$/dv) but higher because they would be applied to larger sources. We therefore recommend 

against use of capital cost. 

We agree that cost per ton and incremental cost per ton are appropriate factors, and note that 

NDEP determined that an average of $3,050/ton was an acceptable cost for Low-NOx Burners 

(LNB) and Flue Gas Recirculation (FGR) at Tracy Generating Station (TGS) Unit #1, and 

that $4,972 per ton was an acceptable incremental cost for LNB+FGR at TGS Unit #2. 

However, we continue to advise against over-reliance upon incremental cost. First, it is 

generally understood that the cost/ton of pollution control is an exponential function with an 

increasing slope as higher control efficiencies are approached. Thus, the incremental cost of 

moving from lower control to higher control will increase as higher control efficiencies are 

sought. One way to deal with this problem is to look not at the absolute values of the incremental 

cost, but to the relative ratios of the incremental costs. 

The incremental cost evaluation problem is apparent at Fort Churchill Generating Station 

(FCGS) where the incremental cost ratio of the LNB+FGR strategy chosen by NDEP is 2.7 times 

the next-lowest-$/ton strategy (LNB). However, NDEP rejected the LNB+SCR strategy, even 

though its relative incremental cost ratio was only 2.0. 

At RGGS, NDEP rejected any strategy with a relative incremental cost ratio greater than 1.1. 

Although NDEP did not explain how it considered the importance of actually relating costs to 

visibility improvement for this visibility improvement program, we also note that NDEP found 

that a cost of $9.8 million/dv was acceptable for addition of LNB plus Selective Non-Catalytic 

Reduction (SNCR) at Tracy #3. 

Applying this $9.8 million/dv “benchmark” to the Nevada BART sources and using the NDEP 

data in its Table #1 produces the following conclusions for BART: 

• At Tracy #1, BART is LNB+FGR as proposed by NDEP. 

• At Tracy #2, BART is LNB+FGR as proposed by NDEP. 

• At Tracy #3, BART is LNB+SNCR as proposed by NDEP. 

• At Ft. Churchill #1, BART is LNB+FGR as proposed by NDEP. 

• At Ft. Churchill #2, BART is LNB+FGR as proposed by NDEP. 

• At Reid Gardner #1, BART is LNB +SCR. 

• At Reid Gardner #2, BART is LNB +SCR. 

• At Reid Gardner #3, BART is LNB +SCR. 

If we use NDEP’s determinations that an average of $3,050/ton was an acceptable cost for 

LNB+FGR at TGS Unit #1, and that a cost of $9.8 million/dv was acceptable for addition of 

LNB+SNCR at TGS #3 as our criteria, we arrive at the same results. 

On average cost/ton and cost/dv bases, LNB+SCR is clearly BART at all three RGGS units. 

Despite NDEP’s assertion that it did not rely solely upon incremental costs, it appears that the

only way NDEP can justify rejecting LNB+SCR at RGGS is on that basis. NDEP should clearly 

state the basis for its BART determinations, and how it included effects on visibility. 

D-61 
NDEP follow-up response: 

USEPA’s BART guidance6

 lists five factors states must consider in identifying BART, but does 

not identify any individual factor for greater consideration as the FLMs have with the fifth factor, 

the degree of visibility improvement which may reasonably be anticipated from the use of 

BART. The BART guidance7

 provides direction on selecting the “best” alternative including 

identification of the average and incremental cost, consideration of the modeled visibility 

impacts, justification for adopting the technology selected as the “best” level of control, and an 

explanation of the CAA factors leading to the BART option selected. The guidance8

recommends two types of cost-effectiveness calculations – average cost effectiveness and 

incremental cost effectiveness. 

NDEP has followed the guidance provided in Appendix Y in our identification of BART controls 

for Nevada sources, in spite of the contentions to the contrary by the FLM community. 

However, NDEP did not apply a cap on capital cost, cost per ton, or incremental cost as implied 

by NPS, but evaluated the cost effectiveness and capital cost for each facility independently (i.e., 

on a case-by-case basis in accordance with Appendix Y guidance). Acceptable costs for BART 

controls at one source did not determine acceptable BART control costs at other sources (i.e., 

Nevada has not established “benchmarks” that define acceptable BART cost metrics. 

Acceptable costs were determined on a source-by-source basis.). Although NPS recommends 

against using capital cost in the BART determination process, note that capital cost, coupled with 

control efficiency determine the control cost (i.e., cost per ton). 

As NDEP has stated in previous responses to FLM comments (see Appendix C, NPS-NWS 

Comment 17 and NDEP Response), Nevada does not agree with the optional cost effectiveness 

measure of dollars per deciview ($/dv) of visibility improvement. Nevada notes that $/dv is an 

optional measure of cost effectiveness as listed in the BART guidance9

 and that EPA provides no 

guidance on the use of this metric in the selection of BART controls. 

Nevada has evaluated the inherent uncertainty in use of $/dv as a cost effectiveness metric using

Oregon DEQ’s cost evaluation for the Boardman facility. The annual cost of installing and 

operating NLNB/MOFA with SDFGD as BART controls for the Boardman facility is 

approximately $40M. NDEP has used these costs and DEQ’s modeled post-BART visibility 

improvement at all 14 Class I areas within 300 km of the facility to calculate the cost 

effectiveness in millions of $/dv. The results were used to evaluate how the number and 

distribution of Class I areas affect $/dv as a cost effectiveness metric. 

NDEP calculated the cost effectiveness in $/dv for five different groupings of Class I areas, as 

follows: 

• All Class I areas within 300 km of the Boardman facility (Mt. Adams, Goat Rocks, Mt. 

Hood, Eagle Cap, Strawberry Mountain, Mt. Rainer, Mt. Jefferson, Alpine Lakes, Three 

Sisters, Mt. Washington, Hells Canyon, Glacier Peak, Diamond Peak, North Cascades), 

 

6 40 CFR Part 51 Appendix Y (I) (C) (2) 7 40 CFR Part 51 Appendix Y (IV) (E) (2) 8 40 CFR Part 51 Appendix Y (IV) (D) (4) (b) 9 40 CFR Part 51 Appendix Y (IV) ( E) (1) (4) 

D-62 
• The 5 Class I areas closest to the facility (Mt. Adams, Goat Rocks, Mt. Hood, Eagle Cap, 

Strawberry Mountain), 

• The 5 Class I areas in the middle distance (Mt Rainer, Mt. Jefferson, Alpine Lakes, Three 

Sisters, Mt. Washington), 

• The 2 closest and 3 most distant Class I areas (Mt. Adams, Goat Rocks, Glacier Peak, 

Diamond Peak, North Cascades), and 

• The 5 most distant Class I areas (Mt. Washington, Hells Canyon, Glacier Peak, Diamond 

Peak, North Cascades). 

The results are presented in Table 1. 

TABLE 1. EVALUATION OF $/DV AS COST EFFECTIVENESS METRIC

Baseline

Visibility

(dv)

Phase I

Visibility

(dv)

Phase I

Improvement 

(dv)

Cost

Effectiveness 

(millions $/dv)

Mt. Adams, Goat Rocks, Mt. Hood,

Eagle Cap, Strawberry Mountain, Mt. 

Rainer, Mt. Jefferson, Alpine Lakes,

Three Sisters, Mt. Washington, Hells

Canyon, Glacier Peak, Diamond Peak,

North Cascades

31.09 13.84 17.25 2.32

Mt. Adams, Goat Rocks, Mt. Hood,

Eagle Cap, Strawberry Mountain 13.65 6.41 7.24 5.52

Mt. Rainer, Mt. Jefferson, Alpine

Lakes, Three Sisters, Mt. Washington

12.00 5.26 6.74 5.93

Mt. Adams, Goat Rocks, Glacier Peak,

Diamond Peak, North Cascades

8.59 3.66 4.93 8.11

Mt. Washington, Hells Canyon, Glacier

Peak, Diamond Peak, North Cascades

7.77 3.18 4.59 8.71

Most Distant 5 CIAs

All CIAs within 300 km

Closest 5 CIAs

5 CIAs in Middle Distance

2 Closest and 3 Most Distant CIAs

Table 1 shows a considerable range of costs depending on the number and location of the 

impacted Class I areas. These costs range from $2.32 million to $8.71 million/dv of visibility 

improvement depending on the number and location of the affected Class I areas. Table 1 shows 

that the more distant the Class I areas the higher the cost of BART controls in $/dv, while the 

closer the Class I areas the lower the cost in $/dv. Note that the traditional measures of cost 

effectiveness; total annualized costs in dollars; cost effectiveness in dollars per ton; and 

incremental cost effectiveness in dollars per ton, remain constant. Only the number and location 

of the Class I areas were changed for this evaluation. The results clearly demonstrate how the 

location and number of Class I areas can influence the use of $/dv as a cost effectiveness metric. 

D-63 
NDEP has utilized capital costs, cost per ton of pollutant removed, and incremental cost 

differences in our cost evaluation of BART controls. NDEP does not accept the use of $/dv as 

an effective measure of cost effectiveness for the reasons stated above. 

As Nevada stated in our response to the initial FLM comment (Appendix C, Comment 17), 

NDEP evaluated the control cost, incremental cost, and capital cost in combination and used a 

“least-cost envelope” to identify dominant alternatives on a facility by facility basis. NDEP then 

evaluated these factors with the estimated emissions reductions to determine BART for each 

source individually, as each source has unique characteristics of cost and control efficiency. 

Nevada used the limited visibility modeling performed by NV Energy in conjunction with the 

emissions reductions to estimate the visibility improvement based on the premise of a linear 

relationship between modeled visibility and emission rates (NPS agrees with this premise in a 

subsequent comment). 

The NPS has ignored the remainder of NDEP’s response, which identifies how capital cost, cost 

per ton and incremental cost increase, as well as the limited emissions reductions achieved for 

the next most stringent control option at Reid Gardner. Capital cost increases by more than four 

times, cost per ton by more than twice, and incremental cost by more than seven times, while 

emissions are reduced by 542 tpy or 41 percent for unit 1. The clear breaks in these factors 

support NDEP’s BART determination. NDEP’s other BART determinations have similar 

characteristics when considered on a source-by-source basis. 

NPS goes on to advise against over reliance upon incremental cost, stating that “the incremental 

cost of moving from lower control to higher control will increase as higher control efficiencies 

are sought.” Examination of Table 1, “BART NOx Cost Factors and Visibility Improvement for 

NV Energy Facilities,” included in Appendix C of this SIP, demonstrates that several more 

stringent control options have incremental costs lower than the next less stringent control option 

(e.g., for Tracy unit 1 see LNB w/ SNCR, LNB w/ FGR, and LNB w/ SCR; for Tracy unit 2 see 

LNB w/ SNCR; for Tracy unit 3 see LNB w/ SNCR and LNB w/ SCR; for Fort Churchill units 1 

and 2 see LNB w/ SCR; for Reid Gardner units 1 and 2 see ROFA w/ Rotamix; and for Reid 

Gardner unit 3 see LNB w/ OFA and SNCR). Therefore, the NPS premise for not using 

incremental cost is flawed. 

NPS further proposes use of relative ratios of incremental costs and then points out the problem

with this approach. However, examination of the problematic data cited by NPS suggests they 

have misinterpreted the data. NPS has apparently presented ratios of average cost effectiveness 

(in $/ton) rather than ratios of incremental cost effectiveness for the options they evaluated, 

based on the data presented in Table 1 of NDEP’s response to FLM comments. Appendix Y 

does not mention the use of relative ratios of incremental costs as a measure of cost 

effectiveness. 

Nevada is pleased that NPS has reached the same conclusions regarding BART control 

technologies as NDEP for the Tracy Generating Station and Fort Churchill Generating Station. 

However, Nevada is confused regarding NPS’ conclusions for BART at Reid Gardner 

Generating Station, as LNB with SCR was not one of the BART control options considered or 

D-64 
presented by NV Energy or NDEP. If NPS means LNB with OFA and SCR is BART for Reid 

Gardner, then NDEP disagrees with the NPS assessment. 

Based on the data in Table 1, referenced above, installation of ROFA with Rotamix at the Reid 

Gardner Generating Station has an estimated capital cost of nearly $8 million per unit, while 

LNB with OFA and SCR has capital costs of more than $35 million per unit, 4.4 times as much. 

Average cost effectiveness for the SCR option is 2.3 times as much for units 1 and 2, and 1.7 

times as much for unit 3. Incremental costs for the SCR option are 7.3 times as much for unit 1, 

6.8 times for unit 2, and 2.4 times as much for unit 3. Emissions reductions increase between the 

two options by 41 percent for unit 1, 39 percent for unit 2, and 104 percent for unit 3. Selection 

of the SCR option would increase the facility’s capital costs by more than $81 million to reduce 

NOx emissions by approximately 2,000 tons per year. Nevada deems NDEP’s identification of 

BART as consistent with the breaks in cost effectiveness and visibility improvement/emissions 

reductions (i.e., cost benefits), as well as the Appendix Y guidance. 

To determine whether changes resulting from these comments regarding cost and control 

efficiencies might significantly change NDEP’s conclusions, Nevada evaluated alternative cost 

and emission scenarios in cost analyses. This is not to say Nevada agrees with the values used in 

the alternative scenarios cost analyses, but we did want to evaluate how reduced costs might 

influence NDEP’s BART determination for Reid Gardner. This exercise will be referred to as the 

alternative cost analyses in the remainder of this document. 

Alterative Cost Analyses

NDEP included an economic analysis summary as Table 1 in each of NDEP’s BART 

determination reviews for our subject-to-BART sources. These reviews are included in 

Nevada’s RH SIP as Appendix B, BART Determination Support Documents10. Table 1 in 

NDEP’s economic analysis for Reid Gardner11, is the basis of the alternative cost analyses. For 

this exercise, Table 1 was modified to incorporate the lower emission limits (in lb/MMBtu) 

presented by NV Energy for the various proposed NOx BART controls regardless of percent 

control efficiency (an approach preferred by NPS as noted in their follow-up comment 15) and is 

presented below as Table 2. Changing these NOx emission limits addresses some of the FLM 

comments directed at the control efficiencies used by NDEP in our original economic analyses. 

In addition, NDEP evaluated lower control costs by reducing NV Energy’s costs by 30 percent to 

address FLM comments suggesting NV Energy’s costs were inflated. So, the alternative cost 

analyses for Reid Gardner, presented in Table 2 below, incorporate higher percentage control 

efficiencies with lower emission rates and lower costs. Figure 1 presents the least cost envelope

analyses for Reid Gardner units 1, 2 and 3 based on NDEP’s alternative cost analyses. Note that 

these analyses are based on baseline values determined by NDEP and that these values are not 

the same baseline values used by NV Energy. 

Examination of Table 2 and Figure 1, below, shows the results of NDEP’s alternative cost 

analyses do not change our determination of BART for the three Reid Gardner units, even with 

 

10 Available at http://ndep.nv.gov/baqp/planmodeling/rhaze.html. 11 Nevada Division of Environmental Protection BART Determination Review of NV Energy’s Reid Gardner 

Generating Station Units 1, 2 and 3

D-65 
the greater emissions reductions and lower costs suggested by the FLMs. LNB with OFA and 

SCR costs per ton of NOx removed for all three units are 2.25 to 2.5 times greater than those for 

ROFA with Rotamix. The LNB with OFA and SCR incremental costs per ton for units 1 and 2 

are 7.5 to 8 times greater than those for ROFA with Rotamix, while the LNB with OFA and SCR 

incremental costs for unit 3 are 2.5 times those for ROFA with Rotamix. The annual reduction 

in NOx emissions for LNB with OFA and SCR from units 1 and 2 is 56 percent (441 tpy for unit 

1 and 472 tpy for unit 2), while the reduction for unit 3 is 65 percent (654 tpy) of the emissions 

for ROFA with Rotamix. These factors, based on NDEP’s alternative cost analyses, coupled 

with a capital cost increase of more than 400 percent for SCR controls, confirm NDEP’s 

selection of ROFA with Rotamix as SO2 BART for Reid Gardner. 

D-66 
TABLE 2. REID GARDNER ALTERNATIVE COST ANALYSES

Reid-Gardner Unit 1

Current Operation

(Uncontrolled) ROFA w/SCR LNB w/OFA

& SCR

ROFA

w/Rotamix

LNB w/OFA

& SNCR LNB w/OFA

Capital Cost $38,484,900 $35,048,000 $7,884,900 $6,945,500 $4,448,000

First Year O&M Cost $1,313,191 $1,029,801 $613,952 $396,248 $80,000

First Year Debt Service $4,081,555 $3,717,051 $836,241 $736,612 $471,737

Total Annual Cost Reduced 30% $3,776,322 $3,322,796 $1,015,135 $793,002 $386,216

Base Heat Input (MMBtu) 9,815,313

Total Heat Input allowed (MMBtu) 10,643,400

Base emissions (tons) 2,267

NOx Removal Rate % 84.8% 84.8% 65.4% 50.2% 35.1%

NOx Removed (Tons) 0 1923 1923 1482 1138 795

NOx Emission Rate (Tons) 2267 344 344 785 1129 1472

NOx Emission Rate (lb/MMBtu) 0.462 0.07 0.07 0.16 0.23 0.30

First Year Cost ($/ton removed) $1,963 $1,728 $685 $697 $486

Incremental Cost ($/ton) $6,251 $5,225 $647 $1,184 $486

Reid-Gardner Unit 2

Current Operation

(Uncontrolled) ROFA w/SCR LNB w/OFA

& SCR

ROFA

w/Rotamix

LNB w/OFA

& SNCR LNB w/OFA

Capital Cost $38,484,900 $35,048,000 $7,884,900 $6,945,500 $4,448,000

First Year O&M Cost $1,388,071 $1,078,551 $661,760 $418,657 $80,000

First Year Debt Service $4,081,555 $3,717,051 $836,241 $736,612 $471,737

Total Annual Cost Reduced 30% $3,828,738 $3,356,921 $1,048,601 $808,688 $386,216

Base Heat Input (MMBtu) 10,501,749

Total Heat Input allowed (MMBtu) 10,643,400

Base emissions (tons) 2,445

NOx Removal Rate % 85.0% 85.0% 65.6% 50.6% 35.6%

NOx Removed (Tons) 0 2078 2078 1605 1238 870

NOx Emission Rate (Tons) 2445 368 368 840 1208 1575

NOx Emission Rate (lb/MMBtu) 0.466 0.07 0.07 0.16 0.23 0.30

First Year Cost ($/ton removed) $1,843 $1,616 $653 $653 $444

Incremental Cost ($/ton) $5,883 $4,885 $653 $1,149 $444

Reid-Gardner Unit 3

Current Operation

(Uncontrolled) ROFA w/SCR LNB w/OFA& SCR

ROFA

w/Rotamix

LNB w/OFA

& SNCR LNB w/OFA

Capital Cost $38,484,900 $35,048,000 $7,884,900 $6,945,500 $4,448,000

First Year O&M Cost $1,320,114 $1,000,893 $543,568 $345,970 $80,000

First Year Debt Service $4,081,555 $3,717,051 $836,241 $736,612 $471,737

Total Annual Cost Reduced 30% $3,781,168 $3,302,561 $965,866 $757,807 $386,216

Base Heat Input (MMBtu) 10,063,851

Total Heat Input allowed (MMBtu) 10,836,120

Base emissions (tons) 2,268

NOx Removal Rate % 84.5% 84.5% 55.6% 49.0% 33.4%

NOx Removed (Tons) 0 1916 1916 1262 1111 759

NOx Emission Rate (Tons) 2268 352 352 1006 1157 1510

NOx Emission Rate (lb/MMBtu) 0.451 0.07 0.07 0.20 0.23 0.30

First Year Cost ($/ton removed) $1,973 $1,724 $765 $682 $509

Incremental Cost ($/ton) $4,304 $3,572 $1,378 $1,055 $509

NOx Control

NOx Control

NOx Control

Note: Shaded Columns Represent BART, emission rates from NV Energy, and NV Energy total annual costs reduced by 30%.

D-67 
FIGURE 1. ALTERNATIVE LEAST COST ENVELOPES FOR 

REID GARDNER UNITS 1, 2 AND 3*

Reid-Gardner Unit 1 Alternative Least Cost Envelope

ROFA w/SCR

LNB w/OFA & SCR

ROFA w/Rotamix

LNB w/OFA LNB w/OFA & SNCR

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

0 500 1000 1500 2000 2500

Tons Removed

Annual Costs ($)

 

Reid-Gardner Unit 2 Alternative Least Cost Envelope

ROFA w/SCR

LNB w/OFA & SCR

ROFA w/Rotamix

LNB w/OFA LNB w/OFA & SNCR

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

0 500 1000 1500 2000 2500

Tons Removed

Annual Costs ($)

Reid-Gardner Unit 3 Alternative Least Cost Envelope

ROFA w/SCR

LNB w/OFA & SCR

ROFA w/Rotamix

LNB w/OFA LNB w/OFA & SNCR

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

0 500 1000 1500 2000 2500

Tons Removed

Annual Costs ($)

*NOTE: Revised using lower NV Energy control efficiencies in lb/MMBtu and NV Energy annual

costs reduced by 30 percent. 

Nevada’s alternative cost analyses led NDEP to the same conclusions regarding the selection of 

ROFA with Rotamix as BART controls for Reid Gardner. Nevada has also discussed the FLM’s 

D-68 
emphasis on visibility criteria in the BART process thereby driving the process by available 

technology; however NDEP deems the BART process a cost-benefit analysis. Finally, Nevada 

has identified a 2018 reasonable progress goal that exceeds the uniform rate of progress, 

indicating significant progress toward the national visibility goal without the BART controls 

and/or limits recommended by the FLMs at Reid Gardner. 

No changes were made to Nevada’s RH SIP as a result of these comments. 

COMMENT 8 (NPS-FWS p.5-6) NPS follow-up: 

NDEP should present evidence to support its assertion that “NDEP has consistently evaluated 

the economic factors as part of our evaluation of proposed BART controls on a unit-by-unit 

basis...” NDEP explains that it used three factors (capital cost, average cost per ton, and 

incremental cost per ton), but does not tell how, or with what criteria, it applied them. As we 

noted in our previous follow-up, it appears that a consistent application of its criteria would 

have led to very different determinations. If NDEP lacked the modeling analyses it needed to 

produce an informed determination, it should have first obtained that information. 

NDEP is correct in noting that the EPA BART Guidelines allow it to “choose not to analyze the 

other Class I areas any further as additional analyses might be unwarranted.” However, we 

believe that it is good public policy to at least consider the consequences of that choice. If the 

other Class I areas were so distant as to be essentially unaffected, NDEP’s choice could be 

justified. However, a simple inspection of the modeling results presented by NV Energy shows 

that, by evaluating impacts only at the closest Class I area, NDEP has ignored from 50% to 90% 

of the cumulative impacts at the Class I areas for which results are presented. Thus, NDEP has 

also ignored 50% to 90% of the benefits that would result from any reductions in emissions at 

thee facilities. 

NDEP points to the “clear breaks” in the NV Energy Table 5-4 results as proof that the morestringent controls are too expensive. As we noted earlier, BART is not necessarily the most-costeffective option. And, as we have shown above, those “clear breaks” can be misleading unless 

placed into the proper perspective. We continue to disagree that this should be a determining 

factor if the more-stringent controls are still reasonably cost-effective. 

We agree with NDEP that, “In general, there is a linear relationship between CALPUFF 

modeled visibility and emission rates. The visibility improvement resulting from BART 

installation is expected to be proportional to the difference in modeled annual emissions and the 

annual NDEP BART emissions.” However, if one inspects the results in NV Energy’s Table 3-2 

for NOx reductions and Table 5-4 for visibility improvement, it can be seen that, if, for example, 

a 95 ton per year reduction due to LNBw/OFA at RGGS #3 produces an improvement of 0.407 

dv at Grand Canyon, then a reduction of 1,136 tons per year after application of 

LNBw/OFA+SCR should produce more than the 0.652 dv improvement presented by NV 

Energy.1

 If NDEP is to use the NV Energy data, it must insure that the data is valid and that it is 

properly presented and interpreted. It is apparent that the NVE data that NDEP is using requires 

further explanation, at the very least. (Footnote 1: Similar inconsistencies can be found 

throughout the Reid Gardner analyses. For example, the NVE model results indicate that a one 

D-69 
ton/yr reduction by LNB will improve visibility 7.5 times as much as a one ton reduction 

resulting form LNB+SCR.)

NDEP follow-up response: 

NDEP has consistently evaluated the proposed BART controls on a unit-by-unit basis by 

identifying the clear breaks in cost-benefit based on cost effectiveness and visibility 

improvement. Nevada utilized capital cost, average cost per ton, and incremental cost per ton as 

economic factors and modeled visibility or emissions reductions as visibility improvement 

factors. NDEP does not agree with the use of the optional cost effectiveness metric of $/dv in 

our determinations as recommended by the FLM community. This position is based on 

Nevada’s analyses presented in NDEP’s follow-up response to NPS’ follow-up response to 

Comment 7. Other states have also expressed reservations regarding the use of $/dv as a 

measure of cost effectiveness. 

As NDEP stated in Nevada’s initial responses to FLM comments, section 5.6 of Nevada’s RH 

SIP discusses the visibility improvement resulting from BART implementation in Nevada. In 

addition, as NDEP noted in Nevada’s initial responses to FLM comments, Chapters 5 of NV 

Energy’s BART determination reports discuss the dispersion modeling results as well as 

presenting tables and figures documenting visibility improvement at all Class I areas within 300 

km of the facilities. All these data were considered in NDEP’s BART determinations. 

However, Nevada did not rigorously utilize $/dv as a cost effectiveness measure as this comment 

seems to suggest we should. NDEP deems cost benefit rather than visibility improvement as the 

determining factor for identifying BART, contrary to NPS philosophy. This is an area where 

NDEP and NPS must agree to disagree. 

NPS has apparently misinterpreted the data cited from the NV Energy reports regarding the 

modeled visibility improvement resulting from each ton of NOx reduction. NDEP has compiled 

and analyzed the cited data, as presented in Table 3. We examined the changes from baseline for 

each control option, as well as the changes between options. Our analysis shows the deciview 

improvement per ton of NOx removed is consistent between the options out to four decimal 

places. NDEP deems these data to be not only valid, but also properly presented and interpreted. 

TABLE 3. VISIBILITY IMPROVEMENT PER TON OF NOX REDUCTION AT REID 

GARDNER

98th

percentile

delta

deciview

reduction 

(dv)

visibility

change

from

baseline

(dv)

visibility

change

between

options

(dv)

annual

emissions

change

from

baseline

(tpy)

annual

emissions

change

between

options

(tpy)

visibility

improvement

per ton 

removed from

baseline 

(dv/ton)

visibility

improvement per

ton removed 

between options

(dv/ton)

Base 0.386

LNB w/ OFA 0.407 0.021 0.021 95 95 0.00022 0.00022

LNB w/ OFA and SNCR 0.485 0.099 0.078 434 339 0.00023 0.00023

ROFA w/ Rotamix 0.514 0.128 0.029 556 122 0.00023 0.00024

ROFA w/ SCR 0.652 0.266 0.138 1136 580 0.00023 0.00024

LNB w/ OFA and SCR 0.652 0.266 0 1136 0 0.00023 na

D-70 
No changes were made to the draft RH SIP as a result of these follow-up comments. 

COMMENT 9 (NPS-FWS p.6): Comments on Reid Gardner BART Determination, Sulfur

Dioxide (SO2) NPS follow-up: 

Reid Gardner is subject to BART, and BART is a federally-enforceable emission limit. NDEP 

should provide the 98th percentile values on which it based its BART limit. And, because NDEP 

believes that operating conditions and/or coal quality will change, it should identify those 

changes and include them in its analysis so that those assumptions can be evaluated by others.2

(Footnote 2: NDEP should also explain why such changes in operations would not trigger new 

source review requirements.)

NDEP follow-up response: 

Please see NDEP’s response to USEPA comment 2, above, where NDEP explained that Nevada 

conducted additional evaluation of NV Energy’s BART Analysis for Reid Gardner Station Unit 1

and the analyses for units 2 and 3, as well as analysis of the emissions data collected under the 

auspices of 40 CFR Part 60. These efforts lead NDEP to establish a revised SO2 BART limit for 

Reid Gardner at 0.15 lb/MMBtu. Text, figures and tables in this SIP as described in Nevada’s 

response to USEPA comment 2, as well as text in NDEP’s BART review for Reid Gardner were 

modified to reflect the change in SO2 BART emission limits for Reid Gardner and its 

ramifications. 

In addition, please see Nevada’s response to NPS follow-up Comment 6 above, which discusses 

the operational challenges presented by the installation of retrofit technology at Reid Gardner 

unit 4. 

Operational conditions related to boiler draft balance and/or coal quality are not permit 

conditions. As such, modification of these operational conditions does not trigger new source 

review requirements. No changes were made to Nevada’s draft RH SIP as a result of this 

comment. 

COMMENT 10 (NPS-FWS p.6) NPS follow-up: 

NDEP should duly resolve this during the BART process. [NOTE: “This” refers to an NPS issue

with the averaging periods for the SO2 BART emission limits at Reid-Gardner.]

NDEP follow-up response: 

NDEP has addressed a similar comment in Nevada’s response to USEPA Comment 2 in section 

2.2.2.2 of this appendix. 

NDEP expects NV Energy will operate the post-BART Reid Gardner Generating Station much 

as it has historically and will achieve actual emission rates consistent with the highly efficient 

recent operational history of the facility, which has achieved the low SO2 emission rates noted by 

the FLMs. It is improbable that the facility will have emissions as high as 0.15 lb/MMBtu for 

extended periods or operate at full capacity year round. 

No changes were made to the draft RH SIP as a result of this comment. 

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COMMENT 12 (NPS-FWS p.7) NPS follow-up: 

Condensible PM is generally understood to be a significant component of PM emissions from 

fossil-fuel-fired EGUs, and the CALPUFF model used by NV Energy to model emissions is 

capable of, and was used for modeling condensible PM emissions. NDEP is incorrect in its 

assertion that “there is no post-combustion technology to directly control condensable 

particulate emissions.” Wet electrostatic precipitators are commonly installed for this purpose, 

and reagents have been recently developed to suppress the formation of SO3 which leads to 

emissions of H2SO4. 

NDEP follow-up response: 

USEPA is currently implementing the new source review (NSR) program for PM2.5. There are a 

number of outstanding issues related to NSR for PM2.5. For instance, there is little or no 

information on PM2.5 emissions from stationary sources, reference test methods have not been 

promulgated, and the reference test method that was developed for condensable PM was flawed. 

Currently there is a lack of necessary tools to estimate emissions of PM2.5 and related precursors. 

Similar issues exist for condensable PM10. Until USEPA has determined how BACT and LAER, 

and other aspects of NSR will be handled for condensables and precursors, NDEP deems it 

unreasonable to consider condensable PM under BART. 

Reid Gardner recently installed pulse jet fabric filter as part of an environmental upgrade project 

for units 1, 2 and 3 under the conditions of a consent decree between USEPA, NDEP and NV 

Energy. Fabric filter is BART for PM10 at Reid Gardner. The potential level of emissions 

reduction for electrostatic precipitators is not as great as the fabric filter and was eliminated from

further consideration as BART for Reid Gardner. 

No changes were made to Nevada’s draft RH SIP as a result of this comment. 

COMMENT 13 (NPS-FWS p.7): Nitrogen Oxides (NOx) NPS follow-up: 

While true, the generalities presented by NDEP do not address the question of why a specific 

boiler (RGGS #3) should be allowed to emit more NOx after installation of similar BART 

controls than similar boilers at RGGS with higher pre-BART emissions and similar BART 

controls. And, we still do not see how the higher emission rates for RGGS Unit 3 are further 

explained in NDEP’s response to the next USDOI comment. 

NDEP follow-up response: 

NDEP research has identified inconsistencies between the NV Energy Reid Gardner BART 

reports and operating permit regarding the dates of commission and when the three BART units 

were placed into operation. Reid Gardner unit 1 was manufactured in 1965, unit 2 in 1968, and 

unit 3 was manufactured in 1976, based on information from the permits. The differences in 

manufacture date may account for some of the variability in controlled NOx emission rates 

exhibited by the three units. 

In addition, based on NV Energy’s experience with installation of the ROFA system on Reid 

Gardner unit 4, described in Nevada’s response to follow-up comment 6 above, NDEP is not 

certain that the manufacturer’s guarantees are necessarily achievable. The tuning of ROFA on 

unit 4 has taken much longer than originally anticipated, and the guaranteed value has been 

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difficult to obtain. The engineering team has had to continuously revise their approach to 

installation of the ROFA, including changing coal burner components and air ducting for the 

boiler. NV Energy’s operational experience with ROFA was a factor in setting the higher BART 

emission limit for unit 3. 

No changes were made to Nevada’s draft RH SIP as a result of this comment. 

COMMENT 14 (NPS-FWS p.7) NPS follow-up: 

We disagree that “...assumptions presented by NV Energy do not vary significantly from 

engineering norms...” Differences between 6% and 15% control, and between 24% and 63% 

control are significant. Good combustion controls are the foundation for any NOx reduction 

strategy. If that foundation is not strong, then the add-on controls will be hampered in their 

effectiveness and their costs will increase. 

NDEP follow-up response: 

This NPS follow-up comment refers to control efficiencies for combustion controls, specifically 

LNB with OFA at Reid Gardner. The BART control technology identified by NDEP for Reid 

Gardner, ROFA with Rotamix, combines combustion control with reagent injection and has 

control efficiencies twice those of LNB with OFA and correspondingly lower emission rates. 

This comment appears to be moot in light of the BART control technology selected by NDEP. 

No changes were made to Nevada’s draft RH SIP as a result of this comment. 

COMMENT 15 (NPS-FWS p.7) NPS follow-up: 

NDEP has based its analyses of the costs of combustion controls plus SCR on the assumptions 

that this combination of controls can achieve annual emission rates no lower than 0.083 – 0.098 

lb/mmBtu. It appears that NDEP arrived at these emission rates counter to the approach used by 

NVE in which NVE estimated the emission rate that was achievable and then calculated the 

corresponding reduction efficiencies. Although we believe that NVE has underestimated the 

ability of SCR to achieve lower emissions, we agree with its approach and it the approach taken 

by the overwhelming majority of BART sources across the nation. 

Instead, NDEP used the “artificially” calculated control efficiencies that resulted from NVE’s 

emission estimates, and then applied those artificial values to its escalated baseline emission and 

heat input scenarios. As a result, not only are the NDEP emission rates higher than the 0.07 

lb/mmBtu rate presented by NVE, they are higher than the emission rates demonstrated in 

practice (as illustrated by the updated CAM data we are submitting) and higher than the vendor 

guarantees.3

 NVE and NDEP should re-evaluate SCR on the basis that it can achieve an annual 

emission rate of 0.05 lb/mmBtu. (Footnote 3: For example, Minnesota Power has stated in its 

Taconite Harbor BART analysis that “The use of an SCR is expected to achieve a NOx emission 

rate of 0.05 lb/mmBtu based on recent emission guarantees offered by SCR system suppliers.”)

NDEP follow-up response: 

NDEP has evaluated lower emission rates (i.e., higher control efficiency percentages) and 

reduced costs in alternative cost analyses of BART controls for Reid Gardner, as described in 

NDEP’s response to NPS follow-up comment to Comment 7, above. The alternative cost 

analyses led NDEP to the same determination of BART for Reid Gardner, ROFA with Rotamix. 

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COMMENT 16 (NPS-FWS p.7-8) NPS follow-up:

The Boardman costs represent an unusual situation in which a $40 million capital cost would be 

included for modification of the boiler to reduce outlet temperatures to a range that would 

accommodate SCR.4

 Unless NVE can show that it would experience unusual costs, then we 

believe that the cost values cited (and again included) are fair representations of typical SCR 

costs. (Footnote 4: NDEP can learn more about this at 

http://www.deq.state.or.us/aq/haze/pge.htm)

NDEP should also recognize that the “average and median total capital investment of $320 and 

$301/kW for SCR and $346 to $334/kW for combustion control plus SCR” is based almost 

entirely on data presented by sources that have rejected SCR, and thus have a large financial 

interest in convincing their regulatory agencies to agree. When we compare those industry 

estimates to the “real-world” data compiled for the Electric Power Research Institute and the 

Boardman reports, we suspect that the industry cost data to which NDEP referred is inflated. We 

hope that NDEP would exercise caution in evaluating data from sources with clear conflicts of

interest. In addition, we suggest that NDEP consider the information presented by Minnesota 

Power to the Minnesota Public Utilities Commission in which it estimated that addition of SCR 

would cost $205/kW at is Clay Boswell unit #3. 

NDEP follow-up response:

NDEP has determined BART on a case-by-case basis in consideration of the factors listed in Part 

51 Appendix Y guidance. In addition, NDEP conducted alternative cost analyses to evaluate 

whether inflated costs and/or lower achievable emission rates would change our BART 

determinations for Reid Gardner. The alternative cost analyses, described above under Comment 

7, led NDEP to conclude our initial BART determination was sound. 

Because Nevada determined BART on a case-by-case basis, the cost information presented by 

NPS is of passing interest. However, NDEP does note NPS has a tendency to present those cost 

data in support of their positions while disavowing those data that don’t support their positions, 

although the referenced cost data compilation was conducted by NPS. The NPS points NDEP 

directly to cost data for one facility to support SCR as BART, while, as they state above, many 

other facilities have rejected SCR as BART. NDEP asserts that it does exercise caution in 

evaluating data from outside sources. 

 

No changes were made to Nevada’s RH SIP as a result of this comment. 

NPS follow-up:

It appears that NDEP has somehow concluded that our “NPS version of corrected OAQPS Cost 

Manual...” spreadsheets represent some radical revision of the EPA OAQPS Control Cost 

manual approach recommended by the BART Guidelines. Instead, the “correction” to which the 

file’s title refers is in the original version of that workbook that used the example problem in the 

Cost Manual as a check. In the process of developing the workbook, it was discovered that some 

errors had occurred in the Cost Manual’s presentation of its example, and those errors were 

corrected (with the cooperation of OAQPS). We suggest that NDEP become more familiar with 

the methods employed by the Cost Manual and the workbook based upon it. If NDEP then finds 

that there really is an error or deviation in the workbook, we would be pleased to work with 

NDEP (and OAQPS) to correct it. 

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We are unaware that the OAQPS Control Cost manual must be “properly vetted through a 

public process” in order for NDEP to accept the science inherent in its methods. And, while we 

have made our workbook available to all as an aid toward evaluating the costs of SCR, if NDEP 

wishes to use a different approach, it is welcome to do so, provided that it presents adequate 

rationales, explanations, and justification.

NDEP follow-up response:

NDEP appreciates NPS explaining the changes it made to the Cost Manual and the workbook 

based upon it. This is the first explanation we have seen of how the NPS version of the corrected 

OAQPS Cost Manual was modified in conjunction with OAQPS. Can NPS point NDEP to 

OAQPS’ announcement and documentation of these changes for NDEP review? NDEP is 

skeptical of utilizing undocumented resources from outside sources without further evaluation. 

NPS concurs with NDEP’s BART technology determinations, as stated in its follow-up to 

Comment 7, for all Nevada’s subject-to-BART sources except Reid Gardner. So these 

comments are moot, except for Reid Gardner. NDEP has evaluated how lower costs might affect 

our BART determination for Reid Gardner with alternative cost analyses, described in NDEP’s 

response to NPS’ follow-up comment to Comment 7. The alternative cost analyses confirm

NDEP’s determination of BART technology for Reid Gardner. No changes were made to 

Nevada’s RH SIP as a result of this comment. 

NPS follow-up: 

The data available to NPS lead us to believe that costs for a typical SCR installation range from 

$50 – 250/kW. NVE has provided no documentation or justification for its much higher costs. If 

NVE cannot provide the documentation and justification to support its estimates, then it should 

use the Cost Manual approach to generate estimates that are consistent and transparent. We are 

simply doing exactly that. 

NDEP follow-up response:

The Part 51 Appendix Y guidance states that BART is a case-by-case determination. The use of 

$/kW is an optional measure of cost effectiveness not identified in Appendix Y. In addition, see 

NDEP’s follow-up response to the NPS follow-up to Comment 7 above, where NDEP references 

its alternative cost analyses. No changes were made to Nevada’s RH SIP as a result of this 

comment. 

NPS follow-up: 

We believe that BART decisions should be made in the context of other decisions made by a 

particular state, and in the context of decisions made by other states, in much the same manner 

as Best Available Control Technology determinations. This promotes the concept of the “level 

playing field.” We also encourage states to consider the unique circumstances particular to a 

given source and its impacts upon Class I areas in its vicinity. At the very least, a state should be 

internally consistent in its determinations, or provide information describing any apparent 

inconsistencies.

NDEP follow-up response:

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As NDEP stated in our response to the NPS follow-up comment above, NDEP views BART as a

case-by-case determination, consistent with Appendix Y guidance. NDEP has consistently 

determined BART through identification of clear breaks in the cost effectiveness measures 

identified in Appendix Y guidance and visibility improvement/emissions reductions at the 

affected Class I areas. Nevada notes that NPS concurs with NDEP’s BART technology 

determinations for all but one of Nevada’s subject-to-BART facilities. 

No changes were made to Nevada’s RH SIP as a result of this comment. 

COMMENT 17 (NPS-FWS p.8) NPS follow-up: 

Although NDEP did not address our comments, it is correct in noting that the EPA BART 

Guidelines allow it to “choose not to analyze the other Class I areas any further as additional 

analyses might be unwarranted.” However, we believe that it is good public policy to at least 

consider the consequences of that choice. If the other Class I areas were so distant as to be 

essentially unaffected, NDEP’s choice could be justified. However, a simple inspection of the 

modeling results presented by NV Energy in Table 5-3 of its submittals shows that, by only 

evaluating impacts at the Grand Canyon, NDEP has ignored half of the cumulative impacts at 

the five Class I areas for which results are presented. Thus, NDEP has also ignored half of the 

benefits that would result from any reductions in emissions at RGGS. 

NDEP follow-up response:

This comment duplicates a portion of the NPS follow-up comment to Comment 8; see NDEP’s 

follow-up response to Comment 8. 

The original FLM Comment 17 suggests cost benchmarks based on the $/dv cost effectiveness 

metric. As NDEP has noted above, BART is a case-by-case determination and is not determined 

by cost benchmarks at other facilities. NDEP has chosen not to use the optional $/dv cost 

effectiveness metric for the reasons discussed in our response to NPS follow-up comment to 

Comment 7. 

In addition, NDEP disagrees with the NPS statement that Nevada did not consider visibility 

improvement in its BART determinations. NDEP discusses visibility improvement resulting 

from the implementation of BART at Nevada sources in section 5.6, “Visibility Improvement

Due to BART Implementation” of Nevada’s RH SIP. In the cases where limited modeling was 

performed, NDEP utilized emissions reductions in lieu of visibility improvement, since modeled 

visibility improvement is proportional to emission rates. Finally, regional visibility modeling 

demonstrates Nevada’s 2018 reasonable progress goal for Jarbidge is below the uniform rate of 

progress and that Nevada’s emission reductions are consistent with our share of visibility 

impairment at Class I areas in adjacent states. 

No changes were made to Nevada’s RH SIP as a result of this comment. 

NPS follow-up: 

We disagree and suggest that NDEP reconsider the cost information provided by NVE by taking 

a fresh look at the data we have provided,5

 as well as its background. While it is true that it is the 

role of the states (or EPA when the state fails) to establish BART, that does not preclude DOI 

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