ordinance that would require a public vote to approve any Conditional Use Permit issued for the 

project. 

 

Sevier is closest to Capitol Reef National Park and other Class I areas in Utah and 

appears to be more than 300 km from the Jarbidge Wilderness in Nevada. As such, it probably 

falls outside the distance at which adverse impacts to visibility at Jarbidge could be expected and 

probably does not need to be considered in Nevada’s Regional Haze SIP. However, this project 

may contribute to the cumulative visibility impacts at Class I areas in southwestern Utah, 

including Bryce Canyon and Zion National Parks. 

 

3.1.6 Intermountain Power Project Unit 3 (UT)

 

The Intermountain Power Project (IPP) is owned and operated by the Los Angeles 

Department of Water and Power (LADWP) and PacifiCorp. IPP has two existing coal-fired

EGUs sized at 900 MW each at a site near Delta, UT. A third 900 MW coal-fired EGU has been 

proposed for this site, which is about 300 km distant from Jarbidge. 

 

A final air quality permit for Unit 3 was issued by UDAQ, but this permit was then 

appealed by the Sierra Club and Grand Canyon Trust. Then, in 2007, the six California cities that 

take the majority of IPP’s power refused to support construction of a third coal-fired EGU. Also, 

PacifiCorp formally announced cancellation of Unit 3 in December 2007. However, in January 

2008, the Utah Associated Municipal Power System (UAMPS), a group of 23 Utah communities 

and six electric cooperatives that pledged to purchase 50% of the power generated by Unit 3, 

sued to force LADWP to proceed with the plan to construct Unit 3. 

 

As of May 2009, the final PSD permit for IPP Unit 3 has not been terminated by UDAQ 

nor has the air permit application been withdrawn by the proponent. In fact, in April 2008, the 

Utah Department of Environmental Quality (UDAQ) granted an extension of the IPP Unit 3 air 

quality permit to October 15, 2009 [Reference 11]. The IPP Unit 3 emissions are estimated at 

3,183 tpy for both SO2 and NOx [Reference 12]. 

 

Because the IPP Unit 3 permit remains active, these emissions need to be part of 

Nevada’s SIP planning process. However, as IPP Unit 3 is part of the 2018 WRAP inventory, 

these emissions were already included in Nevada’s regional haze SIP. 

 

3.1.7 Power County Advanced Energy Center (ID)

 

The Power County Advanced Energy Center (PCAEC) is a project to gasify coal and 

petroleum coke for use in the production of nitrogen fertilizers and elemental sulfur. The project 

developer is Southeast Idaho Energy LLC (Refined Energy Holdings) and the project site is near 

American Falls, ID. 

 

Based on information from SourceWatch [Reference 13], the original plans for this

project included a 520 MW Integrated Gasification Combined Cycle (IGCC) power plant. The 

original air quality permit filed by PCAEC in 2007 included on-site power generation, albeit at a 

D-109 
significantly smaller size (60-70 MW). However, these plans were later withdrawn in 2008 when 

PCAEC filed a revised air permit application. 

 

PCAEC was issued an air quality permit by the Idaho Department of Environmental 

Quality (IDEQ) on February 10, 2009 (Permit P-2008.0066). Following issuance of the permit, a 

Petition for Contested Case Proceeding was filed by Sierra Club, Idaho Conservation League, 

and the Shoshone-Bannock Tribe with the Board of Environmental Quality. This permit appeal is 

still pending. 

 

The allowable PCAEC emissions listed in the IDEQ permit are small, 109 tpy for NOx

and only 23 tpy for SO2 [Reference 14]. However, based on an initial review of this permit, it 

appears that these emissions may have been underestimated (a detailed review of the PCAEC 

permit documents is beyond the scope of the assigned work for the Nevada Regional Haze SIP 

review). 

 

For example, the PCAEC permit does not appear to address emissions that might occur 

from start-up, shutdown, and/or malfunction flaring at the gasifier unit. Typically, coal 

gasification system output needs to be routed to a flare during these operating events. If untreated 

gas were be routed to the flare under these circumstances, overall SO2 emissions could increase 

substantially. 

 

However, more significantly, the emissions data used by IDEQ in the permit appear to be 

internally inconsistent with respect to the sulfur emissions. Using the IDEQ Statement of Basis

(Page 12), the gasifier capacity is up to 5,000 tons per day (tpd) of input coal/pet coke blend at a 

maximum sulfur content of 6%. This would equate to sulfur inputs to the gasifier system of 300 

tons per day (tpd), or 109,500 tons per year (based on 365 days per year). Since two pounds of 

SO2 are created for each pound of sulfur, the potential uncontrolled SO2 emissions associated 

with the gasifier would then be 219,000 tpy. Yet, the allowable SO2 emissions in the PCAEC

permit only total 23 tpy. In order to achieve the allowable SO2 emissions, the level of sulfur 

control for the gasifier process needs to be about 99.99%. This level of sulfur control seems very 

high for the process equipment listed in the permit (sour water scrubber and Claus sulfur 

recovery unit). Also, because IDEQ has determined that: 1) the sulfur removal equipment is 

integral to the process and should not be regulated as pollution control equipment, and 2) the 

sulfur standards contained in the certain New Source Performance Standards (NSPS) are not 

applicable to the unit, there are minimal enforceable standards in the permit to require that the 

plant equipment actually achieves these high sulfur control levels. 

 

Overall, the ability of PCAEC to actually achieve the low SO2 emissions allowed by the 

permit is suspect. However, whether SO2 emissions at PCAEC could potentially increase to 

levels which would cause visibility impairment at Jarbidge cannot be determined at present. 

 

3.2 COMPARISON TO NEVADA REGIONAL HAZE SIP 

 

This section summarizes the 2018 regional emissions described above in relation to the 

projections contained in Nevada’s draft regional haze SIP. In developing these data, emissions 

from the following projects were included in this analysis based on the developer’s current intent 

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to proceed with project construction and development and/or the fact that final air quality permits 

have been issued by the regulatory agency: 

 

• Toquop Energy 

• TS Power Plant 

• Power County Advanced Energy Center 

 

In the case of the Ely Energy Center and White Pine Power Project, the project 

developers have recently announced that these projects will not proceed in the immediate future. 

However, no action has been taken (as of early May 2009) to formally withdraw the air permit 

applications for these projects or terminate the draft PSD permits issued for these facilities. As 

long as the permit applications are still active at NDEP, these projects need to be part of 

Nevada’s regional haze SIP planning efforts. Due to this regulatory uncertainty, the results in this 

section are listed both with and without Ely and White Pine emissions. 

 

For Sevier Power, the project appears to be proceeding forward pending resolution of the 

air quality permit appeal currently before the Utah Supreme Court. However, Sevier Power 

appears to be too far removed from Jarbidge to be realistically considered as a potential 

contributing emission source. Sevier Power emissions may impact Class I areas within Utah, but 

visibility impacts within Utah falls outside the scope of Nevada’s Regional Haze SIP. 

 

For IPP Unit 3, the PSD permit for this project has been extended until October 15, 

2009. However, as the IPP Unit 3 emissions are part of the WRAP 2018 emission projections, 

they appear to have been considered by NDEP in their regional haze SIP. Therefore, Nevada’ 

regional haze SIP should acknowledge that IPP’s emissions have been included in order to 

prevent any confusion over the issue. 

 

Table 3-2 summarizes the future projects considered in Nevada’s SIP and compares the 

projected 2018 emissions to allowable permit levels. In Table 3-2, the natural gas fired EGUs

listed in the April 2009 draft SIP have not been considered. 

 

Table 3-2 

 

Comparison of Permitted SO2 & NOx Emissions to Nevada Regional Haze SIP 

(Based on Future Coal EGUs within Nevada or that may affect Jarbidge) 

 

Project SO2 Emissions (tpy) NOx Emissions (tpy) 

Permit NV 

SIP 

Permit NV SIP 

Toquop Energy 1,352 0 1,614 0 

TS Power Plant 845 670 596 499 

Power County

Advanced Energy 

Center 

23 0 109 0 

D-111 
Ely Energy Center 4,628 0 4,853 0 

White Pine Power 

Project 

6,071 4,356 4,812 3,909 

IPP Unit 3 3,183 3,183 3,183 3,183 

Unnamed Coal

EGU 

0 1,452 0 1,340 

Totals 15,402 9,661 15,167 8,931 

Totals (without 

Ely & White Pine)

5,403 5,305 5,502 5,022 

 

If the Ely and White Pine Projects are included, the data show that the SIP has 

significantly underestimated future SO2 and NOx emissions associated with future coal-based

EGU development in Nevada. The Nevada SIP has underestimated these emissions by roughly 

5,700 tons SO2 and 6,200 tons NOx. 

 

If Ely and White Pine are excluded, the Nevada SIP still underestimates future EGU 

emissions, although the error is smaller (about 100 tpy for SO2 and about 500 tpy for NOx). 

However, any modeling projections reported in the SIP could still be significantly affected by 

these differences. As noted in Table 3-2, the Toquop Energy Project may more or less be 

represented (from an emissions basis) by the “unnamed coal EGU” project in the April 2009 

draft Nevada regional haze SIP. However, the location of the “unnamed coal EGU” does not 

match the Toquop plant. As such, this plant does not have similar Class I visibility impacts to 

Toquop. Due to its location, Toquop would be expected to have its greatest impact at Class I 

areas in southwestern Utah, namely Zion and Bryce Canyon and also at Grand Canyon. Based on 

the WRAP 2018 emissions information [Reference 15], the unnamed Nevada coal-fired EGU 

was modeled at a site close to the proposed White Pine Project. However, even if the magnitude

of the Toquop emissions is accurately reproduced in the 2018 inventory, errors have likely been

introduced in the modeling of future 2018 emissions at Zion and Bryce Canyon (and perhaps 

even other Class I areas). 

 

 

4.0 BART ANALYSES 

 

The Nevada Division of Environmental Protection (NDEP) has identified five EGUs

within Nevada that are “BART-eligible.” Table 4-1 summarizes these facilities. 

 

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Table 4-1 

 

Nevada BART-Eligible Sources

 

Owner Facility Unit Size Location Operational 

Date 

Unit 1 55 MW 1963 

Unit 2 83 MW 1965 

NV Energy Tracy 

Unit 3 113 MW 

Mustang, NV 

1974 

NV Energy Fort Unit 1 113 MW 1968 

Churchill Unit 2 113 MW 

Yerington, NV 

1971 

Unit 1 100 MW 1965 

Unit 2 100 MW 1968 

NV Energy Reid 

Gardner 

Unit 3 100 MW 

Moapa, NV 

1976 

NV Energy Sunrise Unit 1 Not Specified Las Vegas, NV 1964 

Southern Unit1 790 MW 1969 

Cal Edison 

Mohave 

Unit 2 790 MW 

Laughlin, NV 

1969 

Of the above facilities, only Reid Gardner is presently coal-fired. Tracy, Fort Churchill, 

and Sunrise are all natural gas-fired. The Mohave Station was formerly a coal-fired EGU, but

ceased operations at the end of 2005. If Mohave reopens, it would be as a natural gas-fired

facility. 

 

The Valmy Station is not a “BART-Eligible” EGU as its date of operation falls outside of 

the BART time window. 

 

All of the BART-eligible sources in Nevada are more than 300 km from the Jarbidge 

Wilderness, which is Nevada’s only Class I PSD area. Thus, the BART controls for Nevada

sources are intended to provide visibility improvements at Class I areas outside of Nevada. 

 

4.1 SUMMARY OF PROPOSED BART AT NEVADA SOURCES 

Tables 4-2 and 4-3 summarize the emission reductions expected to be generated for SO2

and NOx emissions respectively by implementation of the proposed Nevada BART decisions. In

these tables, the “baseline” emission estimates were developed by NDEP from acid rain 

monitoring data for each unit (generally over the period 2002 through 2007). The “baseline” 

emissions are reported by NDEP to represent the average emissions over the peak 2-year period

at each unit for which monitoring data were available. The draft SIP goes on to state that these 

estimates are generally lower than the WRAP “baseline” emissions, which were estimated based 

on the peak-24 hour emissions over the 2001-2003 period. 

 

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Table 4-2 

 

Proposed Nevada BART-Emission Reductions: SO2 Emissions 

 

Facility Unit Size Baseline 

Emissions 

(tpy) 

BART 

Emissions 

(tpy) 

Emissions 

Reduction 

(tpy) 

Unit 1 55 MW 1 34 -33 

Unit 2 83 MW 2 73 -71 

Tracy 

Unit 3 113 MW 82 146 -64 

Fort Unit 1 113 MW 8 147 -139 

Churchill Unit 2 113 MW 11 147 -136 

Unit 1 100 MW 621 1,144 -523 

Unit 2 100 MW 398 1,251 -853 

Reid Gardner 

Unit 3 100 MW 422 1,233 -811 

Mohave Unit1 790 MW 21,507 45 21,462 

Unit 2 790 MW 21,083 45 21,038 

Totals 44,135 4,265 39,870 

Net Change w/o Mohave -2,630 

 

 

Table 4-3 

 

Proposed Nevada BART Emission Reductions: NOx Emissions

 

Facility Unit Size Baseline 

Emissions 

(tpy) 

BART 

Emissions 

(tpy) 

Emissions 

Reduction 

(tpy) 

Unit 1 55 MW 221 130 91 

Unit 2 83 MW 321 156 165 

Tracy 

Unit 3 113 MW 795 498 297 

Fort Unit 1 113 MW 1,209 524 685 

Churchill Unit 2 113 MW 862 403 459 

Unit 1 100 MW 2,267 959 1,308 

Unit 2 100 MW 2,445 1,002 1,443 

Reid 

Gardner 

Unit 3 100 MW 2,268 1,399 869 

Mohave Unit1 790 MW 10,761 2,347 8,414 

Unit 2 790 MW 10,068 2,347 7,721 

Totals 31,217 9,765 21,452 

Net change w/o Mohave 5,317 

D-114 
 

The net change in emissions attributable to the proposed Nevada BART controls is 

dominated by the situation at Mohave. Since Mohave ceased operations in 2005, the Mohave

emissions reductions reported in Tables 4-2 and 4-3 have already occurred. In order to assess the 

expected change in emissions compared to the current situation, one needs to look at the “net 

change without Mohave” results, also shown in Tables 4-2 and 4-3. When Mohave is excluded 

from the evaluation, it is seen that the emission reductions are much less substantial and in the 

case of SO2 emissions, Nevada’s proposed BART emission controls actually lead to increases in 

emissions compared to the baseline condition. 

 

4.2 REVIEW OF REID GARDNER BART ANALYSIS

In this study, special attention was paid to the BART analysis prepared by NDEP for the 

Reid Gardner Station. Reid Gardner is the only “BART-eligible” Nevada EGU that remains a 

coal-fired facility in the post-BART operating scenario. Reid Gardner is also generally upwind of 

Class I areas in Utah and Arizona, such as Zion National Park, Bryce Canyon National Park, and 

Grand Canyon National Park and would be expected to impact these Class I areas. 

 

The Reid Gardner Station was originally constructed in 1965 (Unit 1). Unit 2 was added 

in 1968, Unit 3 in 1976, and Unit 4 in 1983. Units 1-3 are all sized at 100 MW each, while Unit 4

is sized at 265 MW. Unit 4 was not subject to BART review as its construction/operational date

(1983) falls outside the BART time window. EGUs must have been in existence prior to August

7, 1977, but not prior to August 7, 1962 in order to be “BART-eligible.” 

Based on information available from NDEP [Reference 16], the Reid Gardner BART review 

followed the five-step process outlined in the Environmental Protection Agency (EPA) BART 

guidelines [Reference 17]. The BART decision for Reid Gardner is summarized and reviewed 

below. 

 

4.2.1 SO2 BART at Reid Gardner

 

 Current SO2 control at Reid Gardner Units 1, 2, and 3 consists of a soda ash scrubber. For

BART, NDEP evaluated additional emission controls to replace and/or upgrade the current SO2 

emission controls, specifically: 

 

• Dry flue gas desulfurization (FGD) 

• Dry sorbent injection 

• Furnace sorbent injection 

• New wet FGD system (replace current wet FGD system) 

• Improve and/or upgrade existing wet FGD system 

 

In the federal BART guidelines, EPA recommended a “presumptive BART” level of 0.10 

to 0.15 lb/MMBtu or 95% control for SO2 emissions [Reference 17]. However, the “presumptive 

BART” applies only to EGUs sized 250 MW and larger, so technically the “presumptive BART” 

recommendation would not apply to any of the Reid Gardner units due to their size (100 MW vs. 

the “presumptive BART” threshold of 250 MW). NDEP has proposed in the draft regional haze 

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SIP that the current wet FGD system (wet soda ash scrubber) represents BART for Units 1, 2, 

and 3. However, the BART SO2 emissions limit in the draft SIP was set at 0.25 lb/MMBtu. 

Nevada’s proposed BART SO2 emissions limit at Reid Gardner is approximately twice the 

“presumptive BART” level recommended by EPA for SO2 emissions at coal-fired EGUs. 

 

NDEP’s BART report for Reid Gardner suggests that the proposed SO2 emissions limit 

of 0.25 lb/MMBtu was selected based on the 98th percentile emissions value from the valid 

continuous emissions monitoring data. In other words, the Reid Gardner historical emissions are 

at or below 0.25 lb/MMBtu about 98 percent of the time. In this manner, NDEP has proposed a

BART limit such that Reid Gardner would comply nearly all of the time based on historical 

emissions monitoring data. At the proposed emission limits in the regional haze SIP, Nevada’s 

proposed BART would not lead to Reid Gardner employing the “best available retrofit 

technology” for SO2 as required by the Clean Air Act. 

 

In fact, by establishing the BART SO2 limit in this manner, the result is that the April 

2009 draft Regional Haze SIP would allow for a substantial increase in SO2 emissions from each 

Reid Gardner EGU. As proposed, the draft Nevada visibility SIP would allow each Reid Gardner 

unit to emit continuously at their peak emissions rate based on historical data. Using NDEP’s

data presented in the SIP, SO2 emissions from all three units combined could increase by almost 

2,200 tpy, which represents an increase of 2.5 times over the “baseline.” This would exceed the

projected “new” emissions associated with the Toquop Power Plant. 

 

Also, based on WRAP’s emission projections [Reference 18], Reid Gardner already 

achieves SO2 emissions in the range of 0.03 to 0.04 lb/MMBtu. WRAP’s 2018 emission 

inventory projections also appear to utilize SO2 emission values in this range at Reid Gardner. 

Since Reid Gardner has already demonstrated the ability to achieve average SO2 emissions in the 

range of 0.03 to 0.04 lb/MMBtu, this emissions range establishes a more appropriate SO2 BART

limit for Reid Gardner. 

 

Fortunately, there is a relatively easy fix which still retains what appears to be Nevada’s

intent in establishing the proposed Reid Gardner SO2 BART limit. NDEP could instead set a 

“two-tiered” SO2 emissions limit under BART that would allow for peak short-term SO2

emissions consistent with the historical data, yet also set a lower limit averaged over a longer 

time period that would more closely align with the historical SO2 emission levels and require 

Reid Gardner to maintain the high-level of performance already demonstrated at its pollution 

control systems. For example, an SO2 limit set at 0.04 lb/MMBtu (30-day rolling average), 

would yield an annual emissions total roughly equivalent to the WRAP emissions estimate, yet 

would still allow occasional short-term periods for higher SO2 emissions. This approach would 

be a more prudent way under BART to set limits that provide for variability in short-term 

emissions, yet require that Reid Gardner maintain emissions control at or near the current levels

so as not to degrade further visibility at downwind Class I areas. 

 

In the end, allowing a substantial increase in SO2 emissions above the baseline level goes 

against the regulatory intent of the BART program. BART is intended to provide for emission 

reductions and should not be used as a mechanism to permit substantial increases in emissions at

a facility. There is no valid reason why SO2 control at Reid Gardner under BART should not at 

D-116 
the very least match the performance levels historically achieved at this facility. When viewed in 

that context, a long-term (30-day rolling average) SO2 BART limit should be set for Reid 

Gardner at or below 0.04 lb/MMBtu. 

 

4.2.2 NOx BART at Reid Gardner 

Current nitrogen oxides (NOx) emission controls at Reid Gardner Units 1-3 consist of

low- NOx burners with over-fire air (OFA). For potential application as BART, Nevada 

evaluated the following NOx emission control options: 

 

• Low- NOx burners (LNB) with overfire air (current configuration) 

• LNB with Selective Non-Catalytic Reduction (SNCR) 

• Rotating Opposed Fire Air (ROFA) with Rotomix 

• LNB with Selective Catalytic Reduction (SCR) 

• ROFA with Selective Catalytic Reduction (SCR) 

 

In the EPA guidelines, the “presumptive BART” NOx emissions level for a coal-fired 

boiler depends on the boiler configuration and fuel. Reid Gardner Units 1-3 are wall-fired boilers

using mostly bituminous coal. Under “presumptive BART”, the recommended NOx limit is 0.39 

lb/MMBtu [Reference 17]. Again, Reid Gardner Units 1-3 technically do not fall under 

“presumptive BART’ because the unit size (100 MW) is below the 250 MW threshold used to 

trigger “presumptive BART.” 

 

NDEP’s BART evaluation for Reid Gardner has derived a BART emissions limit of 0.20 

lb/MMBtu for Units 1 and 2 and 0.28 lb/MMBtu for Unit 3. The need for a higher BART NOx

limit at Unit 3 is not discussed in NDEP’s summary BART report. NDEP should provide clear 

evidence as to why Unit 3 is unique and cannot achieve the same NOx BART limit as Units 1

and 2. Without this information, the need for a higher NOx BART limit at Unit 3 cannot be 

confirmed by ARS or any other member of the public. The proposed BART emissions limit is 

based on installation of ROFA with Rotomix as the preferred technology. 

 

 Lower NOx emissions could be achieved using one of the SCR technology alternatives. If 

SCR were employed along with ROFA with Rotomix, the NOx emissions could decrease to a 

range of 0.083 to 0.098 lb/MMBtu using NDEP data (the exact emissions level depends on the

Unit). This would represent an additional 60-65% reduction in NOx from Reid Gardner Units 1-

3. Based on the NDEP evaluation, cost was the primary factor in not selecting one of the SCR 

options as BART. Cost is an allowable consideration under EPA’s BART guidelines. 

 

When SCR is added to ROFA with Rotomix, the capital costs increase from about $8

million to roughly $38.5 million for each unit (over $90 million for SCR at all three units). The 

emissions control cost-effectiveness with SCR increases by about a factor of two or three, from 

around $1,000 per ton to an average of about $2,800 per ton at Units 1 and 2 and from about 

$1,600 per ton to about $3,000 per ton at Unit 3. Although NDEP has rejected these costs as too 

expensive, it should be noted that NOx BART determinations in North Dakota determined that 

costs in the $3,000 to $4,000 per ton range were acceptable [Reference 19]. On an incremental 

D-117 
basis compared to ROFA with Rotomix, the SCR costs for Reid Gardner are reported to be

around $7,000 per ton at Units 1 and 2 and $4,500 per ton at Unit 3. The above cost numbers 

were developed by NV Energy and used by NDEP to evaluate the BART costs. 

 

Because cost was the primary parameter used by NDEP to exclude the SCR technologies 

as BART for Reid Gardner, it is important that the cost information used to support this decision 

is accurate. Based on the SIP, NDEP has chosen to use the SCR cost information provided by 

NV Energy, but there is no evidence that NDEP critically reviewed the company’s SCR cost 

information. Since regulated companies know that cost information is part of the BART review 

process, these companies have a vested interest in trying to present maximum or “worst-case” 

costs for a particular control technology. An independent review of NV Energy’s cost 

information is essential if NDEP is to rely on cost data to exclude SCR as BART. 

 

In the Oregon regional haze SIP, the Oregon Department of Environmental Quality 

(ODEQ) did conduct an independent evaluation of the company-provided costs for SCR at the 

Boardman Power Plant [Reference 20]. The Oregon DEQ concluded that capital costs for the 

SCR alternative at Boardman were overestimated by the company by 27%. 

 

An independent evaluation of the Nevada regional haze SIP conducted by the National 

Park Service also found that the reported SCR costs for Reid Gardner were likely overstated 

[Reference 21]. NPS estimated costs were about 33% lower than those developed by NV Energy. 

NPS concluded that a lower cost would result in cost-effectiveness values that suggest that SCR 

is viable as BART from an economic standpoint. Coupled with the Boardman information 

presented above, this shows the need for a critical evaluation of the SCR cost information 

submitted by NV Energy. 

 

The cost information should also be coupled with the NOx emission levels assumed for

SCR. In the April 2009 draft Nevada regional haze SIP, the resulting SCR NOx emissions are 

higher than what would normally be assigned to this technology. At newer coal-fired units for 

which Nevada has issued draft permits (i.e., Toquop Energy Project), NOx control using SCR 

achieves emissions as low as 0.06 lb/MMBtu [Reference 4]. While it is recognized that control 

technologies when applied in a retrofit situation may not be as effective, the proposed BART 

limits at Reid Gardner are more than 60% higher than when the same pollution technology is 

applied at new emission units. 

 

In the Oregon regional haze SIP, SCR controls have been proposed for the Boardman 

Power Plant (a coal-fired EGU) as “beyond BART” emission controls (See Section 4.4). At

Boardman, the SCR control efficiency is about 70%, reducing NOx emissions to 0.07 lb/MMBtu 

from a “pre-SCR” level of 0.23 lb/MMBtu [Reference 20]. This “pre-SCR” NOx emission rate is 

higher than the “pre-SCR” rate at Reid Gardner for Units 1 and 2, yet the draft Nevada SIP is

based on higher “post-SCR” NOx emissions. The April 2009 draft Nevada SIP only presumes

that SCR control achieves a control efficiency in the range of 60-65% at Reid Gardner, compared 

to 70% elsewhere. If 70% control for SCR were used, the resulting NOx emission rate at Reid 

Gardner Units 1 and 2 would be less than 0.06 lb/MMBtu and would be 0.083 lb/MMBtu at Unit 

3. In fact, the BART analysis for Reid Gardner submitted by NV Energy also used a “post-SCR”

emission rate of 0.07 lb/MMBtu [Reference 22]. 

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Also, in New Mexico, SCR is being considered for implementation as BART for the San 

Juan Power Plant at a NOx emissions level of 0.07 lb/MMBtu [Reference 19]. The reported SCR

cost factor at San Juan is $6,500 per ton NOx removed. Presumably, the higher cost of NOx

control at San Juan is justified by the significant visibility improvement that would occur from

implementation of this technology (estimated at up to 1.3 dV). The SCR costs reported for Reid 

Gardner and rejected by NDEP as too expensive are less than 50% of the costs being considered 

by New Mexico for implementation of SCR at San Juan. 

 

In summary, Nevada’s regional haze SIP needs to use a more realistic NOx control 

efficiency for SCR or explain why the same NOx emissions control achieved elsewhere cannot 

be achieved using SCR at Reid Gardner. If a lower NOx emission level were achievable, the 

economic cost effectiveness of SCR would also improve. Also, because NDEP did not critically 

review the company-submitted SCR cost information and other indications are that costs 

submitted by regulated companies are sometimes inflated, the conclusions of the Nevada SIP 

regarding the cost-effectiveness of SCR at Reid Gardner are deemed to be unreliable. Finally, if

a more realistic NOx emissions level were used to represent SCR at Reid Gardner, the NOx

reductions would be higher and the cost-effectiveness of SCR would improve. 

 

4.3 VISIBILITY IMPROVEMENTS FROM BART IMPLEMENTATION 

The April 2009 draft regional haze SIP includes information on the expected

improvement in visibility conditions resulting from the proposed BART technologies and 

emission rates. Information related to the modeled BART improvements is provided for Mohave 

and Reid Gardner, as these emission sources impact the Class I areas of greatest interest with

respect to the issues in this report. 

 

Details on the specifics of how the BART-improvement modeling was prepared by 

NDEP are not contained within the draft SIP documentation. 

4.3.1 Mohave Generation Station 

Table 4-4 summarizes the results from the Mohave Generating Station BARTimprovement modeling. BART for Mohave was the elimination of coal-fired electric generation 

and operation of natural gas. Mohave’s modeling results are presented for the plant as a whole

rather than for individual units. Although part of the “baseline” SIP emissions, Mohave is not 

currently operating. As such, any visibility benefit associated with emission reductions at 

Mohave has already been achieved. 

 

Table 4-4 shows that the BART controls at Mohave should have a strong positive benefit 

at improving visibility at nearby Class I areas. Despite a strong positive benefit, even after 

implementation of BART controls, the Mohave plant remains above the “cause and contribute” 

visibility thresholds at Grand Canyon and Joshua Tree (98th percentile extinction at or above 0.5 

dV). These results suggest that additional emission reductions are likely needed at Mohave in 

order to reach the national visibility goal. 

 

D-119 
 

Table 4-4 

 

Summary of BART-Improvement Modeling Results 

Mohave Generating Station

 

Class I Area Baseline Condition Post-BART Condition 

 

Dist. 

(km) 

 98

th

 % dV Days > 0.5 dV 98

th

 % dV Days > 0.5 dV 

Grand Canyon 110 2.91 194 0.53 8 

Joshua Tree 137 3.96 90 0.76 14 

Zion 262 1.45 80 0.20 0 

Sycamore Canyon 223 1.38 29 0.12 0 

Agua Tibia 286 1.11 19 0.10 0 

Cucamonga 287 1.05 20 0.11 0 

San Gorgonio 225 1.50 27 0.14 1 

San Jacinto 234 1.46 29 0.15 1 

Mazatal 279 0.98 25 0.04 0 

Pine Mountain 265 0.98 23 0.04 0 

Dome Land 268 1.34 26 0.10 0 

 

4.3.2 Reid Gardner 

 

Table 4-5 summarizes the Reid Gardner BART-improvement modeling results. The 

proposed BART at Reid Gardner provides for NOx control through installation of ROFA with 

Rotomix on each unit. Also, even though the proposed BART used the in-place SO2 emissions 

control technology at Reid Gardner, the proposed SIP emission rate actually allows for SO2

emission increases compared to the baseline condition. The Reid Gardner modeling results are 

presented in the draft SIP for individual units. 

 

Although Nevada has proposed NOx BART emission rates for Reid Gardner, it is unclear 

to what extent these controls are actually reflected in the WRAP 2108 emissions inventory used 

to drive the model calculations summarized above. Based on the most recent WRAP emissions

update [Reference 18], the planned emission changes due to BART at Reid Gardner do not 

appear to be reflected in the WRAP 2018 modeled inventory. This makes the results of the Reid 

Gardner post-BART modeling suspect. The draft SIP should clearly identify the baseline and 

post-BART emissions used to generate the Reid Gardner modeling results. 

 

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Table 4-5 

 

Summary of BART-Improvement Modeling Results 

Reid Gardner Generating Station

 

Class I Area Dist. 

(km) 

Unit Baseline Condition Post-BART Condition 

98

th

 % 

dV 

Days > 0.5 dV 98

th

 % 

dV 

Days > 0.5 

dV 

1 0.85 19 0.83 19 

2 0.86 21 0.73 15 

Grand Canyon 86 

3 0.79 17 0.73 18 

1 0.32 3 0.33 4 

2 0.32 3 0.32 3 

Joshua Tree 292 

3 0.33 3 0.34 4 

1 0.22 3 0.22 2 

2 0.22 3 0.19 2 

Zion 148 

3 0.22 3 0.20 2 

1 0.13 0 0.12 0 

2 0.13 0 0.12 0 

Bryce Canyon 227 

3 0.13 0 0.13 0 

1 0.06 0 0.06 0 

2 0.06 0 0.06 0 

Sycamore 

Canyon 

289 

3 0.07 0 0.07 0 

 

At Reid Gardner, if the modeling results are to be believed, the implementation of BART 

controls is shown to have only minimal effect at reducing visibility impacts. In fact, in a few 

cases, the proposed BART emission controls at Reid Gardner emissions is actually shown to 

degrade visibility marginally (i.e., see Unit 3 at Grand Canyon and Joshua Tree). The lack of

change in the Reid Gardner modeling results appears to reinforce the above suspicion that the 

post-BART emissions are not properly reflected in the 2018 model emissions inventory. If the 

modeled inventory does not accurately reflect the post-BART emissions at Reid Gardner, the 

modeling results reported in the SIP are in error and Nevada has failed to provide one of the 

administrative requirements of its regional haze SIP (documentation of the changes in visibility 

attributable to the proposed BART emission controls). 

 

Also of interest is that the “post-BART” impact of Reid Gardner would still be at or 

above the “cause or contribute” threshold under the federal visibility rules at Grand Canyon 

(98th percentile extinction at or above 0.5 dV). Assuming the modeling results are accurate 

(which may not be the case based on the above analysis), the Reid Gardner model results would

clearly demonstrate the need for a more stringent BART determination. Nevada should select

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BART technologies and associated emission limits that significantly reduce the impact of Reid 

Gardner’s emissions on visibility degradation at the Grand Canyon and other Class I areas and 

properly document the actual effect of these changes on visibility. The modeling results 

summarized in Nevada’s draft regional haze SIP suggest that the proposed BART emission 

limits at Reid Gardner fail to provide any significant visibility improvement at Class I areas

outside Nevada. 

 

On a unit-by-unit basis, the 98th percentile extinction from Reid Gardner is less than 0.5 

dV at Zion and Bryce Canyon. As such, the individual units do not “cause or contribute” to

visibility impairment at either Zion of Bryce Canyon, even under the baseline condition. 

However, the modeling results as presented in the draft SIP do not allow for a determination of 

the cumulative impact from Reid Gardner Units 1, 2, and 3. 

 

One final note of interest with respect to the modeling results is that the reported

visibility impacts from Reid Gardner at Joshua Tree (292 km away) are significantly greater than 

impacts to other Class I areas that are closer to the facility (with the exception of Grand Canyon). 

The information provided in the draft SIP did not discuss this finding and why it might have

occurred. 

 

4.4 OPTIONS FOR “BEYOND-BART” CONTROLS 

Regional haze SIPs in other states have investigated and sometimes recommended 

additional emission controls that are “beyond BART” which are justified as part of the goal to 

achieve “reasonable further progress” toward the national visibility goal. Two such examples are

summarized in this section. 

 

In Oregon, the Boardman Power Plant BART analysis concluded that low- NOx burners 

with modified overfire air satisfied the current BART requirements and proposed an allowable 

NOx emissions level of 0.23 lb/MMBtu. Although SCR was not recommended for immediate 

implementation under BART, Oregon has proposed to require installation of SCR at Boardman 

no later than July 1, 2017 [Reference 20]. Oregon has proposed additional NOx emission controls 

that are “beyond BART” at Boardman in order to maintain the “reasonable further progress” 

goals of Oregon’s visibility program. The post-SCR NOx emissions level at Boardman will be

0.07 lb/MMBtu. 

 

The State of Kansas has also elected to impose “beyond BART’ emission controls as part 

of its proposed regional haze SIP [Reference 23]. In Kansas, there are no existing federal Class I 

areas, so Kansas has adopted its program in order to assist neighboring states achieve their 

“reasonable further progress” goals. Kansas also implemented its program even though the light 

extinction from Kansas sources was no greater than 5% of the total extinction on worst-case days 

at any of the neighboring Class I areas. As described previously, Nevada sources are projected in 

2018 to contribute up to 9% of the nitrate extinction at Class I areas in neighboring states. 

 

In Kansas, the “beyond BART” review focused on sources that were not “BARTeligible.” The evaluation reviewed the costs of controls and also the potential visibility benefits

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of implementing these controls. Of approximately 25 Kansas emission units not regulated under 

BART, additional emission controls were proposed for 10 emission units at six facilities where

the cost was deemed to be reasonable (at or below $15,000 dollars per ton per deciview of 

improvement). 

 

The “beyond BART” approach could be applied in Nevada to secure additional emission 

reductions at Nevada emission sources, which would in turn aid neighboring states achieve their

“reasonable further progress” goals. Candidates for “beyond BART” would include the 

implementation of SCR at Reid Gardner Units 1-3 and investigation of improved emission 

controls at Reid Gardner Unit 4. NDEP needs to ensure that emission controls at its sources are 

sufficient to ensure that Nevada sources contribute their fair share to improving visibility 

conditions at Class I areas in neighboring states. In the draft SIP, Nevada has relied upon 

emission reductions already achieved at Mohave without developing appropriate emission 

control strategies that would provide meaningful visibility improvement from any other sources. 

 

 

5.0 CUMULATIVE VISIBILITY IMPACTS AT SOUTHWESTERN PARKS 

One of the items requested by WRA and NPCA was a review of the potential cumulative

visibility impacts attributable to multiple emission sources that occurs at National Parks in the 

southwestern United States, in particular Zion National Park. 

 

The cumulative effect of emission sources at Zion and other southwestern Class I areas

(Grand Canyon, Sycamore Canyon, and Bryce Canyon) is covered in only summary fashion 

within the April 2009 draft regional haze SIP. Since these Class I areas are located outside of 

Nevada, the NDEP does not have primary responsibility for developing the visibility plan for 

these areas. However, Nevada sources do contribute in part to the visibility impairment at each

of these areas and Nevada is responsible for addressing in the SIP how their sources impact the 

overall visibility planning efforts at these Class I areas. Future development of coal-fired EGUs 

in Nevada, especially the proposed Toquop Power Project (See Section 3.1.1 of this report), may 

also contribute to visibility impairment at Class I areas outside of Nevada. 

 

Data from the Nevada regional haze SIP on cumulative effects at Class I areas outside of 

Nevada are summarized in Table 5-1. These data show the current baseline extinction, the target 

2018 extinction based on the Uniform Rate of Progress (URP) necessary to achieve the national 

visibility goal by 2064, and the projected extinction using modeling projections based on the 

2018 emissions inventory from WRAP. 

 

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Table 5-1 

 

Cumulative Impacts on Regional Haze and Utah and Arizona Class I Areas

 

Class I Area Baseline Extinction 2018 URP 

Target 

Projected 2108 

Extinction 

dV dV dV 

Grand Canyon (AZ) 11.66 10.58 11.10 

Sycamore Canyon 

(AZ) 

15.25 13.25 15.08 

Zion (UT) 13.24 11.78 12.76 

Bryce Canyon (UT) 11.65 10.52 11.22 

For each of the Class I areas of interest, the projections of visibility impairment based on 

the 2018 WRAP emissions inventory fail to achieve the URP target goals, which means that the 

“glide path” for visibility improvement will not be achieved at each of these areas without 

additional emission reductions. 

 

NDEP claims that the reduction in SO2 and NOx emissions outlined in the draft SIP from 

sources within Nevada (in percent) is greater than the fraction of the extinction contributed by 

Nevada sources at each of these areas. However, this claim in largely an artifact of the large

emission reduction which has already occurred at Mohave associated with discontinuing use of 

coal at this facility. NDEP does not appear to have aggressively sought additional emissions 

reductions at other emission sources under its jurisdiction. 

 

In addition, the above claim is based on an assumption that all emission reductions have 

an equal effect on visibility at the Class I areas of interest. In fact, sources affect visibility 

differently based on their proximity to any particular Class I area. For visibility to improve at an 

individual Class I area, emission reductions may be required at specific sources rather than for 

the state as a whole. For example, with respect to Zion and Bryce Canyon National Parks, an 

equivalent emission reductions at Reid Gardner would be expected to have a larger benefit

compared to Mohave due to the closer proximity of Reid Gardner to the areas of interest. 

 

While the emission reductions at Mohave are important, the data presented in Nevada’s 

draft regional haze SIP also show that emission reductions at Mohave are insufficient by

themselves to meet the 2018 visibility target goals at Class I areas outside of Nevada. Additional 

emission reductions will be needed at other sources to achieve meaningful improvements to 

visibility at areas such as Zion and Grand Canyon. For example, if each Nevada source were

expected to individually contribute to “Nevada’s emission reduction share,” the emissions

reductions and improvement in visibility attributable to the proposed BART at Reid Gardner 

falls short of the goals provided in Nevada’s regional haze SIP. 

 

 

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