrubbing is a relatively new
there are only a few plants which kave opera dry
scrubbers. Therefore, unlike the PEDCo mo ' cQst
scrubbing costs must be estimated using more ge «eoort
equation formulas. The recent NCAW Four Coj^® - bv
included dry scrubbing equations that were develop ^
F. Hesketh.* The equations take the following
Capital Cost
Cost ¦ (1.69 x 104)(raw)*75(% control)*
Annual Cost
Cost = (2.77 x 103)(mw)*75(% control)*
mw = design capacity
% control ¦ percent of SOj control
These equations are used to estixaate the dry
scrubbing costs for unit 3 of the Craig facility.
Hayden SOj Control Costs
The Hayden plant currently has no SO- control.
Therefore additional control would need to be retrofitted
onto this plant. To estimate the costs for retrofitting
pollution controls PHB reviewed the conclusions of several
groups.** Based on this review, it has been decided that
* H. F. Heskith, Economic Process Technology, and Cost
Curve Development Data and Procedures for Coal-Fired
Electrical Generation Facilities, 1971TI
** ICF, Inc. Interim Results of Acid Rain Mitigation
Study, January IT^ 1981; PEDCoEnvironmental,
Simplified Procedures for Estimating Flue Gas
Desulfurization System Costs, EPA-600/2-76-150;
Energy and Environmental Analysis, Inc., Conversation
with Carl Held regarding EPA-generated cost curves.
C-4
-------
an appropriate retrofit factor would be 1.3; that is,
retrofitting control equipment costs 30 percent more than
installing the same equipment on a new plant.
S02 control costs for Hayden were estimated at
several different control levels. In general, wet
scrubbing systems can be sized at any desired efficiency.
PHB chose to estimate costs at 30 and 60 percent
efficiency. Exhibit C-2 illustrates the plant-specific
inputs that were used in the PEDCo model. When the
plant-specific data are entered into the PEDCo cost
methodology the following, capital and annual costs are
determined:
SO, CONTROL COSTS FOR HAYDEN
1 (mm 1985$)
Hayden Hayden
(30%) (60%)
Capital Cost* 22.5 35.0
Annual Cost 3.8 7.8
Craig Units 1 and 2 and S02 Control Costs
The Craig units 1 and 2 were proposed to achieve a 75
percent SO, removal rate using wet scrubbing. Control
costs were estimated at this proposed control level as
well as a more stringent 85 percent control. Exhibit C-3
lists the plant-specific inputs that were used for these
units.
Inputting the plant-specific data into the wet
scrubbing model results in the following capital and
annual costs for S02 control at Craig units 1 and 2.
* The 1.3 retrofit factor has been applied to the
capital costs.
-------
Exhibit C-2
PLANT-SPECIFIC DATA FOR HAYDEN
Hayden Hayden
(30%) (60%)
Model Inputs
S02 Tons/Hour Removed 1.8 3.6
Scrubber Trains 3 4
Duct Factor 0.48* 0.96
Flue Rate (000 cfm) 672** 1344
General Data
Coal Use (000 T/Y) 1692+ 1692
Percent Sulfur in Coal 0.912+ 0.912
Avg. BTU/lb 10716+ 10716
SO- Emission Control
T#/mmBtu) 1.2 0*6
* Based on PEDCo engineering formula.
** Flue-gas rate taken from Colorado Department of Health
emission inventory.
+ DOE, Cost and Quality of Fuels for Electric Utility
Plants - 1979.
C-6
-------
Exhibit C-3
PLANT-SPECIFIC DATA FOR CRAIG
UNITS 1 AND 2
Model Inputs
SO2 Tons/Hour Removed
Scrubber Trains
Duct Factor
Flue Rate (000 cfm)
Craig
(75%)
2.9
8
1.33*
1598**
Craig
(85%)
3.30
10
1.49
1811
General Data
Coal Use (000 T/Y) 2449
Percent Sulfur in Coal 0.49+
Aug. BTU/lb 10500+
SO- Emission Control
T#/nanBtu) 0.23
2449
0.49
10500
0.14
* Based on engineering formula.
** PSD permit information.
+ DOE, Cost and Quality of Fuels for Electric Utility
Plants - 1979.
C-7
-------
SO, CONTROL COSTS AT CRAIG UNITS 1 AND 2
(mm 1985$)
Craig
(75%)
Craig
(85%)
Capital Cost*
Annual Cost
74.4
84.2
16.8
19.4
Craig Unit 3 S02 Control Costs
The Craig plant's unit 3 will have a dry scrubbing
system at an 88 percent removal efficiency. At this time,
this is the maximum S02 control removal for a dry
scrubbing system. Inputting this control efficiency along
with this unit's designed capacity (447 raw) into the dry
scrubbing cost equations results in capital and annual
cost estimates of $31.5 and 5.2 million, respectively.
ANNUALIZED COSTS
PHB has annualized the capital costs of the scrubbing
systems using a cash-flow model. To use this model a
number of assumptions have to be made. Exhibit C-4 lists
the inputs to the model and the values that were assigned
to these inputs. Most of the rates used (e.g., income
tax, inflation) are based on reasonable assumptions about
the future, while the capitalization and depreciation
figures used are common to most utilities. The cash-flow
model, using the parameters listed in Exhibit C-4,
generates a before-tax capital recovery factor (real
dollars) of 8.38 percent. This factor has been used to
annualize all of the utility capital cost figures in this
report.
Exhibit C-5 summarizes the capital, annual and
annualized costs for the Hayden and Craig utility plants.
The annualized costs range from $5.7 million at Hayden
with a 30 percent control level to $26.5 million at Craig
units 1 and 2 at an 85 percent control level.
No retrofit factor is applied because construction is
not completed at this plant.
C-8
-------
Exhibit C-4
CAPITAL RECOVERY FACTOR
DATA INPUTS
Input
Value
Investment Tax Credit
Inflation Rate
Interest Rate
Rate on Preferred
Discount Rate
Capitalization
- Equity
- Debt
Useful Life of Pollution
Control Equipment
Depreciable Life
Depreciation Method
10.0%
7.0%
10.0%
15.0%
14.5%
40.0%
60.0%
15 years
5 years
Straight Line
C-9
-------
Exhibit C-5
COSTS OP SO- CONTROL AT HAYDEN AND CRAIG
(mm 1985$)
Plant
Capital
Annual
Annualized
Hayderi (30%)
22.5
3.8
5.7
Hayden (60%)
35.0
7.8
10.7
Craig 1 and 2
(75%)
74.4
16.8
23.0
Craig 1 and 2
(85%)
84.2
19.4
26.5
Craig 3 (88%)
31.5
5.2
7.8
C-10
-------
AIR QUALITY IMPACTS OF EMISSION SOURCES
AT BACT CONTROL
APPENDIX D
This appendix summarizes the cumulative air quality
impact of the Moonlake and Craig utility plants and the
oil shale facilities on the mandatory and proposed Class I
areas. The figures represent the air quality impact of
each source when an assumed BACT control level is
required. This control level is needed to obtain a PSD
permit.
The exhibits in this appendix include the cumulative
air quality impact of each basin or combination of basins
on the Class I areas. The values that are circled
represent sources that would not be able to receive a
permit because the increment ceiling would be violated.
Each table represents the impact of sources on an
individual Class I area.
-------
Exhibit D-l
AIR QUALITY IMPACT AT MAROON BELLS
WITH BACT ASSUMPTIONS
Source Parachute Piceance Uinta Uinta/Parachute
Moonlake 1 & 2 0.5 0.5
Union 0.4
Colony 0.7
TOSCO 0.6 1.6
Occidental 0.7 1.3
Geokinetics 0.6 1.3
Multimineral 1.0 1.6
White River 0.7 1.7
Superior 1.8 2.5
Pacific i,3
Paraho 1.0 2.8
Magic Circle 1.1 2.9
Rio Blanco 2.5 3.6
Exxon 2.8 3.9
Chevron 2.2
Mobil 2.6
Syntana 1.3 4.1
NOSR 3.9
Cities Service
©
Circled values indicate violations of the increment.
D-2
-------
Exhibit D-2
AIR QUALITY IMPACT AT DINOSAUR PARK
WITH BACT ASSUMPTIONS
Source Parachute Piceance Uinta Parachute/Piceance
Moonlake 1 & 2 2.9
Union 0.4 0.4
Colony 0.6 0.6
TOSCO 3.3
Occidental 1*3 1.9
Geokinetics 4-°
Multimineral 1•9 2.5
White River 4•3
Superior 3.7 4.3
Pacific 1.1 4»8
Paraho (5 • 8J
Magic Circle
Rio Blanco 5•1
Exxon 5.9
Chevron 1.8
Mobil 2.2
Syntana
NOSR 3.2
Cities Service 4.9
©
0
©
Circled values indicate violations of the increment.
D-3
-------
Exhibit D-3
AIR QUALITY IMPACT AT COLORADO MONUMENT
WITH BACT ASSUMPTIONS
Source Parachute Piceance Uinta
Moonlake 1 & 2 1.4
Union 0 •6
Colony 0•^
TOSCO 1.6
Occidental 1.0
Geokinetics 1.9
Multimineral 1.4
White River 2.0
Superior 2.6
Pacific 1.7
Paraho 2.8
Magic Circle 3.0
Rio Blanco 3.7
Exxon 4.2
Chevron 2.8
Mobil 3.4
Syntana 3.4
NOSR 4.9
Cities Service
Circled values indicate violations of the increment.
-------
Exhibit D-4
AIR QUALITY IMPACT AT MT. ZIRKEL
WITH BACT ASSUMPTIONS
Source Parachute Piceance Uinta Uinta/Craig
Moonlake 1 & 2 0.4 0.4
Craig 1-3 5.0
Union 0.1
Colony 0.2
TOSCO 0.5 0
Occidental 0.7
Geokinetics 0.5 0
Multimineral 0.9
White River 0.6
Superior 1•5
Pacific 0.4
Paraho 0.9 0
Magic Circle 1«0
Rio Blanco 1*9
Exxon 2.2
Chevron 0.7
Mobil 0.8
Syntana i.i 0
NOSR 1.3
Cities Service 2.0
Circled values indicate violations of the increment.
D-5
-------
Exhibit D-5
AIR QUALITY IMPACT AT ROCKY MOUNTAIN
WITH BACT ASSUMPTIONS
Source
Moonlake 1 & 2
Union
Colony
TOSCO
Occidental
Geokinetics
Multimineral
White River
Superior
Pacific
Paraho
Magic Circle
Rio Blanco
Exxon
Chevron
Mobil
Syntana
NOSR
Cities Service
Parachute
0.1
0.2
0.4
0.6
0.7
1.0
1.7
Piceance Uinta
0.3
0.3
0.4
0.8
1.2
1.4
0.3
0.3
0.3
0.6
0.7
0.8
Uinta/Piceance
0.3
0.3
0.6
0.6
0.7
0.7
1.1
1.4
1.5
1.9
2.1
2.2
D-6
-------
Exhibit D-6
AIR QUALITY IMPACT AT RAWAH
WITH BACT ASSUMPTIONS
Source Parachute Piceance Uinta Uinta/Craig
Moonlake 1 & 2 0.3 0.3
Craig 1-3 1.7
Union 0.1
Colony 0.2
TOSCO 0.3 1.7
Occidental 0.3
Geokinetics 0.3 1.7
Multimineral 0.4
White River 0.3 1.7
Superior 0.7
Pacific 0.3
Paraho 0.6 2.0
Magic Circle 0.7 2.1
Rio Blanco 1•1
Exxon 1.3
Chevron 0.5
Mobil 0.6
Syntana 0.8 2.2
NOSR 0.9
Cities Service 1.2
D-7
-------
Source
Exhibit D-7
AIR QUALITY IMPACT AT EAGLE'S NEST
WITH BACT ASSUMPTIONS
Moonlake 1 & 2
Union
Colony
TOSCO
Occidental
Geokinetics
Multimineral
White River
Superior
Pacific
Paraho
Magic Circle
Rio Blanco
Exxon
Chevron
Mobil
Syntana
NOSR
Cities Service
Parachute
0.2
0.3-
0.6
1.0
1.2
1.7
2.7
Piceance Uinta
0.4
0.3
0.4
1.0
1.4
1.7
0.5
0.5
0.6
0.9
1.0
1.1
Parachute/Uint-«
0.4
0.6
0.7
0.8
0.8
0.9
1.2
1.5
1.6
2.0
2.2
2.3
2.8
3.8
D-8
-------
Exhibit D-8
AIR QUALITY IMPACT AT ARCHES
WITH BACT ASSUMPTIONS
Source
Parachute
Moonlake 1 & 2
Craig 1-3
Union
Colony
TOSCO
Occidental
Geokinetics
Multimineral
White River
Superior
Pacific
Paraho
Magic Circle
Rio Blanco
Exxon
Chevron
Mobil
Syntana
NOSR
Cities Service
0.2
0.3
0.6
1.0
1.2
1.7
2.7
Piceance Uinta
1.1
0.3
0.4
0.9
1.3
1.5
1.3
1.6
1.7
2.2
2.3
.6
Piceance/Craig
0.6
0.9
1.0
1.5
1.9
2.1
D-9
-------
Exhibit D-9
AIR QUALITY IMPACT AT BLACK CANYON
WITH BACT ASSUMPTIONS
Source Parachute Piceance Uinta
Moonlake 1 & 2 0.6
Union 0.4
Colony 0.6
TOSCO 0.7
Occidental 0.7
Geokinetics 0.7
Multimineral 0.9
White River 0.8
Superior 1.6
Pacific 1.1
Paraho 1. i
Magic Circle 1,2
Rio Blanco 2.0
Exxon 2.3
Chevron 1.8
Mobil 2.2
Syntana 1.4
NOSR 3.2
Cities Service 4.9
D-10
-------
AIR QUALITY IMPACTS OF EMISSION SOURCES
AT MOST STRINGENT TECHNOLOGY LEVEL
APPENDIX E
This appendix summarizes the cumulative air quality
impact of the Moonlake and Craig utility plants and the
oil shale facilities on the mandatory and potential Class
I areas. The figures represent the air quality impact of
each source when most stringent technology is required.
The exhibits in this appendix include the cumulative
air quality impact of each basin or combination of basins
on the Class I areas. The values that are circled
represent sources that would not be able to receive a
permit because the increment ceiling would be violated.
Each table represents the impact of sources on an
individual Class I area.
-------
Exhibit E-l
AIR QUALITY IMPACT AT MAROON BELLS
WITH MOST STRINGENT TECHNOLOGY ASSUMPTIONS
Source Parachute Piceance Uinta Unita/Parachute
Moonlake 1 & 2 0.5 0.5
Union 0.4 0.9
Colony 0.7 1.2
TOSCO 0.5 1.2
Occidental 0.1
Geokinetics 0.5 1> 2
Multimineral 0.4
White River 0.6 1*3
Superior 1.2
Pacific 0.9 1.5
Paraho 0.8 1.7
Magic Circle 0.9 1.8
Rio Blanco 1.9
Exxon 2.0
Chevron 1.8 2.7
Mobil 2.2 3.1
Syntana 1.0 3.2
NOSR 3.3 4.3
Cities Service 4.1
Circled values indicate violations of the increment.
E-2
©
-------
Exhibit E-2
AIR QUALITY IMPACT AT DINOSAUR PARK
WITH MOST STRINGENT TECHNOLOGY ASSUMPTIONS
Source Parachute Piceance Uinta Parachute/Piceance
Moonlake 1 & 2 2.9
Union 0.4 0.4
Colony 0.5 0.5
TOSCO 3.0
Occidental 0.6 1.1
Geokinetics 3.3
Multimineral 1.2 1.7
White River 3.6
Superior 3.0 3.5
Pacific 1.0 4.0
Paraho 4.8
Magic Circle (5T2)
Rio Blanco 4.4
Exxon 4.7
Chevron 1.7
Mobil 2.1
Syntana
NOSR 2.9
Cities Service 3.6
Circled values indicate violations of the increment.
E-3
-------
Exhibit E-3
AIR QUALITY IMPACT AT COLORADO MONUMENT
WITH MOST STRINGENT TECHNOLOGY ASSUMPTIONS
Source Parachute Piceance Uinta
Moonlake 1 & 2 1-4
Union 0.6
Colony 0.9
TOSCO 1.5
Occidental 0.4
Geokinetics 1•6
Multimineral 0.8
White River 1.1
Superior 2.0
Pacific 1.7
Paraho 2.3
Magic Circle 2.5
Rio Blanco 3.1
Exxon 3.3
Chevron 2.8
Mobil 3.4
Syntana 2.6
NOSR 4.6
Cities Service ©
Circled values indicate violations of the increment.
E-4
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Exhibit E-4
AIR QUALITY IMPACT AT MOUNT ZIRKEL
WITH MOST STRINGENT TECHNOLOGY ASSUMPTIONS
Source Parachute Piceance Uinta Unita/Craig
Moonlake 1 & 2 0.4 0.4
Craig 1-3 5.0
Union 0.1
Colony 0.2
TOSCO 0.5 0
Occidental 0.3
Geokinetics 0.5 0
Multimineral 0.5
White River 0.6
Superior 1.1
Pacific 0.4
Paraho 0.8 \jjv7
Magic Circle 0.9 ftTa
Rio Blanco 1•5
Exxon 1.6
Chevron 0.7
Mobil 0.8
Syntana 0.9
NOSR 1.2
Cities Service 1.5
Circled values equal violations of the increment.
E-5
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Exhibit E-5
AIR QUALITY IMPACT AT ROCKY MOUNTAIN
WITH MOST STRINGENT TECHNOLOGY ASSUMPTIONS
Source Parachute Piceance Uinta Unita/Piceance
Moonlake 1 & 2 0.3 0.3
Union 0.1
Colony 0.2
TOSCO 0.3 0.3
Occidental 0.1 0.4
Geokinetics 0.3 0.4
Multimineral 0.2 0.5
White River 0.3 0.5
Superior 0.6 0.9
Pacific 0.4
Paraho 0.5 1.1
Magic Circle 0.6 1.2
Rio Blanco 1.0 1.6
Exxon 1.1 1.7
Chevron 0.6
Mobil 0.7
Syntana 0.6
NOSR 0.9
Cities Service 1.2
E-6
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Exhibit E-6
AIR QUALITY IMPACT AT RAWAH
WITH MOST STRINGENT TECHNOLOGY ASSUMPTIONS
Source Parachute Piceance Uinta Unita/Craig
Moonlake 1 & 2 0.3 0.3
Craig 1-3 1.7
Union 0.1
Colony 0.2
TOSCO 0.3 1.7
Occidental 0.1
Geokinetics 0.3 1.7
Multimineral 0.2
White River 0.3 1.7
Superior 0.5
Pacific 0.3
Paraho 0.5 1.9
Magic Circle 0.6 2.0
Rio Blanco 0.9
Exxon 1.0
Chevron 0.5
Mobil 0.6
Syntana 0.6 2.0
NOSR 0.8
Cities Service 0.9
2-7
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Exhibit E-7
AIR QUALITY IMPACT AT EAGLE'S NEST
WITH MOST STRINGENT TECHNOLOGY ASSUMPTIONS
Source Parachute Piceance Uinta Unita/Parachute
Moonlake 1 & 2 0.4 0.4
Union 0.2 0.6
Colony 0.3 0.7
TOSCO 0.4 0.7
Occidental 0.1
Geokinetics 0.4 0.7
Multimineral 0.2
White River 0.5 0.8
Superior 0.8
Pacific 0.6 1.1
Paraho 0.7 1.3
Magic Circle 0.8 1.4
Rio Blanco 1.2
Exxon 1.3
Chevron 1.0 1.8
Mobil 1.2 2.0
Syntana 0.8 2.0
NOSR 1.6 2.4
Cities Service 2.0 2.8
E-8
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Exhibit E-8
AIR QUALITY IMPACT AT ARCHES
WITH MOST STRINGENT TECHNOLOGY ASSUMPTIONS
Source Parachute Piceance Uinta Piceance/Craig
Moonlake 1 & 2 1.1
Craig 1-3 1.7
Union 0.2
Colony 0.3
TOSCO 1.2 1.8
Occidental 0.1
Geokinetics 1.3 1.9
Multimineral 0.2
White River 1.4 2.0
Superior 0.7
Pacific 0.6
Paraho 1.8 2.4
Magic Circle 1.9 2.5
Rio Blanco 1.1
Exxon 1.2
Chevron 1.0
Mobil 1.2
Syntana 2.0 2.6
NOSR 1.6
Cities Service 2.0
E-9
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Exhibit E-9
AIR QUALITY IMPACT AT BLACK CANYON
WITH MOST STRINGENT TECHNOLOGY ASSUMPTIONS
Source Parachute Picaence Uinta
Moonlake 1 & 2 0.6
Union 0.4
Colony 0.6
TOSCO 0•6
Occidental 0.3
Geokinetics ®®
Multimineral 0.5
White River 0•7
Superior 1 •2
Pacific 1.1
Paraho 0 •9
Magic Circle 1•0
Rio Blanco 1•6
Exxon 1 •7
Chevron 1.8
Mobil 2.2
Syntana 1 1
NOSR 3.0
Cities Service 3.7
E-10
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