May 1, 2006
Eric Merchant, Air Quality Specialist
Air Permitting Section
Permitting and Compliance Division
Montana Department of Environmental Quality
1520 E. 6th Avenue
P.O. Box 200901
Helena, MT 59620-0901
RE: Comments on MTDEQÕs Preliminary Decision to Issue an Air
Quality Permit for the Highwood Generating Station
Dear Mr. Merchant:
The Montana Environmental Information Center (MEIC) respectfully submits the following comments on the Montana Department of Environmental QualityÕs (MTDEQ) preliminary determination to issue an air quality permit to Southern Montana Electric Generation and Transmission Cooperative (SMEGTC) to construct the Highwood Generating Station (Highwood) near Great Falls, Montana.
1. The Draft AIR QUALITY Permit DOES Not
ADDRESS CARBON DIOXIDE AND OTHER GREENHOUSE GAS EMISSIONS
The draft permit for the Highwood
Generating Station did not address carbon dioxide (CO2) or other
greenhouse gases to be emitted from the proposed power plant. However, such emissions can be quite
significant from coal-fire boilers and, in particular, from circulating
fluidized bed (CFB) boilers such as is proposed for Highwood. The National Coal Council identifies
fluidized bed combustion as an especially large source of the greenhouse gas
nitrous oxide (N2O), a problem that is not shared by the most common
form of coal combustion technology, pulverized coal (PC):
ÒN2O has a GWP (Global
Warming Potential)
296 times that of CO2. Because of its long lifetime (about 120
years) it can reach the upper atmosphere, depleting the concentration of
stratospheric ozone, an important filter of UV radiation. N2O is
emitted from fluidized bed coal combustion; global emissions from FBC units are
0.2 Mt/year, representing approximately 2% of total known sources. N2O
emissions from PC units are much lower. Typical N2O emissions from
FBC units are in the range of 40-70 ppm (at 3% O2). This is
significant because at 60 ppm, the N2O emission from the FBC is
equivalent to 1.8% CO2, an increase of about 15% in CO2
emissions for an FBC boiler. Several techniques have been proposed to control N2O
emissions from FBC boilers, but additional research is necessary to develop
economically and commercially attractive systems."[1]
The Highwood Generating Station has a
potential to emit approximately 3.2 million tons of carbon dioxide each year
and 2,300 tons of nitrous oxide each year.[2] The nitrous oxide that would be
released from the Highwood Generating Station is equivalent, in Global Warming
Potential, to an additional 680,800 tons per year of carbon dioxide, or an
effective 22% increase in HighwoodÕs carbon dioxide emissions.
We believe that the EPA, and the State
of Montana have a legal obligation to regulate CO2 and other
greenhouse gases as pollutants under the Clean Air Act and the Montana Clean
Air Act. Indeed, twelve states,
fourteen environmental groups and two cities have filed suit in federal court
stating that EPA must regulate greenhouse gas emissions under the Clean Air
Act. Specifically, the parties
appealed the U.S. EPA's decision to reject a petition that sought to have the
federal government regulate greenhouse gas emissions from new motor vehicles.[3] If the federal court agrees that
greenhouse gases, such as CO2, must be regulated under the Clean Air
Act, such a decision would also require the establishment of CO2
emission limits in this permit for the Highwood Generating Station.
At the minimum, MTDEQ must consider
emissions of CO2 in its BACT analysis for Highwood. The federal Environmental Appeals Board
(EAB) has interpreted the definition of BACT as requiring consideration of
unregulated pollutants in setting emission limits and other terms of a permit,
since a BACT determination is to take into account environmental impacts.[4] A recently issued paper entitled Considering
Alternatives: The Case for
Limiting CO2 Emissions from New Power Plants through New Source
Review by Gregory B.
Foote discusses the regulatory background to support consideration of CO2
impacts when permitting a new source and, in particular, a new coal-fired power
plant. This paper indicates that
it is entirely appropriate to consider CO2 emissions when evaluating
environmental impacts under the new source review permit program, and the paper
also suggested approaches for evaluating technologies in terms of CO2
emissions. This paper and all
other documents cited herein are incorporated by reference as part of our
comments.
2. The DRAFT Air Quality permit Did NOT
ADEQUATEly Evaluate integrated gasification combined cycle as an available
method TO LOWER AIR EMISSIONS in the BACT analysis
Integrated Gasification Combined Cycle (IGCC) is an available, demonstrated cleaner coal combustion technology with significant emission reduction benefits. There are numerous benefits to IGCC, including fewer emissions of criteria and hazardous air pollutants, the opportunity for capturing greenhouse gases, such as CO2, that cause global warming, and a general increase in efficiency over other coal burning technologies. While IGCC was briefly considered by MTDEQ in its BACT analysis, the state quickly eliminated further consideration of IGCC based on the limited information provided in Southern Montana Electric Generation and TransmissionÕs October 2004 Alternative Evaluation Study. However, the evaluation of IGCC in the October 2004 study was not a BACT analysis. Instead, it was an evaluation to determine an appropriate source of wholesale electric energy post 2008. MTDEQ eliminated consideration of IGCC in the BACT review based on reliability concerns, cost increases (although no cost analysis was provided), and Òlittle to noÓ expected environmental benefit with respect to criteria pollutants as compared to the planned CFB facility. MTDEQ Permit Analysis at 11-12.
Yet, MTDEQ found that IGCC was a technically feasible electric power production technology using coal as fuel (see MTDEQ Permit Analysis at 11 under ÒAdditional Evaluation of IGCC and PC TechnologyÓ). Thus, MTDEQ is then obligated to fully evaluate IGCC in its BACT analysis as a technically feasible control technology. Further, MTDEQ should also evaluate IGCC with add-on controls to achieve the maximum emission reduction in criteria pollutants, hazardous air pollutants, and greenhouse gases.
Montana and Federal Law Require a Thorough Evaluation of IGCC as Part of the BACT Analysis.
Section 165(a)(4) of the Clean Air Act (CAA) provides that Òno major emitting facility on which construction is commenced after August 7, 1977, may be constructed in any area to which this part applies unlessÉthe facility is subject to the best available control technology for each pollutant subject to regulation under this chapter emitted from, or which results from, such facility.Ó[5] The requirement for conducting a BACT analysis is codified at 40 CFR ¤ 51.166(j), in regulations setting forth the requirements for state-administered PSD programs. Montana law, in turn, requires as a condition of issuance of a PSD permit that Ò[a] new major source shall apply best available control technology for each pollutant subject to regulation under [Federal Clean Air Act] that it would have the potential to emit in significant amounts. . . .Ó[6] State law further requires that Òthe owner or operator of a proposed source. . . shall submit. . .all information necessary to perform any analysis or make any determinationÓ required under Montana air pollution rules.Ó[7]
BACT is then defined under Montana law as follows:
an emissions limitation (including a visible emissions standard) based on the maximum degree of reduction for each pollutant subject to regulation under the [Federal Clean Air Act] . . . which would be emitted from any proposed major stationary source or major modification which the department, on a case‑by‑case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application or production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant.[8]
The wording of the definition of BACT found within MontanaÕs regulations is similar to the federal definition at 40 CFR ¤ 51.166(b)(12).
This definition includes coal gasification. The legislative history of the amendment adding the term Òinnovative fuel combustion techniquesÓ to the Clean Air ActÕs definition of ÒBACTÓ is clear. Coal gasification must be considered. The relevant passage of the debate is excerpted below:
Mr.
HUDDLESTON. Mr. President, the proposed provisions for application of best
available control technology to all new major emission sources, although having
the
admirable
intent of achieving consistently clean air through the required use of best
controls, if not properly interpreted may deter the use of some of the most
effective pollution controls. The
definition in the committee bill of best available control technology indicates
a consideration for various control strategies by including the phrase Òthrough
application of production processes and available methods systems, and
techniques, including fuel cleaning or treatment.Ó And I believe it is likely
that the concept of BACT is intended to include such technologies as low Btu
gasification and fluidized bed combustion. But, this intention is not
explicitly spelled out, and I am concerned that without clarification, the
possibility of misinterpretation would remain. It is the purpose of this amendment to leave no doubt that
in determining best available control technology, all actions taken by the fuel
user are to be taken into account--be they the purchasing or production of
fuels which may have been cleaned or up-graded through chemical treatment,
gasification, or liquefaction; use of combustion systems such as fluidized bed
combustion which specifically reduce emissions and/or the post-combustion
treatment of emissions with cleanup equipment like stack scrubbers. The
purpose, as I say, is just to be more explicit, to make sure there is no chance
of misinterpretation. Mr. President, I believe again that this amendment has
been checked by the managers of the bill and that they are inclined to support
it.
Mr. MUSKIE.
Mr. President, I have also discussed this amendment with the
distinguished
Senator from Kentucky. I think it has been worked out in a form I can
accept. I am
happy to do so. I am willing to yield back the remainder of my time.[9]
EPA and federal courts have consistently interpreted the BACT provisions found in the CAA and the agencyÕs regulations as embodying certain core criteria that require the permit applicant either to implement the most effective available means for minimizing air pollution or justify its selection of less effective means on grounds consistent with the purposes of the Act. In Citizens for Clean Air v. EPA,[10] the Ninth Circuit held that Òinitially the burden rests with the PSD applicant to identify the best available control.Ó As stated in long-standing EPA guidance, Ò[r]egardless of the specific methodology used for determining BACT, be it Ôtop-down,Õ Ôbottom-up,Õ or otherwise, the same core criteria apply to any BACT analysis: the applicant must consider all available alternatives, and [either select the most stringent of them or] demonstrate why the most stringent should not be adopted.Ó[11] Accordingly, the PSD permit applicant not only must identify all available technologies, including the most stringent, but it must also provide adequate justification for dismissing any available technologies.
Consistent with these core criteria, the EPAÕs New Source Review (NSR) Workshop Manual establishes that, as the first step in the Òtop-downÓ BACT analysis, the applicant must consider all ÒavailableÓ control options:
The first step in a "top-down" analysis is to identify, for the emissions unit in question (the term "emissions unit" should be read to mean emissions unit, process or activity), all "available" control options. Available control options are those air pollution control technologies or techniques with a practical potential for application to the emissions unit and the regulated pollutant under evaluation. Air pollution control technologies and techniques include the application of production process or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of the affected pollutant. This includes technologies employed outside of the United States. As discussed later, in some circumstances inherently lower-polluting processes are appropriate for consideration as available control alternatives.[12]
ÒThe term ÔavailableÕ is usedÉto refer to whether the technology Ôcan be obtained by the applicant through commercial channels or is otherwise available within the common sense meaning of the term.ÕÓ[13] In keeping with the stringent nature of the BACT requirement, EPA has repeatedly emphasized that ÒavailableÓ
is used in the broadest sense under the first step and refers to control options with a Òpractical potential for application to the emissions unitÓ under evaluation. . . . The goal of this step is to develop a comprehensive list of control options.[14]
EPA adjudicatory decisions also examine the core requirements for the BACT determination process. ÒUnder the top-down methodology, applicants must apply the best available control technology unless they can demonstrate that the technology is technically or economically infeasible. The top-down approach places the burden of proof on the applicant to justify why the proposed source is unable to apply the best technology available.Ó[15]
Whatever analytical process is utilized for determining BACT, these core criteria Ð the requirement to consider all available technologies, including the most stringent, and to provide adequate justification in the administrative record for dismissing any of the technologies based on relevant statutory factors Ð must be satisfied.
Thus, to conduct a BACT analysis consistent with the requirements of state and federal law for Highwood, MTDEQ must thoroughly evaluate all available control measures. IGCC is commercially available today. Montana and federal law therefore require that this technology be thoroughly evaluated as part of the Highwood BACT analysis.
Recent State Actions Requiring Consideration of Cleaner Coal Technology Establish Irrefutable Precedents for the Consideration of IGCC.
In March 2003, the State of Illinois required the
applicant for a proposed CFB coal-fired electric generation facility to conduct
a robust analysis of IGCC as a core element of its BACT analysis:
Additional material must be provided in the BACT
demonstration to address Integrated Gasification Coal Combustion (IGCC) as it
is a `production processÕ that can be used to produce electricity from
coal. In this regard, the Illinois
EPA has determined that IGCC qualifies as an alternative emission control
technique that must be addressed in the BACT demonstration for the proposed
plant. In addition, based on
the various demonstration projects that have been completed for IGCC, the
Illinois EPA believes that IGCC constitutes a technically feasible production
process.
Accordingly, Indeck must provide detailed information
addressing the emission performance levels of IGCC, in terms of expected
emissions rates and possible emission reductions, and the economic, environmental
and/or energy impacts that would accompany application of IGCC to the proposed
plant. This information must be
accompanied by copies of relevant documents that are the basis of or otherwise
substantiate the facts, statements and representations about IGCC provided by
Indeck. In this regard, Indeck as
the permit applicant is generally under an obligation to undertake a
significant effort to provide data and analysis in its application to support
the determination of BACT for the proposed plant.[16]
In an ensuing letter, the State of Illinois then
formally informed EPA that Illinois has Òconcluded that it is appropriate for
applicants for [proposed coal-fired power plants] to consider IGCC as part of
their BACT demonstrations.Ó[17]
Similarly, the Georgia Department of Natural
Resources, in a March 2002 letter regarding the permit application of Longleaf
Energy Station, also relied, in part, on the failure of the permit applicant to
consider cleaner coal combustion technology in finding the application deficient. In making its determination of
deficiency, Georgia stated that the applicant did not Òdiscuss any other
methods from generating electricity from the combustion of coal, such as
pressurized fluidized bed combustion or integrated gasification combined cycle.Ó
[18] Georgia further stated that the
applicant Òshould discuss these technologies and explain why you elected to
propose a pulverized coal-fired steam electric power plant instead.Ó[19]
Reflecting the viability of IGCC, the State of New
Mexico issued a letter on December 23, 2002 requiring the permit applicant for
a new coal-fired power plant to conduct a site-specific analysis of IGCC as
well as CFB as part of the BACT analysis for the proposed facility: ÒThe
Department requires a site-specific analysis of IGCC and CFB in order to make a
determination regarding BACT for the proposed facility.Ó The New Mexico determination goes
on to provide: ÒThe analysis must include a discussion of the technical
feasibility and availability of IGCC and CFB for the proposed site in McKinley
County, including a discussion of existing IGCC and CFB systems.Ó[20]
On August 29, 2003, New Mexico issued its evaluation
of the applicantÕs response. New
Mexico found that the applicantÕs BACT analysis had in fact indicated that IGCC
is commercially available but that the applicant had improperly relied on cost
to find that the technology was infeasible:
Mustang concludes that neither IGCC nor CFB are
technically feasible control options for the Mustang site. After careful review of the
revised BACT analysis, as well as information gathered from independent
sources, the Department determines that MustangÕs conclusion is not supported
by the evidence. Accordingly, the
Department finds that Mustang has not demonstrated the technical infeasibility
of IGCC and CFB. Moreover,
applying the criteria in the NSR Manual, the Department determines that IGCC
and CFB are technically feasible at the Mustang site, and must be evaluated in
the remaining steps of the top down BACT methodology.
(a)
IGCC and CFB are
technically feasible at the Mustang site.
A technology is considered to be technically feasible if it is
commercially available and applicable to the source under consideration. See NSR Manual at B.17-18. A technology is commercially available if it has reached a
licensing and commercial sales stage of development. Id. A technology is applicable if it has been specified in
a permit for the same or a similar source type. Id. MustangÕs revised BACT analysis indicates that IGCC is
commercially available, and IGCC has been specified in air quality permits for
coal-fired power plants. See,
e.g., Lima Energy Facility, 580
megawatt coal-fired power plant.
Similarly, CFB is commercially available and has been specified in air
quality permits for coal-fired power plants. See, e.g., AES
Puerto Rico 454 megawatt coal-fired power plant; Reliant Energy Seward 584
megawatt coal-fired power plant.
(b)
For both IGCC and CFB,
Mustang improperly relies on cost to determine technical infeasibility. A technology is technically
feasible when the resolution of technical difficulties is a matter of
cost. See NSR Manual at B.19-20. MustangÕs revised BACT analysis indicates that the
resolution of technical difficulties for both IGCC and CFB are a matter of
cost. These costs do not support a
finding of technical infeasibility, but may be considered during Step 4 of the
top down BACT methodology. See NSR Manual at B.26.[21]
Indeed, the Montana Board of Environmental Review has found that MTDEQ must consider IGCC as an available technology in the BACT review for a coal-fired power plant. Specifically, the Board of Environmental Review stated Ò. . .the Department should require applicants to consider innovative fuel combustion techniques in their BACT analysis and the Department should evaluate such techniques in its BACT determination in accordance with the top-down five-step method.Ó[22]
It would be arbitrary and capricious were Montana not
to require consideration of IGCC as an available and technically feasible
technology in the Highwood BACT analysis.
The December 2002 and August 2003 New Mexico determinations and the
March 2003 Illinois determination are attached hereto.
MTDEQ Failed to Adequately Address IGCC in the BACT Analysis.
IGCC is an available method, system and technique for curbing air pollutants from Highwood consistent with MontanaÕs definition of BACT. Electricity generation from coal using IGCC technology is a commercially available and proven process. IGCC units generate electricity by integrating a coal gasifier with combined cycle (combustion turbine and steam turbine) electricity generation equipment (see figure below).
Two full scale commercial IGCC electric generating units are in operation in the United States: Tampa Electric CompanyÕs 262 MW unit at the Polk plant in Florida and CinergyÕs 192 MW unit at the Wabash River plant in Indiana, which both rely on coal as a fuel source.[23] Two other coal-based IGCC plants operate in Europe, NUON/Demkolec is a 253 MW plant in the Netherlands, and ELCOGAS in Spain is 298 MW.[24] IGCC units can be constructed with multiple gasifiers to achieve unit availability at levels comparable to those of conventional baseload facilities. For instance, the Eastman Chemical plant in Kingsport, Tennessee has utilized a dual-gasifier design to produce chemicals from syngas and has experienced 98 percent availability since 1986.[25] ChevronTexaco claims that its new Standard Project Initiative Reference IGCC Plant achieves greater than 90% availability by using multiple gas trains.[26]
Worldwide there are 131 gasification projects in operation with a combined capacity equivalent to 23,750 MW of IGCC units.[27] An additional 31 projects are planned that would increase this capacity by more than 50 percent.[28] Although not all of these projects produce electricity from coal, they demonstrate widespread commercial application of gasification technology for fuel processing, one of two key components of an IGCC plant. The second component is a combined cycle electricity generating system, which is now commonplace for new natural gas fired power plants.
IGCC units are available from major well-known vendors. Coal gasification equipment is available from GE[29], Shell, and Global Energy, while major turbine manufacturers, including GE and Siemens-Westinghouse, provide combined cycle generators designed to run on the synthesis gas produced by coal gasifiers. Engineers from Texaco, Jacobs Engineering, and GE have teamed up to offer a standardized IGCC design.[30] James Childress, the Executive Director of the Gasification Technology Council, provided testimony to the U.S. Senate Environment and Public Works Committee stating, Ò[g]asification is a widely used commercially proven technology.Ó[31] At the same hearing, Edward Lowe, Gas Turbine-Combined Cycle Product Line Manager for General Electric Power Systems, stated that, ÒIGCC is inherently less polluting and more efficient than any other coal power generation technology.Ó[32] Likewise, the National Coal Council, in a May 2001 report, confirms that IGCC is "viable, commercially available technology."[33] ChevronTexaco, in an October 2002 presentation, states that, ÒIGCC is a current viable choice for clean coal capacity.Ó[34] And the Center for Energy and Economic Development (CEED) states that, ÒIGCC technology is available for deployment today.Ó[35]
The
coal gasification fuel-processing step in IGCC power plants results in superior
environmental performance and lower emissions compared to the CFB technology that
is proposed for the Highwood power plant.
Gasifying coal at high pressure prior to combustion facilitates removal
of pollutants that would otherwise be released into the air. According to James
Childress, ÒÉcriteria pollutant emissions for a coal-based IGCC plant are well
below those of even the most modern pulverized coal plants with post combustion
cleanup.Ó[36] Mercury removal rates of greater than
90 percent can also be achieved using currently available control technologies
with IGCC. DOE states that Òan
IGCC power plant has the potential of achieving very high mercury removal
performance with established technologyÓ and mercury removal in an IGCC power
plant can be expected to be very high in removal effectiveness, low in cost,
and reliable in design.Ó[37]
Table 1 summarizes the Highwood proposed permit emission rates with permit emission rates for an IGCC plant using the design fuel for Highwood. For each of the important pollutants in the BACT analysis, IGCC is the top ranked technology or is equivalent to the proposed Highwood emission limits.
Table
1: Emission Rates
|
|
Highwood Proposed Emission Rates |
IGCC Permit Emission Rates* |
|
|
(lb/MMBtu) |
(lb/MMBtu) |
|
NOx |
0.07 |
0.07 |
|
VOC |
0.003 |
0.0017 |
|
PM10 |
0.026 |
0.011 |
|
CO |
0.10 |
0.03 |
|
Sulfuric Acid Mist |
0.0042 |
0.0005 |
|
SO2 |
0.038 |
0.014 |
|
Hg |
0.0000015 |
0.0000005 |
|
* All IGCC emission rates for the BACT analysis come from Elm Road IGCC air permit issued by Wisconsin DNR in January 2004, with the exception of SO2 and Hg. For SO2, the permit limit is assumed to be 99% removal from the Highwood design fuel.[38] For Hg, 95% control was assumed. |
||
For the limits found in Table 1 under baseload conditions, IGCC would yield lesser amounts of all criteria pollutants except NOx and significantly lower amounts of the climate changing emissions CO2 and N2O. Furthermore, IGCC allows for an option to make even deeper cuts in carbon dioxide that conventional coal plants cannot do. The CO2 in the syngas can be captured and sequestered at a fraction of the cost of post-combustion carbon capture and sequestration at other coal plants.
IGCC is clearly an available method, system and technique for producing electricity from coal and thus must be fully and fairly evaluated in the Highwood BACT analysis. Highwood and/or MTDEQ must develop average and incremental costs for each pollutant removed and compare these costs to the proposed configuration of the Highwood facility.
3. THE PROPOSED BACT EMISSION LIMITS FAIL TO REFLECT THE MAXIMUM LEVEL OF CONTROL THAT CAN BE ACHIEVED
The SO2 Emission Limit Does Not
Reflect BACT
The proposed BACT limit for SO2 and BACT analyses are flawed because they do not reflect the maximum degree of reduction that can be achieved. MTDEQ has proposed an SO2 emission limit of 0.038 lb/MMBtu (30-day average) as BACT which reflects 97.3% control. MTDEQ has also proposed shorter term average SO2 limits of 0.057 lb/MMBtu (3-hour average) and 0.048 lb/MMBtu (24-hour average). However, lower emission limits and greater percent removal have been required as BACT at other CFB boilers. Indeed, for the SO2 control technologies evaluated, MTDEQ did not evaluate the maximum degree of emission reduction that could be achieved.
First, two different coal-fired CFB power plants have been
required to meet an SO2 BACT limit of 0.022 lb/MMBtu, which is much
lower than the proposed BACT limit at Highwood of 0.038 lb/MMBtu. Specifically,
the Sevier power plant in Utah, a 270 MW bituminous coal-fired CFB power plant
to be equipped with a circulating dry scrubber, was required in its October
2004 PSD permit to meet an SO2 BACT emission limit of 0.022 lb/MMBtu
on a 30-day average. A copy of the
final permit for the Sevier power plant is attached.
In addition, the 2 unit 454 megawatt AES-Puerto Rico CFB plant, also
equipped with a circulating dry scrubber, is required to burn low sulfur coal
(1% or less) and meet a 0.022 lb/MMBtu SO2 limit on a three-hour
average. A copy of the final permit for AES-Puerto Rico is
attached. Based on the worst-case
coal quality to be used at AES-Puerto Rico (0.8% and 12,000 BTU/lb), the uncontrolled
SO2 emission rate of AES-Puerto Rico is 1.6 lb/MMBtu, similar to the
uncontrolled SO2 emission rate at Highwood. Further, the AES-PR plant is using a
circulating dry scrubber on its CFB boiler, a technology that MTDEQ improperly
eliminated from review in its BACT analysis as technically infeasible because
there is only limited application to large CFB boilers and because of high
pressure drop across a fabric filter baghouse (which MTDEQ determined to be
BACT for particulate matter) due to high particulate loadings. (MTDEQ Permit Analysis at 18.) Clearly, a circulating dry scrubber
is operating on the AES-Puerto Rico
units which are of similar size to the proposed Highwood Generating
Station. Because a circulating dry
scrubber is technically feasible for use at Highwood, MTDEQ must provide further
evaluation of this SO2 control technology in its BACT analysis,
including consideration of other options to address the pressure drop
issue. MTDEQ also dismissed
the lower SO2 emission limit at AES-Puerto Rico because, to the best
of their knowledge, compliance with this emission limit had not yet been
demonstrated. MTDEQ must provide
more information on this statement.
Has the EPA determined that the 0.022 lb/MMBtu emission limit cannot be
met at AES-Puerto Rico? If so, is
AES-Puerto Rico none-the-less meeting an emission limit that is more
restrictive than the SO2 emission limits proposed by MTDEQ? If so, then that level of SO2
control must be evaluated in MTDEQÕs BACT analysis for Highwood. According to information on AESÕs
website, AES-Puerto Rico began commercial operation in November 2002. Surely, there must be more information
available on the facilityÕs compliance with the SO2 emission limit
required as BACT in their PSD permit.
In addition, a higher level of
SO2 control was also required at the recently permitted Gascoyne
power plant in western North Dakota, a 175 megawatt power plant using a CFB
boiler and burning North Dakota lignite.
The BACT SO2 emission limit for this facility is also 0.038
lb/MMBtu (30-day average) but this limit reflects an overall 98.9% SO2
removal using a CFB boiler with limestone injection plus a spray dry absorber[40],
as compared to the overall level of SO2 control of 97% that MTDEQ
based its proposed SO2 BACT emission limit on for Highwood. Thus, MTDEQ must consider the level of
SO2 removal required in the Gascoyne BACT limits in setting the SO2
BACT limit for Highwood.
Further, MTDEQ assumed in its
BACT analysis that use of a CFB with a spray dry absorber or with a wet
scrubber would only achieve the same emission rate (0.038 lb/MMBtu) as projected
to be met with the proposed CFB and the hydrated ash reinjection system (HAR)
system. MTDEQ did not explain the
basis of assuming a 0.038 lb/MMBtu emission rate for either a CFB + wet
scrubber or a CFB + spray dryer absorber and, in fact, information in MTDEQÕs
preliminary determination contradicts this assumption. Specifically, MTDEQ indicated that a
wet scrubber can achieve 90-95% SO2 removal and a spray dry absorber
can achieve up to 95% SO2 control (MTDEQ Permit Analysis at 19),
whereas the HAR system is only projected to achieve 60-80% SO2
control (Permit Analysis at 17).
Thus, assuming 90% control at the CFB boiler plus an additional 90%
control at the wet scrubber or spray dryer (and these are the low end of the
ranges of SO2 removal efficiency that can be achieved with these
technologies) equates to an overall SO2 removal efficiency of 99%,
much higher than the assumed 97% control efficiency assumed for these control
technology combinations. This is
also in-line with the overall 98.9% removal on which GascoyneÕs SO2
BACT limit is based on (with the use of a CFB plus a spray dry absorber) and
the almost 99% SO2 removal required at AES-Puerto Rico which burns
coal with a similar uncontrolled SO2 emission rate as the proposed
worst case coal to be used at Highwood (but achieved with the use of a CFB plus
a circulating dry scrubber). Thus,
MTDEQ should have evaluated these SO2 control combinations assuming
at least 99% control in the BACT analysis, and a cost effectiveness analysis
should also have been done to support the choice of the less effective HAR
system with the CFB as BACT.
In addition, the 3-hour and 24-hour SO2 BACT emission rates proposed by MTDEQ are too lax, given that the AEP-Puerto Rico CFB plant is subject to an emission rate equivalent to almost 99% removal on a 3-hour averaging time using a lower sulfur coal. No adequate justification was given by MTDEQ to provide Highwood with less stringent short term average SO2 BACT emission limits. BACT is supposed to be based on the maximum degree of reduction achievable. If it was determined that the AES-Puerto Rico CFB plant could meet almost 99% SO2 removal on a three hour average with a lower sulfur coal, than Highwood should be able to meet at least the same level of SO2 removal on a 3-hour and 24-hour basis, especially given that MTDEQ is proposing alternative emission limits for startup and shutdown at Highwood.
In addition, MTDEQ failed to impose an overall SO2 percent removal requirement in the draft permit. Given the wide variability in the uncontrolled SO2 emissions of the proposed coals to be used at Highwood with uncontrolled SO2 emissions ranging from 0.73 lb/MMBtu to 1.42 lb/MMBtu (see table 5.3-1 of HighwoodÕs 11/30/05 permit application), it is imperative that MTDEQ also impose a percent removal requirement to ensure that the maximum reduction of SO2 is required regardless of the type of coal burned. As the draft permit stands now, the 0.038 lb/MMBtu limit could reflect only 94.8% SO2 control when clearly much higher levels of control can be achieved.
Thus, for the above reasons, the proposed SO2 BACT emission limits and determination for Highwood is flawed and fails to ensure that the maximum reduction in emissions will be achieved.
The Proposed NOx Limit Does Not
Reflect BACT
The proposed NOx BACT emission limit of
0.07 lb/MMBtu (30-day average) does not reflect the maximum degree of reduction
that can be achieved at CFB boilers.
HighwoodÕs NOx BACT analysis indicated that selective
noncatalytic reduction (SNCR) systems have been designed to achieve 40-60%
removal of NOx, and yet only a 50% removal efficiency was considered
in determining the achievable emission rate with SNCR of 0.07 lb/MMBtu. (See Table 5.3-14 of the November 2005
Highwood permit application). No
justification was provided to adequately support why 60% removal could not be
met at Highwood with SNCR. At 60%
removal, a NOx emission rate of 0.06 lb/MMBtu could be met. MTDEQ must evaluate as part of the BACT
analysis an SNCR system designed to remove at least 60% of the NOx
from the flue gas. At the very
minimum, MTDEQ should have required SNCR optimization studies to be done within
the first year or two of operation of Highwood to determine if a lower NOx
emission limit could be met.
In addition, MTDEQ did not provide any justification
of why the proposed NOx BACT limit of 0.07 lb/MMBtu could not be met
on a 24-hour average basis or a 1-hour average basis. Many other recent permits for coal-fired power plants have
required 24-hour average 0.07 lb/MMBtu emission limits as BACT, including the
proposed Roundup power plant in Montana.
Considering that MTDEQ is proposing alternative emission limits during
startup and shutdown and considering that other recently permitted coal-fired
power plants must meet 0.07 lb/MMBtu on a 24-hour average, a higher 24-hour
average NOx BACT emission limit is not justified for Highwood.
Further, in evaluating selective catalytic reduction
(SCR) at Highwood, the company assumed a total annual cost of over $18 million
per year for an SCR system. These
costs seem high. Indeed, for the
Gascoyne permit, use of a low dust SCR system with its CFB boiler was projected
to cost $6.7 million per year.[41] Thus, the annualized cost of SCR at
Highwood should be re-evaluated to determine if the cost effectiveness of SCR
at Highwood might be reasonable when compared to the costs of NOx
control at other coal-fired power plants.
For all of the above reasons, the NOx
BACT analysis for Highwood is flawed.
The PM Emission Limit Also Does Not Reflect BACT
The proposed BACT PM emission limit for Highwood of
0.012 lb/MMBtu does not reflect BACT.
The Northampton Generating Station, a CFB boiler in Pennsylvania, is
subject to a much lower PM10 limit of 0.0088 lb/MMBtu. Two other CFB plants (JEA Northside and
York County Energy Partners) are required to meet a PM10 limit of
0.011 lb/MMBtu. Because the costs
of meeting the lower PM10 emission limits were reasonable for these
plants, that must be taken into account in determining whether the cost for
meeting a lower PM limit at Highwood is reasonable. MTDEQ did not provide a thorough analysis to justify why
Highwood could not meet a lower limit.
The BACT analysis for Highwood must also include a visible emission limit reflective of BACT for the source. Without any evaluation, MTDEQ proposed a 20% opacity limit, with one six minute period per hour not to exceed 27% opacity, as BACT. (MTDEQ Permit Analysis at 27). Indeed, with a fabric filter baghouse for PM10 control, an opacity BACT limit should be at least 10%, if not lower with the Teflon-coated bags upon which MTDEQÕs proposed BACT limit is based. For example, the state of Utah recently issued two permits for coal-fired power plants to be equipped with fabric filter baghouses Ð Intermountain Power Unit 3 and the Sevier power plant Ð which both have 10% opacity limits required as BACT (both attached).
Thus, MTDEQ must evaluate PM and opacity BACT more thoroughly, considering the lower PM and opacity BACT limits that have been required at other coal-fired power plants as BACT.
The
H2SO4 Limit Does Not Reflect BACT
MTDEQ has proposed a BACT limit for sulfuric acid mist (H2SO4) of 0.0054 lb/MMBtu. Yet much lower H2SO4 limits have been required at recently permitted similarly equipped CFB units, including the Gascoyne power plant (H2SO4 BACT limit is 0.0028 lb/MMBtu) and the Sevier power plant (H2SO4 BACT limit is 0.0024 lb/MMBtu). MTDEQ must evaluate these lower H2SO4 limits in the BACT analysis for Highwood and provide sufficient justification for its H2SO4 BACT determination. In the permit analysis for Highwood, MTDEQ simply acknowledges that the H2SO4 emission rate is not the lowest (MTDEQ Permit Analysis at 40), but does not provide any justification for its determination that 0.0054 lb/MMBtu reflects the maximum degree of reduction of H2SO4 that can be achieved.
The Proposed Mercury Limit Does Not Meet BACT
MTDEQ has proposed a mercury BACT emission limit of
either 1.5 lb/TBtu or 90% control, but MTDEQ did not specify any additional
control technology for mercury other than the planned criteria pollutant
controls. As determined by MTDEQ,
activated carbon injection is an
available mercury control technology (see MTDEQ Permit Analysis at 48), and yet
MTDEQ did not require full evaluation of activated carbon injection in the BACT
analysis. As indicated by MTDEQ,
the owners of two new coal-fired power plants in Montana have agreed to use
activated carbon injection for mercury control (i.e., Hardin and Roundup) and
both of these facilities will burn subbituminous coal similar to Highwood. Activated carbon injection (ACI) has
also been required by the state of Iowa at the subbbituminous coal-fired
Council Bluffs Unit 4.[42] Clearly, this is an available
technology for subbituminous coal-fired power plants.
HighwoodÕs test burn data from May 2005, which was
submitted to the MTDEQ demonstrates an ability to achieve very low mercury
emissions using ACI. Without ACI the test burn showed Hg emissions of 0.7 lbs
Hg/TBtu. The addition of ACI
reduced Hg emissions by 93% to 0.4 lb Hg/TBtu.
Because the costs of activated carbon injection were
considered reasonable for mercury control at two subbituminous coal-fired power
plants, MTDEQ must also consider the costs of activated carbon injection to be
reasonable at Highwood. Thus,
MTDEQ must require installation of an ACI or other sorbent injection system as
BACT for mercury reductions at Highwood.
The corresponding BACT emission limit must reflect at least 90% control
from uncontrolled emissions (the level of control which MTDEQ considers
equivalent to activated carbon injection, see Permit Analysis at 48). Both an emission limit and a percent
control requirement should be imposed to ensure high levels of mercury control
regardless of the variability of mercury in the coal. If any exemption from mercury-specific controls is given to
Highwood, it should only be of limited duration. Three months should be sufficient time for a determination
of the mercury removal effectiveness of the criteria pollutant control
equipment. If the criteria
pollutant controls cannot achieve 90% control, then the company should be
required to begin operating a sorbent injection system immediately to minimize
to the greatest extent possible the amount of mercury emitted to the air. Under
no circumstance is it acceptable to delay by 18 months the operation of an ACI
system if mercury emission limits are not met immediately.
4.
The BACT Limits Must Meet Enforceability Criteria
All BACT limits must be enforceable and thus must
include provisions to ensure enforceability, but the draft Highwood permit does
not include such provisions.
Specifically, as discussed in EPAÕs October 1990 Draft New Source Review
Workshop Manual, ÒBACT emission limits or conditions must be met on a continual
basis at all levels of operation (e.g., limits written in lb/MMBtu or percent
reduction achieved), demonstrate protection of short term ambient standards
(limits written in pounds per hour) and be enforceable as a practical matter (contain
appropriate averaging times, compliance verification procedures and
recordkeeping requirements).Ó (NSR
Workshop Manual at B.56). MTDEQ
did not propose sufficient conditions to ensure the enforceability of its
proposed BACT limits.
As discussed above with respect to SO2,
not only is a lb/MMBtu limit needed that reflects BACT, but also a percent SO2
reduction requirement is necessary due to the variability of the sulfur in the
coal to ensure that high levels of SO2 control reflective of BACT
are met even when the facility is burning coal with sulfur content lower than
the worst case coal assumed to be used at Highwood. Similarly, the mercury BACT emission limit must include both
a lb/MMBtu limit and a percent reduction requirement.
With respect to all of the emission limits, there
must be pound per hour emission caps established, in addition to lb/MMBtu
limits, reflective of BACT and consistent with what is modeled to show
compliance with the NAAQS, PSD increments and visibility standards. The October 1990 Draft NSR Workshop
Manual indicates that it is best to express emission limits in two different
ways, Òwith one value serving as an emissions cap (e.g., lb/hr) and the other
ensuring continuous compliance at any operating capacity (e.g., lb/MMBtu).Ó See NSR Workshop Manual at H.5. See also IN RE Steel Dynamics, Inc.,
PSD Appeal Nos. 99-4 & 99-5, Decided June 22, 2000, at 220-225. For all pollutants except PM, MTDEQ
only proposed lb/MMBtu emission limits, and has not proposed any enforceable
cap on hourly emissions. There
also is no limit on hourly heat input. Thus, there is no assurance that the hourly emission
rates used in the modeling analyses will actually be complied with. Absent pound per hour emission caps, or
a maximum hourly heat input cap that could be used to convert lb/MMBtu emission
limits to a max lb/hr limit, modeling analyses for Highwood must evaluate the
impacts of the facilityÕs uncontrolled emissions.
The permit application must also specify appropriate
compliance methods and recordkeeping requirements to show compliance with these
emission limits. As discussed in
the NSR Workshop Manual, Òthe construction permit should state how compliance
with each limitation will be determined.Ó
(See NSR Workshop Manual at H.6.).
The test methods must provide for continuous compliance where
feasible. While MTDEQ is requiring
continuous compliance test methods for opacity, SO2, and NOx, continuous emission monitors are also
available for CO, PM, and mercury.
MTDEQ should require continuous monitoring for all of these emission
limits. With respect to mercury,
MTDEQ must also mandate coal testing requirements to ensure compliance with 90%
mercury removal requirement proposed by MTDEQ.
5. THE PERMIT MUST INCLUDE EMISSION LIMITS CONSISTENT WITH THE STARTUP/SHUTDOWN MODELING ANALYSIS
The draft Highwood permit includes alternative
emission limits for startup and shutdown.
Although the company performed modeling analyses to demonstrate that the
national and Montana ambient air quality standards (NAAQS/MAAQS) would be met,
the permit does not include emission limits for PM10 or SO2
(3 hr and 24 hr averages) to ensure that emissions do not exceed the levels
that were modeled. Further, the
carbon monoxide limit in section II.B.5. of the draft permit is higher than the
level of emissions modeled in the startup modeling (the permit allows 194
lb/hr, but only 111 lb/hr was modeled as shown in Table 6.3-4 of the 11/05
Highwood permit application). The
permit must include startup and shutdown emission limits consistent with the
levels modeled, or the modeling analyses must be redone to reflect uncontrolled
emissions of SO2 and PM10, and a higher carbon monoxide
emission rate of 194 lb/hr.
6. STARTUP/SHUTDOWN MODELING MUST ALSO BE
PERFORMED TO SHOW COMPLIANCE WITH THE CLASS I INCREMENTS AND AIR QUALITY
RELATED VALUES, AS WELL AS THE CLASS II NO2 INCREMENT
Modeling analyses of the alternative
startup/shutdown emission limits were only performed to assess compliance with
the NAAQS/MAAQS and the Class II increments for SO2 and PM10. It is not clear why no modeling was
done for the annual Class II NO2 increment. The higher NOx emissions
during startup and shutdown will impact the annual NO2
concentrations, and thus an analysis of impacts on the NO2 increment
should have been done. Such an
analysis should have been based on a worst case assessment of the length of
time the boiler would be in startup/shutdown mode throughout the year.
In addition, modeling demonstrations should also
have been done to show that the alternative startup/shutdown emission limits
would not adversely affect the Class I increments or visibility or other air
quality related values. Further,
the permit must include startup/shutdown emission limits consistent with the
ambient impacts that are being modeled (including consistent averaging
times). Without such limits, the
facility should be modeled at uncontrolled emissions. With respect to visibility, the modeling demonstration must
evaluate the same pollutants that were modeled in the normal operation
visibility analysis (PM, SO2, NOx, and SO4).
MTDEQ cannot issue a permit that allows for an
exemption from BACT during startup and shutdown without an adequate
demonstration that the alternative emission limits will not result in a
violation of any PSD increment or adversely impact visibility or other air
quality related values (as well as not cause or contribute to a NAAQS/MAAQS
violation).
7. STARTUP/SHUTDOWN EMISSIONS SHOULD HAVE BEEN MODELED TO DETERMINE IF HIGHWOOD WOULD EXCEED THE MONITORING DE MINIMUS CONCENTRATIONS AND THE NAAQS SIGNIFICANT IMPACT LEVELS
Because the draft permit allows higher emissions for
startup and shutdown, the determination of whether one year of ambient
monitoring is needed or whether a cumulative NAAQS analysis is required must be
based on the worst case emissions Ð i.e., emissions during startup and shutdown
which can last (according to the draft permit) as long as 48 hours. Until such
modeling is completed, it is not clear whether Highwood was properly exempted
from one year of preconstruction monitoring of other pollutants including NO2,
SO2, or carbon monoxide.
Further, MTDEQ also cannot properly determine that the facility will not
cause or contribute to a violation of the carbon monoxide NAAQS.
8. USE OF
SIGNIFICANT IMPACT LEVELS FOR CLASS I PSD INCREMENTS ARE ILLEGAL
The Class I increment modeling for Highwood relied on Òsignificant impact levelsÓ to justify not conducting cumulative Class I increment modeling analyses for NO2 or PM10 and to limit the cumulative SO2 increment analyses to the Gates of the Mountains Wilderness and the Scapegoat Wilderness. However, no state or federal regulation allows for a permit applicant to be exempt from the PSD requirement to show that the proposed source wonÕt cause or contribute to a violation of the PSD increments based on an ÒinsignificantÓ ambient impact.
While EPA proposed use of such Class I significant impact levels in July of 1996, EPA never finalized promulgation of those significant impact levels. Until significant impact levels for Class I increment analyses are promulgated by EPA and incorporated into MontanaÕs regulations and state implementation plan (SIP), any impact in a Class I area by Highwood must warrant a cumulative PSD increment analysis. Thus, cumulative Class I increment analyses must be performed for all affected Class I areas and for all increment pollutants.
It also must be noted that, even if such significant impact levels were legitimate to exempt Highwood from cumulative Class I increment modeling, any determination of whether Highwood would have a significant impact on a Class I area must be based on the worst case emissions expected from the facility Ð i.e., the emissions during startup and shutdown.
9. MTDEQ FAILED TO PROVIDE ITS RATIONALE FOR FINDING THAT HIGHWOOD WOULD NOT ADVERSELY IMPACT VISIBILITY IN ANY CLASS I AREA
As stated in MTDEQÕs permit analysis, ARM 17.8.1106(1) requires the MTDEQ to determine that Highwood would not cause or contribute to an adverse impact on visibility in any Class I area in order for the permit to be issued. MTDEQ provided visibility modeling results in Table 7 of its permit analysis, which reflects SMEGTCÕs Òrefined methodology.Ó The results of SMEGTCÕs Òrefined methodologyÓ indicate that Highwood would cause greater than 5% changes in visibility at the Bob Marshall, Gates of the Mountains, and Scapegoat wilderness areas. The Federal Land Managers (FLMs) consider a 5% or greater change as a level of concern indicating possible adverse impact on visibility. (See the Federal Land ManagersÕ Air Quality Related Values Workgroup (FLAG) Phase I Report at 26 (December 2000)) Further, the cumulative analyses, again using Òrefined methodology,Ó showed Highwood would contribute to visibility impacts that would cause greater than 10% changes in visibility. The FLMs consider a 10% or greater change as unacceptable. Id.
Yet, MTDEQ found that Highwood would not cause or contribute to an adverse impact on visibility in any Class I area. MTDEQ provided no justification for its finding, other than stating that it found Highwood would not interfere with the management, protection, preservation, or enjoyment of the visual experiences of visitors to these Class I areas and that MTDEQ took into account Òthe geographic extent, intensity, duration, frequency, and time of visibility impairment, and how these factors correlate with times of visitor use of the federal Class I area, and the frequency and occurrence of the natural conditions that reduce visibility.Ó MTDEQ Permit Analysis at 82. MTDEQ must provide the details of its determination, especially considering that, using FLAG procedures, Highwood would be considered to adversely impact visibility. Specifically, Table 7.7-3 of SMEGTCÕs 11/30/05 permit application shows the predicted visibility impacts due to Highwood using FLAG methodology, and the results indicate that Highwood would cause greater than 10% change in visibility at the Bob Marshall, Gates of the Mountains, and Scapegoat wilderness areas and also at Glacier National Park. As discussed further below, SMEGTCÕs refined methodology is not consistent with FLAG procedures or current FLM guidance for visibility impact modeling. MTDEQ apparently finds SMEGTCÕs methodology valid, but provides no detailed determination for the public to review. The public must be afforded the opportunity to review and comment on the details of MTDEQÕs determination and, without such opportunity, MTDEQÕs determination is entirely unjustified.
10. SMEGTCÕs
REFINED VISIBILITY MODELING DID NOT FOLLOW FLM PROCEDURES AND UNDERESTIMATES
HIGHWOODÕS IMPACT ON NEARBY CLASS I AREAS
After determining that Highwood would cause changes in visibility greater than 5% at five Class I areas in Montana and greater than 10% at four of those Class I areas (the Bob Marshall, Gates of the Mountains, and Scapegoat wilderness areas as well as Glacier National Park), SMEGTC ÒrefinedÓ their visibility modeling methodology to essentially minimize the predicted visibility impacts. However, SMEGTCÕs methodology does not comport with current FLM guidelines for such analyses. Specifically, for each modeled day with a predicted change in visibility of 5% or greater, SMEGTC evaluated the weather on that day, including such things as whether there was 50% or more cloud cover, a ceiling height of 5,000 feet or less (because the cloud cover would obstruct the view of the mountains from the plains and also the view from the mountains), visibility less than 20 miles as determined by the nearest airport, weather events, relative humidity greater than 70%, and average daily visual range. See SMEGTCÕs November 30, 2005 permit application at 7-30. Then, instead of comparing HighwoodÕs visibility impacts to natural visibility conditions for which the FLMs provide background values in the FLAG guidance, SMEGTC determined an Òairport derivedÓ change in visibility by determining background visibility conditions for that day from airport data. The result of this change in methodology was that HighwoodÕs visibility impacts were greatly minimized as compared to when FLAG procedures were followed. Use of airport data to determine background visibility conditions takes into account more than local weather conditions of that day Ð it also takes into account all of the other visibility impairing emissions that are impacting visibility on that day. This differs from FLAG procedures in which a new sourceÕs impacts are compared to natural background conditions. Further, weather conditions at the nearest airport are not necessarily reflective of weather conditions at the Class I area.
In any case, the FLMs have previously found that use of on the ground precipitation data is not appropriate to discount high visibility impacts. The FLMs have found it appropriate in certain cases to address high levels of humidity (and the likely resulting precipitation) in the CALPUFF model, by either capping humidity in the model or by ignoring all hours of high humidity. See, e.g., January 7, 2003 facsimile from Don Codding, National Park Service, to Dan Walsh, Montana Department of Environmental Quality (attached). But it must be noted that the FLMs did not consider a relative humidity level as low as 70% to be necessarily associated with visibility impairing weather. In the modeling of the Intermountain Power Plant, for example, the FLMs eliminated hours from the visibility impacts analysis when relative humidity was greater than 90%, assuming a precipitation event was likely occurring. See May 2004 National Park Service Supplemental Technical Comments on the Intermountain Power Agency Prevention of Significant Deterioration Permit Application for the Addition of Unit 3 at its Intermountain Power Plant, at 11 (attached).
Thus, SMEGTCÕs refined visibility methodology must be rejected by MTDEQ as inconsistent with current FLM guidance for such visibility impact assessments. Instead, MTDEQÕs determination of whether Highwood would cause or contribute to an adverse impact on visibility must be based on SMEGTCÕs initial visibility modeling results that apparently followed FLAG procedures (i.e., Table 7.7-3 of SMEGTCÕs 11/30/05 permit application).
11.
THE CUMULATIVE VISIBILITY IMPACTS ANALYSIS MUST INCLUDE ALL INCREMENT
CONSUMING SOURCES, IN ACCORDANCE WITH FLAG GUIDANCE
FLAG guidance states that a cumulative visibility analysis should at the minimum include all increment consuming sources. FLAG at 26. SMEGTC did not include all increment-consuming sources in its cumulative visibility modeling. Specifically, SMEGTC did not include emissions from the Montana Refining Company or AgriTechnology Corp. even though these were considered as increment consuming sources in the cumulative increment analysis. (See, e.g., page 6-16 of SMEGTCÕs 11/30/05 permit application). Further, SMEGTC must include all permitted but not yet operating sources in the cumulative visibility analysis if those sources could impact the Class I area being modeled, including the Roundup Power Plant and the Hardin Generating Station. Thus, the cumulative visibility analysis must be redone to include all increment consuming sources, as well as to be consistent with FLAG procedures as discussed in the comment above.
Thank you for considering these comments.
Sincerely,
Anne Hedges
Program Director
Attachments