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Proposed Rule: Approval and Promulgation of Air Quality Implementation Plans; State of 

Nevada; Regional Haze State and Federal Implementation Plans

Technical Support Document (TSD)

Docket Number: EPA-R09-OAR-2011-0130

Prepared and Reviewed by:

Scott Bohning, Eugene Chen, Steve Frey, Ann Lyons, Colleen McKaughan, Thomas Webb

April 2, 2012

1. Relationship of this TSD to our Proposal

In a letter dated November 18, 2009, Nevada Division of Environmental Protection 

(NDEP) submitted the “Nevada Regional Haze State Implementation Plan” (Nevada RH SIP) to 

U.S. Environmental Protection Agency (EPA), Region 9. This SIP addressed regional haze 

program requirements for the first planning period through July 31, 2018. On June 22, 2011 (76 

FR 36450), we proposed approval of the Nevada RH SIP. On December 13, 2011 we finalized 

approval of all elements of the Nevada RH SIP with the exception of the NOx BART 

determination for the Reid Gardner Generating Station.1

 As a result of certain comments 

received during the public comment period for the proposed approval, we took no action on this 

element of the RH SIP in order to perform additional analysis and supplement the administrative 

record. The results of our analysis support NDEP ’s selection of control technology (ROFA with 

Rotamix). As a result, we are proposing to approve certain remaining elements of the RH SIP as 

listed in Table 1 below. In addition, there are certain SIP elements that we are not approving. 

For those elements, we are also proposing a Federal Implementation Plan (FIP).

Table 1. Approved Elements of RH SIP

Unit Plan Element SIP Approved? FIP

1 Emission Limit (lb/MMBtu)

1 0.20 Y

Averaging Period 12-month rolling N 30-day rolling

2

Emission Limit (lb/MMBtu) 1 0.20 Y

Averaging Period 12-month rolling N 30-day rolling

3 Emission Limit (lb/MMBtu) 1 0.28 N 0.20

Averaging Period 12-month rolling N 30-day rolling 1 Although the emission limits are listed separately for each unit, compliance with the emission limits is 

determined based on a unit-wide average (heat input weighted)

This document provides technical information to support the proposed approval, and 

discuss the basis for our proposed disapproval and FIP. It provides additional information 

regarding the technical aspects of our proposed disapproval which we regard as too detailed for 

inclusion in the Federal Register notice. Specifically, this document contains our analysis of the 

two factors of the BART analysis that we consider most crucial to this approval, costs of 

 1 77 FR 17334
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compliance and degree of visibility improvement. It also contains our rationale for disapproving 

the elements listed in Table 1, and the corresponding FIP element. The remaining sections of this 

TSD are numbered as follows:

Section 2 – Background on Regional Haze and BART Requirements

Section 3 – Reid Gardner NOx BART Determination

Section 4 – Costs of Compliance

Section 5 – Degree of Visibility Improvement

Section 6 – FIP elements

Please note that in this document, we often use language such as “we find” or other 

similar phrases that on the surface suggest a final determination has been made. However, the 

information presented in this TSD should be considered part of our proposal and subject to 

change based on comments and other additional information we may receive during the public 

comment period for this proposal.

2. Background on Regional Haze and BART Requirements

Our June 22, 2011 proposed approval of the Nevada RH SIP contains a general 

discussion of regional haze and EPA’s Regional Haze Rule (RHR), including BART 

requirements (76 FR at 36451-36455). The RHR provides the following six factors that a BART 

determination must take into account (40 CFR 51.308(e)(1)(ii)(A)):

• the available technology to control emissions and the technical feasibility of each technology;

• the cost of compliance for the technically feasible control technologies;

• the energy and non-air quality impacts of the control technologies;

• any existing air pollution control technologies at the source;

• the remaining useful life of the source; and

• the degree of visibility improvement which may reasonably be anticipated to result from the 

various control technologies.

All but the first of these factors are also expressly required to be taken into account under 

Section 169A(g)(2) of the Clean Air Act (CAA), 42 U.S.C. § 7491(g)(2). Although we list six

factors, the first factor is not always explicitly stated and the remaining factors are frequently 

referred to as the “five-factor analysis” for the RHR BART determination.

3. Reid Gardner NOx BART Determination

A. NDEP’s Analysis 

RGGS consists of four coal-fired boilers, three of which are BART-eligible units with 

generating capacity of 100 megawatts (MW) each. A fourth unit (250 MW) is not BARTeligible. The units are wall-fired pulverized coal boilers that consume primarily bituminous coal, 

but currently also burn some Wyoming sub-bituminous coal. Nevada Energy, the owner of 

RGGS, performed a BART analysis for the three BART-eligible RGGS units and submitted the 

results of its analysis to NDEP and recommended new LoNOx burners and 0.39 lb/MMbtu as 
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BART .2 NDEP reviewed but disagreed with Nevada Energy’s analysis and NDEP determined 

that, for each unit, rotating overfire air (ROFA) with Rotamix (a technology that combines a 

conventional selective non-catalytic reduction [SNCR] system with a proprietary injection 

system for air and reagent) was BART for NOx.3 NDEP eliminated the next most effective 

control technologies, which consist of selective catalytic reduction (SCR)-based options, on the 

grounds that “the $/ton of NOx removed increased significantly . . . without correspondingly 

significant improvements in visibility.”4

B. EPA’s Analysis

Based upon comments received during the public comment period for our June 22, 2011 

proposal, we conducted additional review of the five-factor analysis performed by NDEP. 

During the course of this review, we identified several aspects of NDEP’s analysis that we 

considered either inconsistent with our regulations under 51.308(e) or unsupported by the record. 

As a result, we performed our own analysis in order to revise these inconsistencies and 

supplement the record with additional visibility modeling. Costs of compliance and degree of 

visibility improvement were the two statutory factors most crucial to our analysis, and are 

discussed at length in the remainder of this document. 

In our analysis of costs of compliance, we find that control options more stringent than 

ROFA with Rotamix, such as SCR with LNB and OFA, are cost effective on an average and 

incremental basis. Our analysis of visibility improvement indicates small incremental visibility 

improvement between ROFA with Rotamix and more stringent control options, such as SCR 

control options. As a result, we agree that NDEP reasonably determined that the costs of further 

control are not warranted based on the low incremental visibility improvement. 

4. Costs of Compliance

The BART guidelines state that “[i]n order to improve consistency, cost estimates should 

be based on the OAQPS Control Cost Manual [now called the EPA Air Pollution Control Cost 

Manual], where possible.” The EPA Air Pollution Control Cost Manual (Sixth Edition, January 

2002)5 provides guidance and methodologies for estimating the cost and economic feasibility of 

a project, with a nominal accuracy of ± 30%. The costs that are incorporated into estimates of 

capital and annual costs by the Control Cost Manual (CCM) are outlined in Section 1, Chapter 

26, which states that total capital costs may include equipment costs, freight, sales tax, and 

installation costs. For existing facilities, retrofit costs should also be considered, and may include 

auxiliary equipment, handling and erection, piping, insulation, painting, site preparation, off-site 

facilities, engineering, and lost production revenue. Finally, annual costs are estimated from 

costs of raw materials, maintenance labor and materials, utilities, waste treatment and disposal, 

replacement materials, overhead, property taxes, insurance, and administrative charges.

A. NDEP’s Analysis

 2 Nevada Energy BART Analysis Reports, completed October 3, 2008. Available in Docket Item No. EPA-R09-

OAR-2011-0130-0007. 3 Revised NDEP Reid Gardner BART Determination Review, available as Docket Item No. EPA-R09-OAR-2011-

0130-0005. 4 Id. at page 6. 5 http://epa.gov/ttn/catc/products.html#cccinfo

6 Section 1: Introduction, Chapter 2: Cost Estimation: Concepts and Methodology, EPA/452/B-02-001, (01/ 2002)
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In evaluating this factor, NDEP developed cost effectiveness values for each NOx control 

technology on an average and incremental basis. A summary of these values for Reid Gardner 

Units 1 through 3, as included in the RH SIP, are summarized in Table 2 below.

Table 2. NDEP Control Cost Effectiveness Summary

Control Option

Control 

Efficiency1

Emission 

Rate1

Emission 

Reduction1

Annualized 

Costs1

Average Cost 

Effectiveness1

Incremental Cost 

Effectiveness1

(%) (lb/ MMBtu) (ton/yr) ($MM) ($/ton) ($/ton)

Reid Gardner Unit 1

LNB + OFA 21.3% 0.36 483 $0.55 $1,143 $1,143

LNB + OFA +

SNCR

40.9% 0.27 927 $1.13 $1,222 $1,308

ROFA + Rotamix 57.7% 0.2 1308 $1.45 $1,109 $833

SCR + LNB + 

OFA

81.6% 0.085 1850 $4.75 $2,566 $6,085

SCR + ROFA3 81.6% 0.085 1850 $5.39 $2,916 $7,280

Reid Gardner Unit 2

LNB + OFA 23.7% 0.355 580 $0.55 $952 $952

LNB + OFA + 

SNCR

42.7% 0.267 1044 $1.16 $1,106 $1,299

ROFA + Rotamix 59.0% 0.19 1443 $1.50 $1,038 $860

SCR + LNB + 

OFA

82.2% 0.083 2010 $4.80 $2,386 $5,813

SCR + ROFA3 82.2% 0.083 2010 $5.47 $2,721 $7,001

Reid Gardner Unit 3

LNB + OFA 6.5% 0.42 147 $0.55 $3,742 $3,742

LNB + OFA + 

SNCR

29.9% 0.316 678 $1.08 $1,596 $1,000

ROFA + Rotamix 38.0% 0.278 869 $1.38 $1,588 $1,560

SCR + LNB + 

OFA

78.2% 0.098 1774 $4.72 $2,660 $3,688

SCR + ROFA2 78.2% 0.098 1774 $5.40 $3,045 $4,444 1 As summarized in Table 1, NDEP Reid Gardner BART Determination, October 22, 2009. Available as Docket Item No. 

EPA-R09-OAR-2011-0130-0005.

2 Incremental cost effectiveness based on ROFA + Rotamix as previous control technology 

The annualized costs listed in Table 2 are based on total capital installation costs and 

certain annual operating costs provided to NDEP by Nevada Energy on October 22, 2008, and 

were included in the SIP without modification. These cost calculations provided line item 

summaries of capital costs and annual operating costs, but did not provide further supporting 

information such as detailed equipment lists, vendor quotes, or the design basis for line item 

costs. 

In its RH SIP, NDEP indicated that it based its NOx BART determination of ROFA with 

Rotamix primarily on the costs of compliance. NDEP judged the costs of ROFA with Rotamix 
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as affordable based on an average cost effectiveness of approximately $1100-1600/ton. NDEP 

eliminated more stringent control options, such as the SCR-based options, on the grounds that 

“the $/ton of NOx removed increased significantly . . . without correspondingly significant 

improvements in visibility.” Per NDEP estimates, the incremental cost effectiveness of SCR 

with LNB and OFA is approximately $3600-6100/ton. NDEP determined that this additional 

cost per year for SCR technologies did not appear cost effective compared to the additional NOx

reduction for each unit

B. EPA’s Analysis

In reviewing the Nevada RH SIP, and as a result of several public comments we received, 

we identified several aspects of NDEP’s approach to this factor with which we disagree, and for 

which we have performed additional analysis. 

We received several public comments alleging that NDEP/Nevada Energy’s cost calculations 

were unsupported by the record or lacked sufficient detail for critical review. We agree with 

these comments, and on December 22, 2011 sent a letter to NDEP in which we requested 

clarification on several items, among which was information that would provide additional detail 

and justification for control cost estimates.7

 In response, NDEP provided certain documents, 

including a set of cost estimates updated in 2011. These updated cost estimates consist of 

updates to specific line items in order to reflect higher material costs, but did not include any 

supporting information such as detailed equipment lists, vendor quotes, or the design basis for 

line item costs. 8

 

 We also received several public comments alleging that NDEP/Nevada Energy’s cost 

calculations were overestimated and based on methodology inconsistent with EPA’s Control 

Cost Manual. In our analysis, we have excluded those costs that are not included in the CCM 

and adjusted the value of specific variables (e.g., interest rate) to conform to values allowed by 

the CCM. In particular, the NDEP/Nevada Energy cost estimates included “owner’s costs”, 

“surcharge”, and “authorization for funds used during construction (AFUDC).” These cost items 

are not allowed by the CCM, and in certain cases are redundant with “project contingency” costs, 

which are already included. While the CCM does provide flexibility in including some 

contingencies (such as degree of retrofit difficulty), neither Nevada Energy nor NDEP has 

provided documentation to justify the need to include contingency costs beyond standard 

allowances provided by the CCM. AFUDC is specifically set to zero in the CCM for SCR 

installations. In addition, we have also revised the interest rate used in calculating the capital 

recovery factor for annualizing these capital costs. Nevada Energy’s debt service calculations 

used an interest rate of 8.5% over the lifetime of the project. In our analysis, we have used a 7% 

interest rate as provided in CCM example calculations. 

 The public comments we received on the issue of cost calculations also identified other 

aspects of NDEP/Nevada Energy’s cost estimates that were alleged to be unjustified or 

overestimated. Examples include a failure to account for multiple unit discount and 

overestimated reagent costs. Although we agree that the record does not support the positions 

 7 Email dated December 22, 2011from Colleen McKaughan (EPA) to Mike Elges (NDEP). 

8 As provided via email dated February 14, 2012 from Rob Bamford (NDEP) to Eugene Chen (EPA)
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that NDEP has taken on these cost items, at this time we decline to exclude or refine these items 

in our revised cost calculations.

 Exclusion of costs not included in the CCM results in a decrease of 25-33% in the 

average and incremental cost effectiveness of the control technology options. Detailed cost 

calculations, in which we revise the original (as included in the RH SIP) and updated (as 

provided by NDEP February 14, 2012) cost calculations for each NOx control technology, is 

included in Appendix A. Summarized in Table 3 below is a comparison of the updated 

NDEP/Nevada Energy cost calculations (as provided on February 14, 2012) and our revised cost 

calculations for the SCR with LNB and OFA control technology option.

Table 3. Cost Effectiveness Comparison – SCR with LNB and OFA

Unit No. Average Cost 

Effectiveness ($/ton)

Incremental Cost 

Effectiveness ($/ton)

NDEP EPA Revised NDEP EPA Revised

Unit 1 $2,827 $2,110 $6,370 $4,534 

Unit 2 $2,627 $1,967 $6,080 $4,330 

Unit 3 $2,932 $2,183 $3,856 $2,756 

Based on our revised cost estimates for the higher, updated cost estimates provided February 14, 

2012, we consider these average and incremental cost effectiveness values for SCR with LNB 

and OFA to be cost effective. 

5. Degree of Visibility Improvement Which May Reasonably be Anticipated to Result 

from the Use of Such Technology

The BART Guidelines describe 1 deciview (dv)9 as the threshold for an impact that 

“causes” visibility impairment, and 0.5 dv as a threshold for an impact that “contributes” to 

visibility impairment (70 FR 39118, 39120-39121). The “cause and contribute” threshold is 

used for the purposes of determining if a BART-eligible source is exempt from BART 

requirements, or must proceed with a five-factor BART determination. In the context of 

performing a BART determination and evaluating the degree of visibility improvement, the 

BART Guidelines indicate that use of a comparison threshold is also an appropriate way of 

evaluating visibility improvement (70 FR 39129-30), but do not provide a single “bright line” 

threshold. Consistent with EPA’s BART Guidelines (40 CFR Part 51, Appendix Y, Section 

III.A.1), we note that Nevada uses the 0.5 dv threshold when considering if a BART-eligible 

source contributes to visibility impairment.10 Although use of this 0.5 dv threshold is required 

only in the context of determining whether a source is subject to BART, it can also function as a 

useful benchmark for comparing the incremental visibility improvement from the use of the 

control technologies considered as part of the five-factor analysis.

 9 The deciview scale represents a standardized index that expresses changes in visibility, similar in manner to how 

the decibel scale is an index that expresses relative changes in sound levels. For a more full description, please 

refer to 62 FR 41145.

10 Per the Nevada RH SIP, page 5-5. Available in Docket Item EPA-R09-OAR-2011-0130-0003
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A. NDEP’s Analysis

As part of their BART analysis, Nevada Energy performed visibility modeling in 

order to evaluate the visibility improvement attributable to each of the NOx control 

technologies that it considered. Results of the visibility modeling performed by 

Nevada Energy in their submittal to NDEP are summarized in Table 4 below. 

Table 4. Summary of Nevada Energy Estimates of Visibility Benefit11

Control Option

Visibility Improvement 

(from WRAP baseline)12

Visibility Improvement 

(Incremental, from 

Control)

RGGS1 RGGS2 RGGS3 Total Total 

(dv) (dv) (dv)

LNB + OFA 0.440 0.479 0.407 1.33 --

LNB + OFA + SNCR 0.521 0.560 0.485 1.57 0.24

ROFA + Rotamix 0.592 0.630 0.514 1.74 0.17

SCR + LNB + OFA 0.698 0.735 0.652 2.09 0.35

SCR + ROFA13 0.698 0.735 0.652 2.09 0.35

Based upon these results, the installation of SCR with LNB and OFA would result in 

an incremental visibility improvement at Grand Canyon National Park of 0.35 

deciviews (dv). This visibility improvement is based upon the NOx emission rates 

estimated by Nevada Energy in their BART analysis for each control technology 

option, and is relative to visibility impacts based on emissions used by the Western 

Regional Air Partnership (WRAP). In preparing the RH SIP, however, NDEP 

developed its own set of NOx emission estimates for the various control technology 

options. The differences between Nevada Energy’s estimates and the emission 

estimates that form the basis of the Nevada RH SIP are summarized in Table 5 below. 

 11 Visibility improvement listed here are for the Class I area with the highest impact, Grand Canyon National Park. 

They represent the change in the 98th percentile impacts from three modeled years. The “total” is the simple total of 

the impacts from the three individual units, which Nevada Energy modeled separately.. 12 From Table 5-4 of NVE BART Analysis Reports, Reid_Gardner_1_10-03-08.pdf, Reid_Gardner_2_10-03-08.pdf,

Reid_Gardner_3_10-03-08.pdf. Available in Docket Item No. EPA-R09-OAR-2011-0130-0007. The improvements 

here are relative to the “WRAP baseline”, impacts from emission levels used by the Western Regional Air 

Partnership and modeled by Nevada Energy. This is a different “baseline” than used for the cost estimates below. 13 Incremental visibility benefit of SCR + ROFA is based upon ROFA + Rotamix as previous control technology.
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Table 5. Comparison of Nevada Energy and NDEP Control Technology Emission 

Estimates 

Control Option Nevada Energy NDEP

Emission 

Factor1

Control 

Efficiency2

Emission 

Factor3

Control 

Efficiency3

(lb/MMBtu) (%) (lb/MMBtu) (%)

Reid Gardner Unit 1

Baseline (LNB + OFA) 0.38 -- 0.462 --

LNB + OFA (enhanced) 0.30 21.3% 0.360 21.3%

LNB + OFA + SNCR 0.23 40.9% 0.270 40.9%

ROFA + Rotamix 0.16 57.7% 0.200 57.7%

SCR + LNB + OFA 0.07 81.6% 0.085 81.6%

SCR + ROFA 0.07 81.6% 0.085 81.6%

Reid Gardner Unit 2

Baseline (LNB + OFA) 0.39 -- 0.466 --

LNB + OFA (enhanced) 0.30 23.7% 0.355 23.7%

LNB + OFA + SNCR 0.23 42.7% 0.267 42.7%

ROFA + Rotamix 0.16 59.0% 0.190 59.0%

SCR + LNB + OFA 0.07 82.2% 0.083 82.2%

SCR + ROFA 0.07 82.2% 0.083 82.2%

Reid Gardner Unit 3

Baseline (LNB + OFA) 0.32 -- 0.451 --

LNB + OFA (enhanced) 0.30 6.5% 0.420 6.5%

LNB + OFA + SNCR 0.23 29.9% 0.316 29.9%

ROFA + Rotamix 0.20 38.0% 0.278 38.0%

SCR + LNB + OFA 0.07 78.2% 0.098 78.2%

SCR + ROFA 0.07 78.2% 0.098 78.2% 1 From each respective unit's NVE BART Analysis, Table 3-1. Available in Docket 

Item No. EPA-R09-OAR-2011-0130-0007 2 From each respective unit's NVE BART Analysis, Table 3-2. Available in Docket 

Item No. EPA-R09-OAR-2011-0130-0007 3 As summarized in Table 1, NDEP Reid Gardner BART Determination, October 22, 

2009. Available as Docket Item No. EPA-R09-OAR-2011-0130-0005. Baseline 

emission factor is not explicitly calculated by NDEP. The factor here represents the 

listed annual emissions divided by 'Base Heat Input'

As seen in these tables, NDEP’s estimates of controlled emission rates differ from 

Nevada Energy’s estimates. These differences are a result of NDEP’s use of a 

different emission baseline in its calculations than Nevada Energy, which is discussed 

below in our discussion of existing pollution control technology. Since NDEP 

elected to calculate controlled emission rates by retaining the respective percent 

reduction values for each control technology, rather than each control technology’s 

emission rate (lb/MMBtu), the use of a higher baseline emission rate results in higher 
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emission estimates for each control technology option. As a result, NDEP’s 

estimated performance for each control technology is less stringent than Nevada 

Energy’s estimates. NDEP, however, did not perform additional modeling to 

determine the visibility improvement attributable to its emission estimates, and 

continued to rely on the visibility modeling performed by Nevada Energy. 

As noted in the discussion of cost of compliance, part of NDEP’s basis for not 

determining a control technology more stringent that ROFA with Rotamix as NOx 

BART was that the incremental costs of more stringent control options were not 

justified relative to their corresponding increases in visibility benefit. However, 

without updated visibility modeling that indicates the visibility improvement 

attributable to NDEP’s emission estimates, we do not consider NDEP to have 

properly considered the appropriate magnitude of incremental visibility improvement 

in reaching its determination. As discussed in our analysis below, we have performed 

our own visibility modeling in order to determine these visibility impacts. 

B. EPA’s Analysis

Under the BART Guidelines, the degree of visibility improvement from controls is 

one of the five factors to consider in making a BART determination for a facility. Of 

particular interest was the visibility benefit from the installation of Selective Catalytic 

Reduction (SCR), as compared to benefits from other, less expensive control 

technologies. As described in the following sections, we performed our own 

CALPUFF air quality modeling of the Reid Gardner Generating Station (RGGS) to 

assess the effect of NOx controls on visibility at nearby Class I areas as an aid in the 

review of NDEP’s BART determination for RGGS. 

1. Modeling Synopsis

2. Background on CALPUFF and visibility calculations

3. The old and the revised IMPROVE equations

4. Modeling Methodology

5. Stack Parameters and Source Emissions

6. Modeling Results

7. Comparison to other modeling

The modeling was performed using the current regulatory version of the CALPUFF 

modeling system, and generally followed procedures in the modeling protocol 

developed by the Western Regional Air Partnership (“WRAP protocol”), with some 

important changes for improved performance and regulatory requirements. Most of 

the modeled control scenarios used input emission rates from the NDEP SIP 

submittal, though with different chemical speciation for PM10 emissions to better 

reflect their visibility effects. In order to focus on the impacts of alternative controls 

for NOx, most scenarios held SO2 and PM10 emissions rates constant at levels 

determined by NDEP to represent BART. Given that EPA has already approved

NDEP’s SO2 and PM10 BART determinations (77 FR 17334), we consider this 

procedure acceptable for making decisions about NOx controls in the present action. 
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1. Modeling Synopsis

EPA used the current regulatory version of the CALPUFF modeling system, which 

comprises the following source code versions:

• CALMET Version 5.8, Level: 070623 

• CALPUFF Version 5.8, Level: 070623

• POSTUTIL Version 1.56. Level: 070627

• CALPOST Version 5.6394, Level: 070622

• CALPOST Version 6.221, Level 080724 (for visibility method 8)

The projection and coordinate system used was the same as used by the WRAP, and 

is illustrated in Figure 1 below.

• Projection: Lambert Conformal Conic (LCC)

• Projection origin (lat, long): 40°, -97°

• Standard parallels: 33°, 45°

• False easting and northing: 0 m, 0 m

• Projection ellipsoid: “NWS-84”, 6370 km radius sphere

The CALMET modeling domain was identical to the WRAP Arizona domain:

288 x 225 grid cells (X & Y), each 4 km, total size 1152 x 900 km;

southwest corner at LCC coordinates -1944 km, -900 km

The CALPUFF modeling domain was centered on RGGS but within the above:

157 x 156 grid cells (X & Y), each 4 km, total size 628 x 624 km;

southwest corner at meteorological domain cell (20, 70)
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Figure 1. Modeling Domain
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Each Class I area located within 300 km of Reid Gardner was included in our 

modeling, as listed in Table 6 below. Modeling receptors for each Class I areas were 

downloaded from the National Park Service “Class I Receptors web site.”14

Table 6. Class I Areas 

abbr. Name min. distance 

from RGGS, km

number 

of 

receptors

State Agency

brca Bryce Canyon 

National Park 226 213 UT NPS

grca Grand Canyon 

National Park 85 791 AZ NPS

jotr Joshua Tree National 

Monument 292 815 CA NPS

syca Sycamore Canyon 

Wilderness Area 288 316 AZ USFS

zion Zion 

National Park 148 224 UT NPS

CALMET was run using the 2001, 2002, and 2003 MM5 simulations used by the 

WRAP for the Arizona domain as the prognostic meteorological input. In particular, 

the Arizona domain, rather than the Nevada domain, was used because the Arizona 

domain included the geographic area needed to ensure a model domain that extended 

to at least 50 km beyond the edge of each Class I area (as seen in Figure 1, most of 

the relevant Class I areas are in Arizona and Utah). In addition, the Arizona domain 

was available for CALMET 5.8 and with upper air data, which was not the case for 

the Nevada domain. CALMET was run with some radius of influence changes to 

smooth the wind fields, and with the incorporation of upper air data. For more details 

regarding specific CALMET settings, please consult Section 5.B.4. 

CALPUFF was run with regulatory default settings. Ozone background was the same 

as that developed for the WRAP Arizona domain. The ammonia background was 

assumed constant at 1 ppb, the default in the IWAQM Phase 2 document for arid 

regions. 15 A description of stack parameters and source emission rates used in the 

CALPUFF modeling can be found in Section 5.B.5, as well as in the spreadsheet 

contained in Appendix C.

CALPOST was run with visibility method (MVISBK) 6 to apply the original 

IMPROVE equation, as well as with method 8, mode 5 to apply the revised 

IMPROVE equation. For both visibility methods, both annual average and best 20% 

 14 http://www.nature.nps.gov/air/maps/Receptors/ 15 Interagency Workgroup On Air Quality Modeling (IWAQM) Phase 2 Summary Report And Recommendations For 

Modeling Long Range Transport Impacts (EPA-454/R-98-019), EPA OAQPS, December 1998, 

http://www.epa.gov/scram001/7thconf/calpuff/phase2.pdf
Page 13 of 40

of days (“B20”) natural background concentrations were used. Our analysis 

primarily relies upon method 8 results, with best 20% backgrounds, as this is most 

consistent with current Federal Land Manager guidance for assessing visibility 

impacts at Class I areas, while also remaining consistent with the BART Guidelines. 

For each Class I area, we developed visibility results using four visibility 

postprocessing methods as listed below. A description of these methods, and of 

visibility calculations in general, are contained in Sections 5.B.2 and 5.B.3.

Table 7. Visibility Methods Used

abbr.

CALPOST 

Method No.

(MVISBK)

natural background 

concentrations

vm6a 6 annual average

vm6b 6 best 20% of days

vm8a 8 annual average

vm8b 8 best 20% of days

There are 9 control scenarios, of which only 8 were modeled, since emissions from 

the SCR scenarios c14 and c15 are the same. Three years of meteorology were used 

for each model run, for a total of 24 CALPUFF and POSTUTIL runs. Each of these 

models runs required a CALPOST run for each of the 5 areas and 4 visibility 

methods, for a total of 480 CALPOST runs. The names used for the CALPUFF input 

and output files reflect these combinations. For example, the 2002 CALPUFF input 

file for control scenario c11 is “cf_c11_2002.inp”, and the corresponding 

CALPOST input file for the Zion area using visibility method 8a is 

“ct_c11_vm8a_zion_2002.inp”.

Table 8. Summary of Model Cases

scen scenario name NDEP NOx 

case

NOx emissions SO2 and PM10 emissions

c00 WRAP WRAP baseline WRAP WRAP

c02 WRAP NOx NA WRAP NDEP BART

c04 Baseline NOx Baseline Base LNB+OFA NDEP BART

c11 Enh. LNB+OFA 1 Enhanced LNB+OFA NDEP BART

c12 SNCR 2 SNCR+LNB+OFA NDEP BART

c13 ROFA+Rotamix 3 ROFA+Rotamix NDEP BART

c14 SCR+ROFA 4 SCR+ROFA NDEP BART

c15 SCR 5 SCR+LNB+OFA NDEP BART

c16 SCR (0.06 

lb/MMBtu)

NA SCR+LNB+OFA at 0.06 

lb/MMBtu

NDEP BART
Page 14 of 40

2. Background on CALPUFF and visibility calculations

CALMET is a pre-processor that creates meteorological data suitable for input to 

CALPUFF. It accepts terrain, land use, and meteorological data in a number of 

forms, including data observations from surface and upper air meteorological 

stations; it can also accept 3D data fields from meteorological models such as MM5. 

Three years of meteorological data is standard, and is recommended in the BART 

Guidelines.

CALPUFF is the air quality model, and simulates ambient concentrations of 

pollutants by portraying source plumes as a series of puffs that can expand and be 

transported independently, according to the meteorological conditions each 

encounters. In addition to meteorology input, CALPUFF requires emission rates for 

the following visibility-impairing pollutants: SO2, SO4, NOx, secondary organic 

aerosol (SOA) or organic carbon (OC), elemental carbon (EC), and other fine 

particulate matter (PMF), and coarse particulate matter (PMC). Since data is not 

typically available for every one of the particulate matter (PM) components, some 

estimates must be made in order to speciate available PM data into SOA or OC, EC, 

PMF, and PMC. CALPUFF computes concentrations for every hour, and for every 

receptor location; there is a standard set of receptors for each Class I area.

POSTUTIL post-processes the concentrations from CALPUFF by apportioning the 

nitrate ion between its nitric acid and particulate nitrate forms; the amount in each 

form depends on the humidity and on the amount of sulfate and ammonia present. 

Finally, CALPOST uses the IMPROVE equation to convert the various chemical 

species concentrations into extinction (bext), the fraction of light removed from a sight 

path. CALPOST then converts extinction into deciviews (dv), a visibility metric 

more in line with human perception of visibility impairment, and the main metric 

used in the Regional Haze Rule. There are several variants to the visibility impact 

calculation, including which version of the IMPROVE equation is used, and how 

background concentrations and humidity are accounted for. Extinction and deciviews 

are available for each day modeled, and for each receptor location.

Under the BART Guidelines, visibility impact of a source is assessed relative to 

natural background, that is, the impairment that would exist without any artificial 

pollution sources. Estimates of natural background concentrations are provided by 

EPA in the natural conditions guidance16 and by the Federal Land Managers in the 

 16 Table 2-1 of Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule, U.S. 

Environmental Protection Agency, EPA-454/B-03-005, September 2003, on web page 

http://www.epa.gov/ttn/oarpg/t1pgm.html, with direct link 

http://www.epa.gov/ttn/oarpg/t1/memoranda/rh_envcurhr_gd.pdf
Page 15 of 40

FLAG 2010 guidance.17 Visibility impairment due to a particular source is usually 

expressed as percent extinction change (% increase over background extinction that is 

caused by including the source), or delta deciviews (increase over natural background 

deciviews caused by including the source).

Finally, of the visibility impacts computed for every modeled data and location, for 

each modeled day the receptor with the highest impact is chosen; and from among the 

resulting daily values, the 98th percentile is used as metric of visibility impact for a 

given Class I area. This would be the 8th high for a 365-day year, or the 22nd high if 

the 1095 days of the three years of data are considered together. Most often the 

average of three individual years’ 98th percentiles is reported, rather than the 98th 

percentile of all three years’ data merged together. Both the average and the merged 

value are reported here.

3. The original and the revised IMPROVE equations

The IMPROVE equation is used to convert measured or modeled concentrations into 

extinction for each pollutant chemical species, and then total them, accounting for the 

effect of relative humidity; it also includes the Rayleigh scattering that occurs in pure 

air. The extinction total is then used to calculate deciviews for use in visibility 

progress assessments. In December 2005 the IMPROVE Steering Committee revised 

the IMPROVE equation after a scientific assessment of its implications for regional 

haze planning. In particular, when compared to nephelometer direct measurements of 

visibility extinction, the original IMPROVE equation over-predicts for low extinction 

conditions and under-predicts for high extinction. These biases have direct relevance 

for estimates for the best 20% and worst 20% visibility days that are used to assess 

progress. 

Original IMPROVE equation:

bext = 3 * f(RH) * [sulfate]

+ 3 * f(RH) * [nitrate]

+ 4 * [organic mass]

+ 10 * [elemental carbon]

+ 1 * [fine soil]

+ 0.6 * [coarse mass]

+ 10

Each term in the equation is the extinction due to a particular measured component; 

bracketed quantities are concentrations of as measured at IMPROVE monitors. The 

 17 Federal Land Managers’ Air Quality Related Values Work Group (FLAG) Phase I Report—Revised (2010), U.S. 

Forest Service, National Park Service, U.S. Fish And Wildlife Service, October 2010. See 

http://www.nature.nps.gov/air/Permits/flag/ Direct link:

http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf
Page 16 of 40

organic mass is assumed to be 1.4 times the organic carbon mass that is measured by 

IMPROVE monitors. The 10 is for Rayleigh scattering which is due to the 

interaction of light with molecules of air itself with no pollutants, and is assumed to 

be the same for all locations, The f(RH) is a water growth factor for sulfate and 

nitrate, which are hygrosopic (their particles tend to attract water). Its value depends 

on relative humidity, ranging from 1 at low humidity to 18 at 98% humidity.

New IMPROVE equation:

bext = 2.2 * fs(RH) * [small sulfate] + 4.8 * fL(RH) * [large sulfate]

+ 2.4 * fs(RH) * [small nitrate] + 5.1 * fL(RH) * [large nitrate]

+ 2.8 * [small organic mass] + 6.1 * [large organic mass]

+ 10 * [elemental carbon]

+ 1 * [fine soil]

+ 1.7 * fss(RH) * [sea salt]

+ 0.6 * [coarse mass]

+ Rayleigh scattering (site-specific)

+ 0.33 * [NO2 (ppb)]

Sulfate is assumed to be all “large sulfate” if total sulfate is over 20 μg/m3, otherwise 

its fraction of the total is assumed to increase uniformly between 0 and 1 when the 

total is in the range between 0 and 20. I.e., large sulfate = (total sulfate/20)*total. A 

similar definition applies for nitrate and for organic mass. The organic mass is 

assumed to be 1.8 times the organic carbon mass that is measured by IMPROVE 

monitors, an increase over the original 1.4. Sea salt is estimated as 1.8 * [chloride] 

(or chlorine if chloride not available) Finally, the fs, fL, fss are water growth factors 

for small (“S”) and large (“L”) fractions of sulfate and nitrate, and for sea salt (“SS”). 

Their values depend on relative humidity, ranging from 1 at low humidity to over 5 at 

95% humidity.

The new equation has five changes: 1) greater completeness though the inclusion of 

sea salt, which can be important for coastal sites; 2) increased organic carbon mass 

estimate, based on more recent data for remote areas; 3) Rayleigh scattering using 

site-specific elevation and temperature, a refinement over the older network-wide 

constant; 4) separate estimates for small and large particles of visibility impacts and 

humidity-dependent particle size growth rates, which could affect estimates at the low 

and high ends; and 5) greater completeness though the inclusion of NO2 (Pitchford, 

2006)18.

The new equation shows broader scatter overall, but less bias in matching visibility 

measurements under high and low visibility conditions. That is, though it has a 

somewhat worse fit considering all the data, it has a better fit under visibility 

 18 Pitchford, Marc, 2006, "New IMPROVE algorithm for estimating light extinction approved for use", The 

IMPROVE Newsletter, Volume 14, Number 4, Air Resource Specialists, Inc.; web page: 

http://vista.cira.colostate.edu/improve/Publications/news_letters.htm

direct link: http://vista.cira.colostate.edu/improve/Publications/NewsLetters/IMPNews4thQtr2005.pdf
Page 17 of 40

conditions most relevant to regional haze planning, the best and worst 20% of days. 

The looser overall fit can cause a slightly different set of days to be the ones chosen 

than the 20% worst, but the chemical species composition for such days is little 

changed (IMPROVE technical subcommittee for algorithm review, 2001, pp. 11-12), 

and so this makes little difference for assessing the contribution of emission sources 

to current conditions, and for projecting the effect of emission controls. The split 

between small and large particles was the main factor in reducing the biases.

The organic carbon (OC) measured by the IMPROVE network does not include all 

organic matter (OM); based on 1970's urban data, a scaling factor of 1.4 is embedded 

in the original equation to account for the full mass. Based on recent data more 

relevant to relatively remote Class I areas, the revised IMPROVE equation embeds an 

OM/OC factor of 1.8. In practice, for the worst days the biggest effect of switching 

to the revised IMPROVE equation is this increased organic carbon mass, since the 

worst days are dominated by organic carbon from fires, rather than the sulfates and 

nitrates that come more from anthropogenic sources.

4. Modeling Methodology

EPA generally used the WRAP protocol19 as a starting point, with some important 

changes. The WRAP protocol received wide review and approval, and was the basis 

for BART screening and BART determination modeling by number of western states 

and by individual facilities. In performing visibility modeling for the Navajo 

Generating Station (NGS), located near Page, AZ, AECOM (formerly ENSR) used 

the WRAP protocol and MM5 meteorology as a starting point and improved the 

modeled wind fields by introducing changes to some CALMET meteorological 

settings.20 Following review and comment by the Federal Land Managers, AECOM 

made additional changes in accordance with FLM recommendations, including the 

incorporation of upper air data. For this action, EPA used the CALMET results from 

that AECOM work.

The WRAP protocol received extensive scrutiny during 2005-2006 by various States, 

EPA Regions, and Federal Land Managers (FLMs). Some key features of the 

protocol are listed here. Meteorological fields were derived from the MM5 

prognostic meteorological model (Mesoscale Model version 5, Penn State University 

and the National Center for Atmospheric Research), using a 36 km grid resolution, 

for the years 2001, 2002, and 2003 and with the continental United States as the 

modeling domain. Subdomains were extracted for use by individual states, such as 

Arizona and Nevada. The MM5 fields were then processed using CALMET 

 19 “CALMET/CALPUFF Protocol for BART Exemption Screening Analysis for Class I Areas in the Western United 

States”, Western Regional Air Partnership (WRAP); Gail Tonnesen, Zion Wang; Ralph Morris, Abby Hoats and 

Yiqin Jia, August 15, 2006. Available on UCR Regional Modeling Center web site, BART CALPUFF Modeling, 

http://pah.cert.ucr.edu/aqm/308/bart.shtml Direct link: 

http://pah.cert.ucr.edu/aqm/308/bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf 20 See “BART Analysis for the Navajo Generating Station Units 1 – 3”, ENSR Corporation, November 2007, 

Document No.: 05830-012-300
Page 18 of 40

(meteorological pre-processor, part of the CALPUFF modeling system) as 

preparation for use in the CALPUFF air quality model, using a 4 km grid resolution. 

After much discussion, WRAP elected to blend surface meteorological station 

observations into the MM5 fields, instead of relying on the CALMET “no 

observations” (“no obs”) mode. (The Federal Land Managers had wanted the 

blending in of upper air data as well, but this was not included in the WRAP 

modeling.) 

The WRAP protocol specified CALMET version 6.211 and CALPUFF version 6.112, 

the latest versions at the time. However, since the time of the WRAP protocol, 

problems were discovered in CALMET version 6.2 that resulted in EPA affirming 

that CALMET version 5.8 and CALPUFF version 5.8 of CALPUFF, are the 

regulatory versions to be used.21 

The AECOM CALMET modeling used by EPA differed from the WRAP protocol in 

using the regulatory version of the modeling system, and in several other ways. The 

CALMET settings were almost all the same; the WRAP-defined Arizona subdomain 

was used; all Class I Areas within 300 km of RGGS were included. However, when 

blending in meteorological station wind observations, AECOM used a lower radius of 

influence for stations (R1, R2, RMAX1). This resulted in smoother wind fields than 

those used for WRAP, which had some abrupt changes as one leaves the zone of 

influence of a given meteorological station. After initial input from the Federal Land 

Managers, EPA requested that certain other CALMET option settings be changed. 

These changes resulted in a more refined approach that is more consistent with 

approaches used in PSD permit application modeling. The revised modeling has 

more extensive use of meteorological station observations (e.g. IEXTR=-4 to 

extrapolate surface observations up to higher layers), and is responsive to the FLM 

concerns regarding adequacy of the surface-only observations used in the WRAP 

modeling. Various relevant CALMET option settings are listed in Table XX: 

Selected CALMET settings for RGGS. For meteorological input to CALPUFF, EPA 

used the AECOM CALMET results, per the “AECOM and EPA modeling” column 

of that table. 

 

21 As indicated in June 29, 2007 letter from Tyler Fox (EPA) to Joe Scire (TRC). Also indicated in U.S. EPA’s 

Support Center for Regulatory Air Models (SCRAM), CALPUFF model change bulletin, June 29, 2007. 

http://www.epa.gov/ttn/scram/dispersion_prefrec.htm#calpuff 
Page 19 of 40

Table 9. Selected CALMET settings for RGGS

Option Description EPA 

default

WRAP

protocol

AECOM 

and EPA 

modeling

Comments

version CALMET version 5.8, level 

070623

6.211, level 

060414

5.8, level 

070623

5.8 is EPA regulatory 

version

NOOBS No Observation Mode 0 0 or 1 

implied

0 Use both surface and upper 

air observations, per FLM 

recommendation

ICLOUD gridded cloud fields 0 0 0

IWFCOD diagnostic winds 1 1 1

IFRADJ Froude wind adj. 1 1 1

IKINE kinematic effects 0 0 0

IOBR O’Brien vertical wind adj. 0 0 0

ISLOPE slope flows 1 1 1

IEXTRP extrapolate wind to upper 

air

-4 1 -4 To extrapolate from surface, 

per FLM recommendation

ICALM extrapolate calm to upper air 0 0 0

BIAS layer biases sfc vs. UA NZ*0 NZ*0 NZ*0

IPROG gridded initial prognostic 0 14 14 Use prognostic inputs from 

MM5

RMAX1 max surface radius of 

influence

NA 50 30 Gives smoother wind fields, 

per AECOM

RMAX2 max aloft radius of 

influence

NA 100 100

RMAX3 max over-water radius of 

influence.

NA 100 100

RMIN min wind radius of 

influence.

0.1 0.1 0.1

RMIN2 min dist sfc winds extrap 4 4 4

TERRAD terrain radius of in influence NA 10 10

R1 weight surface Step 1 vs. 

obs

NA 100 18 Gives smoother wind fields, 

per AECOM

R2 weight aloft Step 1 vs. obs NA 200 20 Gives smoother wind fields, 

per AECOM

ITPROG 3D T from obs or prognostic 0 1 or 2 

implied

1 Use surface station 

temperatures, per FLM 

recommendation

TRADKM radius of influ. for T interp. 500 500 500

IAVET spatial T averaging 1 0 1 Smoothing turned on

JWAT1 starting land use for T 

interp. over water

999 51 51 (Could set to 999 to disable 

overwater feature & avoid a 

CALMET bug; very little 

“water” land use here 

anyway)

JWAT2 ending land use for T interp. 

over water

999 55 55

CALPOST visibility method 6 (MVISBK=6) had long been the recommended 

approach for assessing visibility impacts in Class I areas. It implements the original

IMPROVE equation, with monthly average humidity adjustment factors from the 
Page 20 of 40

2000 version of the FLAG document.22 It is incorporated in the regulatory version of 

CALPOST, version 5.6394. The revised IMPROVE equation is incorporated into a 

later version of CALPOST, 6.221, and is implemented as visibility method 8 

(MVISBK=8), mode 5, using monthly average humidity adjustment factors from the 

2010 version of the FLAG document; this has updated values for each Class I area 

and includes adjustment factors for small and large sulfate and nitrate, and also sea 

salt, to accommodate the revised IMPROVE equation. 

In order to use either of these methods, natural background concentrations are needed 

for each species in the respective IMPROVE equation. For method 8 and the revised 

IMPROVE equation, these are available for each Class I area in the FLAG 2010 

document, for both the annual average and for the average over the best 20% of days 

(“B20”). For method 6, only annual average background species concentrations are 

available, in Table 2-1 the 2003 EPA natural conditions guidance cited above. 

However that document’s Appendix B also provides extinction and deciviews for the 

best 20% of days; the ratio of B20 extinction to annual extinction can be used to scale 

the annual average concentrations, yielding an estimate of the B20 concentrations, 

which were used for this action. Finally, the 2003 EPA guidance gives relative 

humidity adjustment factors f(RH) for both the IMPROVE monitor location nearest a 

Class I area, and an interpolation from multiple monitors for the centroid of the Class 

I area; the latter was used here.

5. Stack Parameters and Source Emissions

Stack Parameters

Stack parameters used in the modeling are summarized in Table 10 below and were 

obtained from the Nevada Energy BART Analysis Reports23, and WRAP Regional 

Modeling Center files.24 There were certain discrepancies in the stack coordinates 

from these two information sources. In our modeling, we used the data from the 

WRAP files, since they more closely corresponded to the coordinates for the overall 

facility known to EPA’s Clean Air Markets Division.

 22 Federal Land Managers’ Air Quality Related Values Workgroup (FLAG) Phase I Report (December 2000), U.S. 

Forest Service, National Park Service, U.S. Fish And Wildlife Service. See 

http://www.nature.nps.gov/air/Permits/flag/; Direct link:

http://www.nature.nps.gov/air/Pubs/pdf/flag/FlagFinal.pdf

23 “BART Analysis for Reid Gardner Station Unit 1, Prepared for NV Energy”, October 2008, CH2MHill. See 

http://ndep.nv.gov/baqp/planmodeling/rhaze.html, file “Reid_Gardner_1_10-03-08.pdf”. Similar names for Unit 2 

and Unit 3 reports.

24 “Summary of WRAP RMC BART Modeling for Nevada, Draft#7”, April 24, 2007, WRAP Regional Modeling 

Center. See: “Nevada Results Summary” at http://pah.cert.ucr.edu/aqm/308/bart.shtml. Direct Link: 

http://pah.cert.ucr.edu/aqm/308/bart/calpuff/summary/NV_summary_May14_2007_v8-NoSRC02_SRC07.doc; also 

for stack locations see “NV_BART_emis”, 

http://pah.cert.ucr.edu/aqm/308/bart/calpuff/emissions/nv_emis_Mar09_2007.xls
Page 21 of 40

Table 10. Reid Gardner Generating Station Stack Parameters

Stack Parameter Unit 1 Unit 2 Unit 3

SRCNAM in CALPUFF RGGS1 RGGS2 RGGS3

HS, Stack Height, m 60.96 75.9 82.3

ES, Stack Elevation, m AMSL 487.68 487.68 487.68

DS, Stack Diameter, m 4.05 4.05 3.93

VS, Exit Velocity, m/s 15.96 15.34 21.75

TS, Exit Temperature, K 330.37 335.93 339.26

Heat input, MMBtu/hr 1215 1215 1237

Location

LCC X km -1555.5060 -1555.5120 -1555.5210

LCC Y km -218.2230 -218.2522 -218.2911

longitude -114.63175 -114.63175 -114.63177

latitude 36.6580507 36.6577814 36.6574208

A discussion of the basis for each model case’s emission estimates is included in the 

following section, as well as a description of the various PM10 speciation profiles and 

sulfuric acid emission calculation methodologies used for each model case. Detailed 

emission calculations for each model case, including particulate speciation profiles 

and sulfuric acid emission calculations, can be found in Appendix C. 

Model Scenario Emission Factor Basis

Case 00 (WRAP) consists of WRAP baseline emission rates for each of the Reid 

Gardner units. The results of this case were compared to similar model runs 

performed by Nevada Energy and by WRAP that also made use of WRAP baseline 

emissions. 

Case 02 (WRAP NOx) consists of WRAP baseline emission rates for NOx. For PM10

and SO2, this case consists of the emission rates corresponding to the BART 

determinations for these units in the Nevada RH SIP (0.015 lb/MMBtu and 0.15 

lb/MMBtu, respectively) as approved by EPA on December 13, 2011.25 The results 

of this case were used primarily for informational purposes in order to determine the 

visibility improvement associated with PM10 and SO2 BART control. 

Case 04 (Baseline NOx) uses the baseline emission factor for NOx relied upon by 

NDEP in the RH SIP.26 For PM10 and SO2, this case consists of the emission rates 

corresponding to the BART determinations for these units in the Nevada RH SIP. 

Although these BART determination emission rates do not necessarily represent 

historical emissions at Reid Gardner, they have been approved for inclusion into the 

Nevada SIP. As a result, we regard the use of these emission rates in this baseline 

 25 77 FR 17334 26 Per Table 1, NDEP Reid Gardner BART Determination, October 22, 2009. Available as Docket Item No. EPAR09-OAR-2011-0130-0005. Baseline emission factors are not explicitly calculated by NDEP. As illustrated in 

Appendix C, the baseline emission factor represents the listed annual emissions divided by “Base Heat Input.”
Page 22 of 40

case and in control option cases to be the most accurate approach to predicting 

visibility impairment attributable to Reid Gardner. 

Cases 11 through 15 (Control Options 1 through 5) use the NOx emission factors for 

the various control technology options as indicated by NDEP in the RH SIP. For 

PM10 and SO2, these cases consist of the emission rates use in Case 04 in order to 

provide a clear estimate of the visibility improvement associated with each NOx 

control technology.

Case 16 (Control Option 6) is an additional case that does not correspond to any of 

Nevada Energy’s control technology options. This case uses a NOx emission factor 

that corresponds to an approximately 86% SCR control efficiency from the NOx 

emission rates of Case 04 (Baseline NOx). 

PM10 Speciation

PM10 emissions are not directly entered into the CALPUFF model but are instead 

speciated into constituent species. These PM10 emissions were classified into the 

following particulate species using a combination of AP-42 emission data and Federal 

Land Managers’ guidance:

• Coarse particulate matter (PMC)

• Fine particulate matter (PMF)

• Sulfates (SO4)

• Secondary organic aerosols (SOA)

• Elemental carbon (EC)

Case 00 (WRAP) PM10 emissions are based upon the WRAP PM10 emission rate. 

These emissions were speciated based upon the assumption that the WRAP PM10

emission rate represents total filterable PM (i.e., the result of a Method 5 test). This 

PM10 emission rate was speciated into PMC, PMF, and EC based upon AP-42 

emission factors, as shown in Appendix C. The condensable PM10 fraction (SOA and 

SO4 species), which would not be represented in the WRAP PM10 emission rate, was 

calculated separately and included in the model.

The remaining cases’ PM10 emissions are based upon the Nevada RH SIP PM10

BART determination of fabric filters and a 0.015 lb/MMBtu emission rate. 

Particulate emissions for these cases were speciated based upon the conservative 

assumption that the BART emission rate represents total PM10 (i.e., filterable plus 

condensable fractions). As included in Appendix C, PM10 emissions were speciated 

based upon AP-42 emission factors in a manner consistent with Federal Land 

Manager’s guidance. 

Sulfuric Acid (H2SO4) Emissions

For the cases modeled in our analysis, we accounted for two mechanisms of sulfur 

acid manufacture: (1) combustion from fuel and (2) production from use of SCR 

catalyst. These emissions were calculated using either AP-42 emission factor data or 
Page 23 of 40

the Electric Power Research Institute (EPRI) document “Estimating Total Sulfuric 

Acid Emissions from Stationary Power Plants.”27

Case 00 (WRAP) relied upon a particulate speciation profile that did not include SO4 

emissions. As a result, sulfuric acid emissions from fuel combustion were calculated 

using the EPRI emission calculation methodology.

Cases 02, 04, and 11 through 16 relied upon particulate speciation profiles that did 

include SO4 emissions. Sulfuric acid emissions from fuel combustion can safely be 

assumed to be represented in the SO4 particulate fraction. As a result, no additional 

emission calculations were performed to quantify sulfuric acid from fuel combustion.

Cases 14 through 16 model the use of SCR. As a result, in addition to the sulfuric 

acid emissions from fuel combustion represented in the particulate speciation, an 

additional amount of sulfur acid manufactured from the use of SCR catalyst was 

calculated. The quantity of sulfuric acid was calculated using the EPRI calculation 

methodology for SCR. 

6. Visibility Modeling Results

Visibility impacts for the Grand Canyon National Park, the Class I area where RGGS 

has the highest impacts, are shown in the following table, for all visibility methods 

used. The results are for all three units modeled together, but only unit 1 NOx 

emission factors are shown for reference (the other units are comparable). The full 

results, including all areas and modeled years, are shown in the tables later in this 

document. Additional results are available in Appendix E (spreadsheet 

(“RGGS_TSD_CALPUFF_tables.xls”).

The benefit of SCR relative to the base case is only 0.38 dv (for the visibility method 

showing the highest impacts and benefits,“vm8b”). While this is not insignificant in 

the context of an overall regional haze plan, considering that visibility progress is 

dependent on the cumulative effect of controls for many sources, this is still not a 

large benefit. It does not in itself show whether SCR is warranted or not in the BART 

context. 

The incremental benefit of SCR over ROFA+Rotamix, based on the 98th percentile 

impact of merged years, is only 0.09 dv (as seen in Table 14 below). Further, even 

the incremental benefit of SCR at a more stringent 0.06 lb/MMBtu emission rate is 

only 0.10 dv. This result is small enough that it tends to support NDEP’s 

consideration of incremental visibility benefit in its BART determination, and the 

conclusion that SCR is not required for BART.

 27 "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, April 2010
Page 24 of 40

Table 11. EPA Modeling Results –

Visibility Impacts at the Grand Canyon 

average of 3 individual year 98th 

percentiles

98th percentile of merged 

years

visibility 

method 6

visibility 

method 8

visibility 

method 6

visibility 

method 8

Unit 1 NOx, 

lb/MMbtu1

annl. 

avg bg

B20 

bg

annl. 

avg bg

B20 

bg

annl. 

avg 

bg

B20 

bg

annl. 

avg 

bg

B20 

bg

scen Scenario vm6a vm6b vm8a vm8b vm6a vm6b vm8a vm8b

c00 WRAP for NOx, SO2, PM 0.591 0.61 0.78 0.60 0.83 0.59 0.75 0.58 0.80

c02 WRAP NOx, NDEP SO2 & PM 0.591 0.56 0.72 0.56 0.77 0.55 0.71 0.54 0.74

c04 Baseline NOx LNB+OFA 0.462 0.46 0.60 0.45 0.63 0.44 0.58 0.42 0.59

c11 Enh. LNB+OFA 0.364 0.40 0.52 0.40 0.54 0.38 0.50 0.37 0.51

c12 SNCR+LNB+OFA 0.273 0.28 0.37 0.28 0.39 0.28 0.36 0.27 0.37

c13 ROFA+Rotamix 0.195 0.24 0.31 0.24 0.33 0.22 0.29 0.22 0.31

c15 SCR+LNB+OFA 0.085 0.19 0.24 0.18 0.25 0.17 0.22 0.16 0.22

c16

SCR+LNB+OFA 0.06 

lb/MMBtu 0.06 0.17 0.23 0.16 0.22 0.16 0.20 0.15 0.20

1 The results are for all three units modeled together, but only unit 1 NOx emission factors are shown for reference 

(the other units are comparable). 

Table 12. EPA Modeling Results –

Visibility Improvement at the Grand Canyon (relative to baseline)

average of 3 individual year 98th 

percentiles

98th percentile of merged 

years

visibility method 

6

visibility 

method 8

visibility 

method 6

visibility 

method 8

Unit 1 NOx, 

lb/MMbtu1

annl. 

avg bg B20 bg

annl. 

avg 

bg

B20 bg

annl. 

avg 

bg

B20 

bg

annl. 

avg 

bg

B20 

bg

scen Scenario vm6a vm6b vm8a vm8b vm6a vm6b vm8a vm8b

c00 WRAP for NOx, SO2, PM 0.591 0.15 0.18 0.15 0.20 0.14 0.18 0.16 0.21

c02 WRAP NOx, NDEP SO2 & PM 0.591 0.10 0.13 0.11 0.15 0.10 0.13 0.11 0.16

c04 Baseline NOx LNB+OFA 0.462

c11 Enh. LNB+OFA 0.364 -0.06 -0.08 -0.06 -0.08 -0.06 -0.08 -0.06 -0.08

c12 SNCR+LNB+OFA 0.273 -0.18 -0.23 -0.17 -0.24 -0.17 -0.22 -0.16 -0.21

c13 ROFA+Rotamix 0.195 -0.22 -0.29 -0.22 -0.30 -0.22 -0.29 -0.20 -0.28

c15 SCR+LNB+OFA 0.085 -0.27 -0.35 -0.28 -0.38 -0.28 -0.36 -0.26 -0.36

c16 SCR+LNB+OFA 0.06 

lb/MMBtu

0.06 -0.29 -0.37 -0.29 -0.41 -0.29 -0.37 -0.28 -0.38

1 The results are for all three units modeled together, but only unit 1 NOx emission factors are shown for reference 

(the other units are comparable). 
Page 25 of 40

Table 13. EPA Modeling Results –

Incremental Visibility Improvement at the Grand Canyon (SCR vs. ROFA/Rotamix)

average of 3 individual year 98th 

percentiles

98th percentile of merged 

years

visibility 

method 6

visibility 

method 8

visibility 

method 6

visibility 

method 8

Unit 1 NOx, 

lb/MMbtu1

annl. 

avg 

bg

B20 bg

annl. 

avg 

bg

B20 bg

annl. 

avg 

bg

B20 

bg

annl. 

avg 

bg

B20 

bg

scen Scenario vm6a vm6b vm8a vm8b vm6a vm6b vm8a vm8b

c13 ROFA+Rotamix 0.195

c15 SCR+LNB+OFA 0.085 -0.05 -0.07 -0.06 -0.08 -0.05 -0.07 -0.06 -0.09

c16 SCR+LNB+OFA

0.06 lb/MMBtu

0.06 -0.07 -0.09 -0.08 -0.11 -0.06 -0.08 -0.08 -0.10

1 The results are for all three units modeled together, but only unit 1 NOx emission factors are shown for reference 

(the other units are comparable). 

Using natural background concentrations from the best 20% of days (“B20”) 

increases visibility impacts estimates by about 30% relative to using the annual 

average (going from vm6a to vm6b, or from vm8a to vm8b). This makes sense 

because natural visibility impairment is lower on the best days, so any given impact 

will be a larger percentage of the best values than of the annual average. States are 

free to use annual average background concentrations in assessing visibility 

impacts,28 and NDEP did so, but even if B20 is used, the visibility benefit of SCR is 

relatively small.

The effect of changing to the revised IMPROVE equation varies by area and scenario, 

but on average decreases 98th percentile delta deciviews by about 5%.

7. Comparison to other modeling

Overview

RGGS has been modeled several times in recent years, by the WRAP Regional 

Modeling Center29, by CH2MHill30 for Nevada Energy, and by Gray Sky Solutions.31 

The differences between their applications of the CALPUFF modeling system are 

summarized in Table 14 below, “CALPUFF settings differences for various model 

applications.” The various modeling domains are illustrated in Figure 2, “Reid 

Gardner Generating Station CALPUFF and CALMET Modeling Domains.”

 28 “Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations”, 

Memorandum from Joseph W. Paisie, EPA OAQPS Geographic Strategies Group, to Kay Prince, EPA Region 5, 

July 19, 2006. Available at: http://www.epa.gov/visibility/pdfs/memo_2006_07_19.pdf

29 WRAP Regional Modeling Center, “Summary of WRAP RMC BART Modeling for Nevada, Draft#7, cited 

above.

30 CH2MHill, “BART Analysis for Reid Gardner Station Unit 1, Prepared for NV Energy”, cited above 31 “Modeling for the Reid Gardner Generating Station: Visibility Impacts in Class I Areas”, H. Andrew Gray, Gray 

Sky Solutions, August 2011
Page 26 of 40

Compared to other modeling efforts involving RGGS, the results of our CALPUFF 

modeling indicate lower visibility impacts, as well as lower visibility improvement 

attributable to the various NOx control technologies (both from baseline and 

incremental). As described further below, we examined the sensitivity of visibility 

impacts to multiple variables in order to better understand our model results. Based 

on the results of our sensitivity analysis, we have identified the most important 

differences as 1) the use of different CALMET versions, and 2) the use of certain 

non-default puff control parameters by the WRAP. 

Regarding CALMET versions, EPA used the regulatory version of CALMET 

(version 5.8), while others used post-5.8 versions. The particular non-default puff 

parameters used by WRAP were not addressed in the WRAP protocol. While these 

alternative values are not necessarily wrong for application of the model to this area, 

they are not further explained in the WRAP documentation, and make a substantial 

difference to the modeled impacts:

• MXSAM Max sampling steps for one time step: 99 (default) vs. 5 (WRAP)

• CDIV(2) divergence criteria: 0 & 0 (default) vs. .01 & .01 (WRAP)

• SL2PF Slug-to-puff transition: 10 (default) vs. 5 (WRAP)

• NSPLIT number of puffs after split 3 (default) vs. 2 (WRAP)
Page 27 of 40

Figure 2. Model Domains for Various CALPUFF Modeling Efforts 
Page 28 of 40

Table 14. CALPUFF settings differences for various model applications

Processor Item WRAP Nevada Energy Gray EPA

CALMET

CALMET 

version 6.211 6.211 6.211 5.8

parameters mainly default mainly default mainly default

mainly default;

smaller influence 

radii

MM5 inputs

2001: Alpine 

Geophysics; 

2002: WRAP 

RMC; 2003: 

LADCO

2001 & 2002: 

Alpine 

Geophysics; 

2003: LADCO

same as 

Nevada Energy same as WRAP

upper air obs. Not included Not included Not included Included

domain

NV WRAP 

domain; 

includes all of 

NV

RGGS-centered, 

includes all of 

NV and most of 

California

RGGS-centered, 

includes all of 

NV and most of 

California

AZ WRAP 

domain; includes 

half of NV and all 

of AZ

domain size, 

km 792 x 1224 1112 x 1008 1112 x 1008 1152 x 900

proj. (origin); 

parallels; 

datum

LCC (40, 97); 

33; 45; NWS-84

LCC (40, 117); 

33; 45; NAD83

LCC (40, 117); 

33; 45; NAD83

LCC (40, 97); 

33; 45; NWS-84

CALPUFF

CALPUFF 

version 6.112 6.112 6.262 5.8

parameters some puff nondefaults defaults defaults defaults

domain

So. NV WRAP 

domain; almost 

all of NV

square about 

RGGS (CH2M 

coords)

square about 

RGGS (CH2M 

coords)

square about 

RGGS (WRAP 

coords)

domain size, 

km 700 x 996 624 x 684 624 x 684 628 x 624

max mix ht, m 4500

(orig. 3000) 4500 4500 4500

PM speciation Total PM as PM 

fine

SO4, EC, OC, 

PMF, PMC

SO4, EC, OC, 

PMF, PMC

SO4, EC, OC, 

PMF, PMC

POSTUTIL POSTUTIL 

version <1.5? 1.52 1.52? 1.56

CALPOST

CALPOST 

version 6.1? 6.131 6.221 6.221 (also 5.6394)

visibility 

method 6 6 8 6 and 8

natural 

background annual average annual average annual average annual average and B20 
Page 29 of 40

Comparison of Baseline Impacts

The EPA-modeled impacts for Grand Canyon National Park are roughly one-third of 

those modeled by Nevada Energy for the base case (EPA “c04”; Nevada Energy

“Base/LNB+OFA”). For visibility method 6, annual average background (“vm6a”), 

the EPA modeled impact for the all three units for the base case is 0.46 dv (average of 

the three years); Nevada Energy found an impact of 0.46 dv for Unit 1 alone. 

Summing the Nevada Energy impact for all three units, and discounting by 8% (to 

account for the difference between modeling units separately vs. together, as shown 

in Table 15 for GRCA) gives (0.46+0.45+0.36)*92% = 1.17 dv for Nevada Energy, 

as compared to 0.46 dv for EPA. 

A similar ratio applies to the WRAP base case (EPA “c00”; Nevada Energy “rm” or 

“WRAP baseline”), where EPA modeled 0.61 dv, roughly a third of the Nevada 

Energy modeled (0.81+0.80+0.76)*92% = 2.18 dv. The comparable result for the 

modeling by Gray was 2.17 dv (though this used visibility method 8 instead of 6). 

For comparison, the WRAP itself found 1.25 dv for all three units for the base case. 

The EPA results are thus roughly 50% lower than WRAP, whereas the Nevada 

Energy and Gray results are about 50% higher than WRAP’s for the WRAP base 

case.

The modeling performed by Gray Sky Solutions matched the modeling by Nevada 

Energy in most particulars, however it did use a slightly later CALPUFF version. In 

addition, the SCR scenario modeled included a substantial SO2 reduction, so the 

results are not directly comparable to the NOx-only reductions in the Nevada Energy

and EPA modeling of SCR.

Sensitivity Analysis

There are substantial differences between the visibility impacts modeled by the 

WRAP, Nevada Energy, and EPA, even with (nearly) identical emission inputs. This 

is because of the different meteorological inputs to CALMET used, and by the 

different versions of CALMET and CALPUFF.

To better understand these differences, EPA conducted a series of sensitivity 

simulations for the 2001 meteorology year (the one with the highest impacts). The 

series started with EPA’s WRAP base case (c00) input files, and changed various 

inputs to make them more like the inputs used by the WRAP. (Actually, in preparing 

the model input files, the WRAP’s own input files were used as a starting point, 

except for the “c00” and “cwe” scenarios.) All runs used visibility method 6, with 

annual average natural background concentrations. The results are detailed in the 

accompanying table below, “Comparison of EPA’s RGGS CALPUFF modeling and 

variants to WRAP BART modeling results” (also available in accompanying 

spreadsheet, “WRAP_compare_tables.xls”), but the results are summarized here.

Starting from EPA’s c00 base case, a new “cwe” control case (WRAP emissions) was 

run that used the same NOx emissions and PM emissions and speciation that the 
Page 30 of 40

WRAP used, that is, total particulate matter (PM) modeled as fine particulate (PMF), 

rather than separated into chemical components. The results of this model run 

resulted in a decrease in 98th percentile delta deciview visibility impacts by only a 

few percent.

The next simulation was WRAP’s own CALPUFF input files, including the puff 

parameter changes noted above. This resulted in over a 50% increase in Grand 

Canyon impacts, with smaller changes at the other areas (and a 2% decrease at 

Sycamore Canyon). Thus, the puff parameters account for a large proportion of the 

difference between the EPA and the WRAP results.

The CALPOST post-processor version was next changed from 5.6394 to 6.131, 

which was the version available around the time that the WRAP and Nevada Energy

were performing modeling. Thus, the CALPOST version had no effect on the 

visibility impacts.

The CALPUFF model itself was then changed, from 5.8 to the 6.112 version used by 

the WRAP. This had essentially no effect on the visibility impacts, although they 

appear shifted by one day due to the convention used in later versions of stating dates 

in terms of their ending hour, rather than their starting hour. (So, 2001-01-01 appears 

as 2000-12-31 in the later CALPUFF version.) Thus, the CALPUFF version had 

essentially no effect on the visibility impacts.

The remaining comparison is between the WRAP modeling itself and EPA modeling 

using the same emissions, PM speciation, CALPUFF settings, and CALPUFF and 

CALPOST versions that the WRAP used, but with different meteorology and 

CALMET versions. In changing from the AECOM meteorology used by EPA to the 

meteorology used by WRAP, visibility impacts increased by some 60%. Thus, the 

CALMET version, incorporation of upper air data, and possibly meteorological 

domain account for a large proportion of the difference between the EPA and the 

WRAP results.

The substantial differences between EPA and WRAP results for the WRAP base case 

for RGGS can therefore be attributed in part to differences in CALPUFF puff 

parameters, and especially to differences in the version of CALMET used. 

Differences in model domains may also play a role. The CALMET and CALPUFF 

domains cover different territory and thus will have slightly different meteorology; in 

addition; puffs that advect out of one domain and are lost to the simulation may 

remain within the other domain and affect visibility estimates.

Additional Analysis of Model Results

As an additional check, EPA examined visibility, sulfate, and nitrate over the entire 

modeling domain, i.e. with “gridded” receptors, instead of the receptor sets within the 

Class I areas. It is possible that overall visibility impacts were similar between the 

various simulations, but they occurred at different locations; that is, a dense plume 

may have hit the Grand Canyon in the WRAP simulation, but missed it in the EPA 
Page 31 of 40

simulation because of wind direction differences. Little was discovered from the 

gridded simulations, but the biggest shift was seen with the change from default to 

WRAP non-default puff parameters (gridded results from the WRAP modeling itself 

were not available for comparison). Extinction and concentration isopleths for these 

simulations are shown in Figure 3, “Reid Gardner, 8th High at Each Gridded 

Receptor” and Figure 4 “Reid Gardner, 1st High at Each Gridded Receptor.” For 

both figures, the main difference between the two simulations appears to be that the

zone of higher visibility and nitrate impacts has a lobe to the northeast, suggesting 

stronger wind transport in that direction, and resulting in higher impact regions 

reaching the western end of the Grand Canyon. Because these plots are of the ranked 

values, e.g. the 8th high over the entire year, the plots are composites of results on 

many days; a much more detailed analysis would be needed to understand why the 

results differ between the simulations. However, the overall similarity of the impact 

patterns at least gives some assurance that no gross error was made in preparing the 

simulation inputs.

A few additional test runs showed that on average, modeling the three units separately 

and adding the results gave 98th percentile delta deciview impacts about 4% higher 

than when the units are modeled together in a single CALPUFF run. This may reflect 

the competition of sulfate and nitrate in the plumes for available ammonia when the 

units are modeled together. The results for Grand Canyon are the basis for the “8% 

discount” applied above to the sum of impacts from individually modeled units.

Table 15. Comparison of CALPUFF Results: 

Sum of individual unit results vs. Modeling all units together in single model run

Class I Area Visibility Impact (dv)1

Unit 1 Unit 2 Unit 3 simple 

sum

modeled 

together

% difference 

brca 0.059 0.061 0.061 0.181 0.181 0%

grca 0.254 0.264 0.264 0.782 0.725 8%

jotr 0.233 0.229 0.229 0.691 0.663 4%

syca 0.045 0.039 0.039 0.123 0.127 -3%

zion 0.103 0.105 0.105 0.313 0.307 2%

Total -- -- -- 2.090 2.003 4% 1 Based on 98th percentile impact using visibility method 6 and annual average natural background
-1800 -1600 -1400

-600

-400

-200

-600

-400

-200

-600

-400

-200

-1800 -1600 -1400

-600

-400

-200

-600

-400

-200

-600

-400

-200

15

16

17

18

19

20

21

22

23

24

25

extinction,

1/Mm

0

0.05

0.1

0.2

0.3

0.4

0.5

0.6

0.7

NO3,

μg/m3

0

0.02

0.04

0.06

0.08

0.1

0.12

0.14

0.16

0.18

0.2

0.22

0.24

SO4,

μg/m3

EPA CALPUFF parameters WRAP CALPUFF parameters

Reid Gardner, 8th High at Each Gridded Receptor (628 x 624 km domain, 4 km grid cells)
-1800 -1600 -1400

-600

-400

-200

-600

-400

-200

-600

-400

-200

-1800 -1600 -1400

-600

-400

-200

-600

-400

-200

-600

-400

-200

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

extinction,

1/Mm

0

0.2

0.4

0.6

0.8

1

1.2

1.4

NO3,

μg/m3

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.5

0.55

0.6

0.65

0.7

0.75

0.8

SO4,

μg/m3

EPA CALPUFF parameters WRAP CALPUFF parameters

Reid Gardner, 1st High at Each Gridded Receptor (628 x 624 km domain, 4 km grid cells)
Page 34 of 40

6. Federal Implementation Plan (FIP) Elements

We are proposing to disapprove certain elements of the Nevada RH SIP and propose a 

corresponding FIP for these elements. The RH SIP elements we are disapproving include 1) the 

NOx emission limit of 0.28 lb/MMBtu for Unit 3, and 2) the rolling 12-month averaging period 

for monitoring NOx emissions for Units 1 through 3. 

A. Unit 3 Emission Limit 

We are proposing to promulgate a FIP to establish a NOx emission limit of 0.20 

lb/MMBtu for Unit 3. In its RH SIP, NDEP proposed a NOx emission limit of 0.28 

lb/MMBtu for Unit 3. This limit for Unit 3 (0.28 lb/MMBtu) was higher than the 

emission limit NDEP proposed for Units 1 or 2 (0.20 lb/MMBtu each). The higher 

emission limit appears to be partially attributable to the fact that the application of 

control technology to Unit 3 results in less stringent levels of performance relative to 

Units 1 and 2. As shown in Table 5 of this notice, Nevada Energy’s emission 

estimates indicate that application of ROFA with Rotamix achieves nearly 60 percent 

reduction from baseline on Units 1 and 2, but only a 38 percent reduction from 

baseline on Unit 3. These percent reduction values were used by NDEP in 

developing its own estimate of NOx emissions, which form the basis for the proposed 

NOx limits. 

Nevada Energy’s BART analysis for Unit 3 did not provide a unit-specific 

explanation for this difference in control effectiveness. In responding to comments 

on this issue, NDEP indicated that it deferred to Nevada Energy’s operational 

experience in developing control efficiency data, and had no reason to question their 

estimates.32 The case-by-case nature of the BART determination process does 

provide for the consideration of site-specific and unit-specific characteristics in the 

BART analysis.33 While there may be unique characteristics associated with Unit 3 

that justify the lower percent reduction values used by Nevada Energy and NDEP, we 

do not find the information in the record on this issue to be at a sufficient level of 

detail to support this determination. 

In the absence of what we consider sufficient justification by Nevada Energy and 

NDEP, we have evaluated Unit 3 control option emissions predicated upon similar 

levels of performance relative to Units 1 and 2. Based upon the Unit 3 baseline 

emissions relied upon by NDEP (described in the ‘NDEP’ column in Table 5), if a 

percent reduction similar to Units 1 and 2 were applied to Unit 3 baseline emissions, 

it can be expected to attain a NOx emission rate of 0.20 lb/MMBtu using the ROFA 

with Rotamix control option.

B. Averaging Period

In its RH SIP, NDEP proposed NOx limits with a 12-month rolling averaging period 

for Unit 1 through 3, which is a longer averaging period than the 30-day rolling 

 32 Page D-37, Appendix D and C-9, Appendix C, Nevada RH SIP. Available as attachments to EPA-R09-OAR2011-0130-0003 33 For example, when determining what control options are considered technically feasible at a specific unit, 70 FR 

39165
Page 35 of 40

average indicated by the BART Guidelines. Longer averaging periods allow 

operators the flexibility to “smooth out” short-term emission spikes by averaging 

those values with periods of lower emission rates. In responding to comments on 

this issue in their RH SIP, NDEP indicated that Nevada Energy expected a high 

degree of operational variability with the ROFA with Rotamix control option based 

upon previous operational experience with ROFA.34 

A summary of NOx emission rates from Units 1 through 3 as reported by the Clean 

Air Markets Division (CAMD) is included in Appendix D, and includes annual and 

monthly average emissions over a 2001-11 time frame. Monthly average NOx data 

over a 2010-11 time period indicates a certain degree of fluctuation, as well as a 

general downward trend in NOx emissions. NDEP has indicated that the downward 

trend in NOx emissions is partially due to the use of a coal fuel stream that consists of 

a mixture of bituminous and sub-bituminous coal. Specifically, the Utah/Colorado 

coal that has historically represented the entirety of the fuel stream to Units 1 through 

3 has recently been supplemented with varying amounts of lower-nitrogen content 

Wyoming sub-bituminous coal.35 Although operational flexibility can be a legitimate 

consideration when establishing an enforceable limit, we consider use of a rolling 12-

month averaging period instead of a rolling 30-day average to be inconsistent with 

BART Guidelines.36 We believe the fluctuations of the NOx emissions from each of 

the units is better dealt with by averaging the emissions from the three units to 

determine compliance over the 30-day rolling average.

 34 Page D-60, Appendix D, Nevada RH SIP. A 35 Email dated March 18, 2012, from Mike Elges (NDEP) to Colleen McKaughan (EPA) 36 70 FR 39172
Page 36 of 40

Appendix A:

EPA Analysis of NOx Control Cost Estimates (from original RH SIP) for Reid Gardner 

Generating Station

See www.regulations.gov, docket ID number EPA-R09-OAR-2011-0130
Printed 4/2/2012

Comparison of SCR Control Costs (Original, 2008)

Parameter

NDEP Revised EPA NDEP Revised EPA NDEP Revised EPA

Unit Output (kW)

Heat Input (MMBtu/hr)

Boiler Type

Ctrl technologyCtrl Emission Rate (lb/MMBtu) 0.085 0.085 0.083 0.083 0.098 0.098

Total Capital Costs $35,048,000 $26,840,000 $35,048,000 $26,840,000 $35,048,000 $26,840,000

Total Annual Costs

Fixed Costs $330,000 $330,000 $330,000 $330,000 $330,000 $330,000Variable Costs $699,801 $699,801 $748,551 $748,551 $670,893 $670,893

Capital Recovery $3,703,556 $2,533,506 $3,703,556 $2,533,506 $3,703,556 $2,533,506

20 yrs @ 8.5% 20 yrs @ 7.0% 20 yrs @ 8.5% 20 yrs @ 7% 20 yrs @ 8.5% 20 yrs @ 7%

Total Annual Costs $4,733,357 $3,563,307 $4,782,107 $3,612,057 $4,704,449 $3,534,399

NOx Removed from baseline (tpy) 1,850 1,850 2,010 2,009 1,774 1,775

Average Cost per ton ($/ton) $2,559 $1,926 $2,379 $1,798 $2,652 $1,991

Incremental Cost per ton ($/ton) $5,684 $4,067 $5,425 $3,885 $3,446 $2,477

Previous ctrl technology ROFA+Rotamix ROFA+Rotamix ROFA+Rotamix

SCR+LNB+OFA SCR+LNB+OFA SCR+LNB+OFA

Reid Gardner

Unit 2 Unit 3

Wall‐fired Wall‐fired Wall‐fired

1132 1132

100,000

1132

100,000 100,000

Unit 1

SCR Cost Comparisons

Page 1 of 13
Reid Gardner NOx Control Effectiveness Summary ‐ EPA Revised Costs

Unit No. Annual Heat Input1

(MMBtu/yr)

Unit 1 9,818,313Unit 2 10,501,749Unit 3 10,063,851

Unit No. Parameter Units Baseline2 LNB+OFA LNB+OFA+SNCR ROFA+Rotamix SCR+LNB+OFA SCR+ROF

Emission Rate (tpy) 2,267 1,784 1,340 959 417 417

Removed (tpy) ‐‐ 483 927 1,308 1,850 1,850Removal Rate (%) ‐‐ 21.3% 40.9% 57.7% 81.6% 81.6%

Emission Factor (lb/MMBtu) 0.462 0.363 0.273 0.195 0.085 0.085

Annual Cost ($) $442,469 $946,040 $1,360,867 $3,563,307 $4,084,42

Average Cost Effectiveness ($/ton) $916 $1,021 $1,040 $1,926 $2,208

Incremental Cost Effectiveness ($/ton) ‐‐ $1,135 $1,088 $4,067 $5,030

Previous ctrl technology ‐‐ LNB+OFA LNB+OFA+SNCR ROFA+Rotamix ROFA+Rota

Emission Rate (tpy) 2,445 1,866 1,401 1,003 436 436

Removed (tpy) ‐‐ 579 1,044 1,442 2,009 2,009

Removal Rate (%) ‐‐ 23.7% 42.7% 59.0% 82.2% 82.2%

Emission Factor (lb/MMBtu) 0.466 0.355 0.267 0.191 0.083 0.083

Annual Cost ($) $442,469 $968,449 $1,408,676 $3,612,057 $4,159,30

Average Cost Effectiveness ($/ton) $764 $928 $977 $1,798 $2,070

Incremental Cost Effectiveness ($/ton) ‐‐ $1,131 $1,106 $3,885 $4,850

Previous ctrl technology ‐‐ LNB+OFA LNB+OFA+SNCR ROFA+Rotamix ROFA+Rota

Emission Rate (tpy) 2,268 2,118 1,590 1,399 493 493

Removed (tpy) ‐‐ 150 678 869 1,775 1,775

Removal Rate (%) ‐‐ 7% 30% 38% 78% 78%

Emission Factor (lb/MMBtu) 0.451 0.421 0.316 0.278 0.098 0.098

Annual Cost ($) $442,469 $895,762 $1,290,483 $3,534,399 $4,091,34

Average Cost Effectiveness ($/ton) $2,958 $1,321 $1,485 $1,991 $2,305

Incremental Cost Effectiveness ($/ton) ‐‐ $858 $2,064 $2,477 $3,092

Previous ctrl technology ‐‐ LNB+OFA LNB+OFA+SNCR ROFA+Rotamix ROFA+Rota

1) Based on NDEP Reid‐Gardner BART Determination, October 22, 2009, Table 1. Heat input values appear to be based on 1.0 capacity factor

and 1152 MMBtu/hr

2) Baseline emissions and control option emissions based upon NDEP's October 22, 2009 BART determination, Table 1.

Based on NDEP baseline, which is higher than NVE submittal. By comparison, NVE's Unit 1 baseline was 1625 tpy NOx

Unit 1Unit 2Unit 3
Reid Gardner NOx Emission Estimates (Based upon NDEP Cost and Control Estimates)

Unit No. Annual Heat Input1

(MMBtu/yr)

Unit 1 9,818,313Unit 2 10,501,749Unit 3 10,063,851Unit No. Parameter Units Baseline2 LNB+OFA LNB+OFA+SNCR ROFA+Rotamix SCR+

Emission Rate (tpy) 2,267 1,784 1,340 959 

Removed (tpy) ‐‐ 483 927 1,308 1Removal Rate (%) ‐‐ 21.3% 40.9% 57.7% 8

Emission Factor (lb/MMBtu) 0.462 0.363 0.273 0.195 0

Annual Cost ($) $550,024 $1,130,186 $1,652,724 $4,7Average Cost Effectiveness3 ($/ton) $1,139 $1,219 $1,264 $

Incremental Cost Effectiveness3 ($/ton) ‐‐ $1,307 $1,371 $

Emission Rate (tpy) 2,445 1,866 1,401 1,003 

Removed (tpy) ‐‐ 579 1,044 1,442 2

Removal Rate (%) ‐‐ 23.7% 42.7% 59.0% 8

Emission Factor (lb/MMBtu) 0.466 0.355 0.267 0.191 0

Annual Cost ($) $550,024 $1,152,595 $1,700,533 $4,7Average Cost Effectiveness3 ($/ton) $950 $1,104 $1,179 $

Incremental Cost Effectiveness3 ($/ton) ‐‐ $1,296 $1,377 $

Emission Rate (tpy) 2,268 2,121 1,590 1,400 

Removed (tpy) ‐‐ 147 678 868 1

Removal Rate (%) ‐‐ 6.5% 29.9% 38.3% 7

Emission Factor (lb/MMBtu) 0.451 0.421 0.316 0.278 0

Annual Cost ($) $550,024 $1,079,908 $1,582,340 $4,7Average Cost Effectiveness3 ($/ton) $3,742 $1,593 $1,823 $

Incremental Cost Effectiveness3 ($/ton) ‐‐ $998 $2,644 $

1) As listed in NDEP Reid‐Gardner BART Determination, October 22, 2009, Table 1, "Base Heat Input."

Based on listed emission rates and emission factors, "base heat input" and not "total heat input" was used.

2) Baseline emissions and control option emissions based upon NDEP's October 22, 2009 BART determination, Table 1.

Based on NDEP baseline, which is higher than NVE submittal. By comparison, NVE's Unit 1 baseline was 1625 tpy NOx

3) Average and incremental cost effectiveness values as reported in NDEP's October 22, 2009 BART determination, Table 1.

Unit 1Unit 2Unit 3
Printed 4/2/2012

Control Cost Comparison - LNB+OFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Capital Costs

Low NOx Burners (Upgrade) + OFA/ROFA

Major Materials Design and Supply Construction 

$1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

this line item description suggests it includes more than just PEC. guidance on what constituent elements may be included in this linprovide sufficient detail to make more specific determinations.

Construction $1,120,000 70% $1,120,000 70% $1,120,000 $1,120,000 $1,120,000 $1,120,000 Vendor estimate. Comparable to Indirect installation costs as desc

guidance on what constituent elements are allowed in this line item

Balance of Plant $800,000 50% $800,000 50% $800,000 $800,000 $800,000 $800,000 Balance of plant is construed to refer to other capital expenditures 

the CCM, and are considered part of direct capital costs (DCC).

Electrical (Allowance) $80,000 5% $80,000 5% $80,000 $80,000 $80,000 $80,000 Electrical equipment is included in the EPA control cost manual a

are retained here without revision

Owner's Costs $160,000 10% $0 0% $160,000 $0 $160,000 $0 Owner's costs such as project management, advisory fees, legal, e

Manual. Although it is possible that certain CCM-allowed costs adetails would be needed to make that dete

Surcharge $256,000 16% $0 0% $256,000 $0 $256,000 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $192,000 12% $0 0% $192,000 $0 $192,000 $0 AFUDC is not allowed for any of the applications listed in the EP

Subtotal, LNB+OFA Capital Cost $4,208,000 $3,600,000 $4,208,000 $3,600,000 $4,208,000 $3,600,000Contingency $240,000 15% $240,000 15% $240,000 $240,000 $240,000 $240,000 EPA Control Cost Manual provides for project contingency costs 

costs (DCC) and indirect installation costs. 

Total LNB+OFA Capital Cost $4,448,000 $3,840,000 $4,448,000 $3,840,000 $4,448,000 $3,840,000

Total Capital Cost $4,448,000 $3,840,000 $4,448,000 $3,840,000 $4,448,000 $3,840,000

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

LNB+OFA

Page 4 of 13
Printed 4/2/2012

Control Cost Comparison - LNB+OFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $32,000 $32,000 $32,000 $32,000 $32,000 $32,000Maintenance Labor $48,000 $48,000 $48,000 $48,000 $48,000 $48,000Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $80,000 $80,000 $80,000 $80,000 $80,000 $80,000Variable Costs

Reagent $0 $0 $0 $0 $0 $0 EPA CCM does provide for certain raw material costs such as rea

Catalyst Replacement $0 $0 $0 $0 $0 $0 The EPA Control Cost Manual does provide for SCR catalyst repl

estimate is not clear, however, and it is difficult to determine how might compare.

Auxiliary Power $0 $0 $0 $0 $0 $0 The EPA Control Cost Manual does provide for utility costs, such 

equipment. 

Subtotal, variable costs $0 $0 $0 $0 $0 $0Debt Service/Capital Recovery1 $470,024 $362,469 $470,024 $362,469 $470,024 $362,469 Regarding interest rates, EPA calculated capital recoveries using 3

cost effectiveness for the Regulatory Impact Analysis for the FinaGuidelines for BART Determinations under the Regional Haze reuses 7% interest rate in SNCR example calculations (Section 4-2, also recommends a 20 year economic lifetime for SNCR (p1-37), specified in BART and BACT analyses.

Total Annual Costs $550,024 $442,469 $550,024 $442,469 $550,024 $442,469

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materialthe revised EPA estimate, although no basis was provided.

LNB+OFA

Page 5 of 13
Printed 4/2/2012

Control Cost Comparison - LNB+OFA+SNCR

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Capital Costs

Low NOx Burners (Upgrade) + OFA

Major Materials Design and Supply Construction 

$1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 Vendor estimate. Comparable to Purchased Equipment Cost (P

although this line item description suggests it includes more thamore detailed guidance on what constituent elements may be inNDEP appendix does not provide sufficient detail to make mor

Construction $1,120,000 70% $1,120,000 70% $1,120,000 $1,120,000 $1,120,000 $1,120,000 Vendor estimate. Comparable to Indirect installation costs as d

more detailed guidance on what constituent elements are allow

Balance of Plant $800,000 50% $800,000 50% $800,000 $800,000 $800,000 $800,000 Balance of plant is construed to refer to other capital expenditu

allowed in the CCM, and are considered part of direct capital c

Electrical (Allowance) $80,000 5% $80,000 5% $80,000 $80,000 $80,000 $80,000 Electrical equipment is included in the EPA control cost manua

(DCC), and so are retained here without revision

Owner's Costs $160,000 10% $0 0% $160,000 $0 $160,000 $0 Owner's costs such as project management, advisory fees, legal

Control Cost Manual. Although it is possible that certain CCM

line item, additional details would be needed to make that dete

Surcharge $256,000 16% $0 0% $256,000 $0 $256,000 $0 There is no provision for surcharge in the EPA Control Cost MAFUDC $192,000 12% $0 0% $192,000 $0 $192,000 $0 AFUDC is not allowed for any of the applications listed in the 

Subtotal, LNB+OFA Capital Cost $4,208,000 $3,600,000 $4,208,000 $3,600,000 $4,208,000 $3,600,000Contingency $240,000 15% $240,000 15% $240,000 $240,000 $240,000 $240,000 EPA Control Cost Manual provides for project contingency cos

direct capital costs (DCC) and indirect installation costs. 

Total LNB+OFA Capital Cost $4,448,000 $3,840,000 $4,448,000 $3,840,000 $4,448,000 $3,840,000Selective Non-Catalytic Reduction (SNCR)

Major Materials Design and Supply Construction 

$1,350,000 $1,350,000 $1,350,000 $1,350,000 $1,350,000 $1,350,000 Vendor estimate. Comparable to Purchased Equipment Cost (P

although this line item description suggests it includes more tha

Construction $202,500 OA b 15.0% $202,500 15% $202,500 $202,500 $202,500 $202,500

Balance of Plant $162,000 12.0% $162,000 12% $162,000 $162,000 $162,000 $162,000Electrical (Allowance) $67,500 5.0% $67,500 5% $67,500 $67,500 $67,500 $67,500

Owner's Costs $135,000 10.0% $0 0% $135,000 $0 $135,000 $0 Owner's costs such as project management, advisory fees, legal

Control Cost Manual. Although it is possible that certain CCM

line item, additional details would be needed to make that dete

Surcharge $216,000 16.0% $0 0% $216,000 $0 $216,000 $0 There is no provision for surcharge in the EPA Control Cost M

AFUDC $162,000 12.0% $0 0% $162,000 $0 $162,000 $0 AFUDC is not allowed for SCR in the EPA Control Cost Manu

Subtotal, SCR Capital Cost $2,295,000 $1,782,000 $2,295,000 $1,782,000 $2,295,000 $1,782,000Contingency $202,500 15% $202,500 15% $202,500 $202,500 $202,500 $202,500 EPA Control Cost Manual provides for project contingency cos

direct capital costs (DCC) and indirect installation costs. 

Total SNCR Capital Cost $2,497,500 $1,984,500 $2,497,500 $1,984,500 $2,497,500 $1,984,500

Total Capital Cost $6,945,500 $5,824,500 $6,945,500 $5,824,500 $6,945,500 $5,824,500

See comments in LNB+OFA section above. While these costs CCM line items, they are comparable to certain allowed costs. retained without revision. 

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

SNCR+LNB+OFA

Page 6 of 13
Printed 4/2/2012

Control Cost Comparison - LNB+OFA+SNCR

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $83,000 $83,000 $83,000 $83,000 $83,000 $83,000Maintenance Labor $124,500 $124,500 $124,500 $124,500 $124,500 $124,500

Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $207,500 $207,500 $207,500 $207,500 $207,500 $207,500Variable Costs

Reagent $151,080 $151,080 $169,985 $169,985 $98,612 $98,612 EPA CCM does provide for certain raw material costs such as rCatalyst Replacement $0 $0 $0 $0 $0 $0 The EPA Control Cost Manual does provide for SCR catalyst r

NDEP's estimate is not clear, however, and it is difficult to detedetermined using the CCM might compare.

Auxiliary Power $37,668 $37,668 $41,172 $41,172 $39,858 $39,858 The EPA Control Cost Manual does provide for utility costs, su

SCR equipment. 

Subtotal, variable costs $188,748 $188,748 $211,157 $211,157 $138,470 $138,470Debt Service/Capital Recovery1 $733,938 $549,792 $733,938 $549,792 $733,938 $549,792

Regarding interest rates, EPA calculated capital recoveries usindetermining cost effectiveness for the Regulatory Impact AnalyVisibility rule and the Guidelines for BART Determinations unThe EPA Control Cost Manual uses 7% interest rate in SNCR eChap 1, p1-37). In addition, the CCM also recommends a 20 y(p1-37), although 30 year lifetimes have often been specified in 

Total Annual Costs $1,130,186 $946,040 $1,152,595 $968,449 $1,079,908 $895,762

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materincluded in the revised EPA estimate, although no basis was pr

SNCR+LNB+OFA

Page 7 of 13
Printed 4/2/2012

Control Cost Comparison - ROFA+Rotami

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

C

NDEP EPA Revised 

C Value % Value % Comments

Capital Costs

Rotating Overfire Air (ROFA)

Major Materials Design and Supply Construction 

$2,880,000 $2,880,000 $2,880,000 $2,880,000 $2,880,000 $2,880,000 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

this line item description suggests it includes more than just PEC. guidance on what constituent elements may be included in this line provide sufficient detail to make more specific determinations.

Construction $742,500 $742,500 $742,500 $742,500 $742,500 $742,500 Vendor estimate. Comparable to Indirect installation costs as desc

detailed guidance on what constituent elements are allowed in this not provide sufficient detail to make this evaluation

Balance of Plant $1,440,000 50% $1,440,000 50% $1,440,000 $1,440,000 $1,440,000 $1,440,000 Balance of plant is construed to refer to other capital expenditures 

the CCM, and are considered part of direct capital costs (DCC).

Electrical (Allowance) $864,000 30% $864,000 30% $864,000 $864,000 $864,000 $864,000 Electrical equipment is included in the EPA control cost manual as 

so are retained here without revision

Owner's Costs $288,000 10% $0 0% $288,000 $0 $288,000 $0 Owner's costs such as project management, advisory fees, legal, etc

Manual. Although it is possible that certain CCM-allowed costs ardetails would be needed to make that determination.

Surcharge $460,800 16% $0 0% $460,800 $0 $460,800 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $345,600 12% $0 0% $345,600 $0 $345,600 $0 AFUDC is not allowed for any of the applications listed in the EPA 

Subtotal, ROFA Capital Cost $7,020,900 $5,926,500 $7,020,900 $5,926,500 $7,020,900 $5,926,500Contingency $864,000 30% $432,000 15% $864,000 $432,000 $864,000 $432,000 EPA Control Cost Manual provides for project contingency costs o

costs (DCC) and indirect installation costs. 

Total ROFA Capital Cost $7,884,900 $6,358,500 $7,884,900 $6,358,500 $7,884,900 $6,358,500Rotamix

Major Materials Design and Supply Construction 

$1,029,000 $1,029,000 $1,029,000 $1,029,000 $1,029,000 $1,029,000 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

this line item description suggests it includes more than just PEC. 

Construction $247,500 $247,500 $247,500 $247,500 $247,500 $247,500 Vendor estimate. Comparable to Indirect installation costs as desc

detailed guidance on what constituent elements are allowed in this not provide sufficient detail to make this evaluation

Balance of Plant $123,480 12.0% $123,480 12% $123,480 $123,480 $123,480 $123,480 Balance of plant is construed to refer to other capital expenditures 

the CCM, and are considered part of direct capital costs (DCC).

Electrical (Allowance) $0 0.0% $0 0% $0 $0 $0 $0 Zero estimate provided by NDEP. Based upon the documentation 

accounted for elsewhere

Owner's Costs $102,900 10.0% $0 0% $102,900 $0 $102,900 $0 Owner's costs such as project management, advisory fees, legal, etc

Manual. Although it is possible that certain CCM-allowed costs ardetails would be needed to make that determination.

Surcharge $164,640 16.0% $0 0% $164,640 $0 $164,640 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $123,480 12.0% $0 0% $123,480 $0 $123,480 $0 AFUDC is not allowed for SNCR (comparable to Rotamix) in the E

Subtotal, Rotamix Capital Cost $1,791,000 $1,399,980 $1,791,000 $1,399,980 $1,791,000 $1,399,980Contingency $154,350 15% $154,350 15% $154,350 $154,350 $154,350 $154,350 EPA Control Cost Manual provides for project contingency costs o

costs (DCC) and indirect installation costs. 

Total Rotamix Capital Cost $1,945,350 $1,554,330 $1,945,350 $1,554,330 $1,945,350 $1,554,330

Total Capital Cost $9,830,250 $7,912,830 $9,830,250 $7,912,830 $9,830,250 $7,912,830

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

ROFA+Rotamix

Page 8 of 13
Printed 4/2/2012

Control Cost Comparison - ROFA+Rotami

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

C

NDEP EPA Revised 

C Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $48,000 $48,000 $48,000 $48,000 $48,000 $48,000

Maintenance Labor $72,000 $72,000 $72,000 $72,000 $72,000 $72,000Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $120,000 $120,000 $120,000 $120,000 $120,000 $120,000Variable Costs

Reagent $213,062 $213,062 $234,741 $234,741 $126,347 $126,347 EPA CCM does provide for certain raw material costs such as reag

Catalyst Replacement $0 $0 $0 $0 $0 $0Auxiliary Power $280,890 $280,890 $307,020 $307,020 $297,221 $297,221 The EPA Control Cost Manual does provide for utility costs, such 

(comparable to Rotamix) equipment. 

Subtotal, variable costs $493,952 $493,952 $541,761 $541,761 $423,568 $423,568Debt Service/Capital Recovery1 $1,038,772 $746,915 $1,038,772 $746,915 $1,038,772 $746,915 Regarding interest rates, EPA calculated capital recoveries using 3

cost effectiveness for the Regulatory Impact Analysis for the Final Guidelines for BART Determinations under the Regional Haze reguses 7% interest rate in SNCR example calculations (Section 4-2, Calso recommends a 20 year economic lifetime for SNCR (p1-37), abeen specified in BART and BACT analyses.

Total Annual Costs $1,652,724 $1,360,867 $1,700,533 $1,408,676 $1,582,340 $1,290,483

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materials the revised EPA estimate, although no basis was provided.

ROFA+Rotamix

Page 9 of 13
Printed 4/2/2012

Control Cost Comparison - SCR+LNB+OFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Capital Costs

Low NOx Burners (Upgrade) + OFA

Major Materials Design and Supply Construction 

$1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 $1,600,000 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

although this line item description suggests it includes more than jdetailed guidance on what constituent elements may be included i

Construction $1,120,000 70% $1,120,000 70% $1,120,000 $1,120,000 $1,120,000 $1,120,000 Vendor estimate. Comparable to Indirect installation costs as desc

detailed guidance on what constituent elements are allowed in this 

Balance of Plant $800,000 50% $800,000 50% $800,000 $800,000 $800,000 $800,000 Balance of plant is construed to refer to other capital expenditures 

allowed in the CCM, and are considered part of direct capital cost

Electrical (Allowance) $80,000 5% $80,000 5% $80,000 $80,000 $80,000 $80,000 Electrical equipment is included in the EPA control cost manual a

and so are retained here without revision

Owner's Costs $160,000 10% $0 0% $160,000 $0 $160,000 $0 Owner's costs such as project management, advisory fees, legal, e

Cost Manual. Although it is possible that certain CCM-allowed cadditional details would be needed to make that dete

Surcharge $256,000 16% $0 0% $256,000 $0 $256,000 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $192,000 12% $0 0% $192,000 $0 $192,000 $0 AFUDC is not allowed for SCR in the EPA Control Cost Manual, 

Subtotal, LNB+OFA Capital Cost $4,208,000 $3,600,000 $4,208,000 $3,600,000 $4,208,000 $3,600,000Contingency $240,000 15% $240,000 15% $240,000 $240,000 $240,000 $240,000 EPA Control Cost Manual provides for project contingency costs 

capital costs (DCC) and indirect installation costs. 

Total ROFA Capital Cost $4,448,000 $3,840,000 $4,448,000 $3,840,000 $4,448,000 $3,840,000Selective Catalytic Reduction (SCR)

Major Materials Design and Supply Construction 

$20,000,000 $20,000,000 $20,000,000 $20,000,000 $20,000,000 $20,000,000 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

although this line item description suggests it includes more than j

b Construction $0 0.0% $0 0% $0 $0 $0 $0

Balance of Plant $0 0.0% $0 0% $0 $0 $0 $0Electrical (Allowance) $0 0.0% $0 0% $0 $0 $0 $0Owner's Costs $2,000,000 10.0% $0 0% $2,000,000 $0 $2,000,000 $0 Owner's costs such as project management, advisory fees, legal, e

Cost Manual. Although it is possible that certain CCM-allowed cadditional details would be needed to make that dete

Surcharge $3,200,000 16.0% $0 0% $3,200,000 $0 $3,200,000 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $2,400,000 12.0% $0 0% $2,400,000 $0 $2,400,000 $0 AFUDC is not allowed for SCR in the EPA Control Cost Manual

Subtotal, SCR Capital Cost $27,600,000 $20,000,000 $27,600,000 $20,000,000 $27,600,000 $20,000,000Contingency $3,000,000 15% $3,000,000 15% $3,000,000 $3,000,000 $3,000,000 $3,000,000 EPA Control Cost Manual provides for project contingency costs 

capital costs (DCC) and indirect installation costs. 

Total SCR Capital Cost $30,600,000 $23,000,000 $30,600,000 $23,000,000 $30,600,000 $23,000,000

Total Capital Cost $35,048,000 $26,840,000 $35,048,000 $26,840,000 $35,048,000 $26,840,000

Zero estimate provided by NDEP. Based upon the documentation are accounted for elsewhere

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

SCR+LNB+OFA

Page 10 of 13
Printed 4/2/2012

Control Cost Comparison - SCR+LNB+OFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $132,000 $132,000 $132,000 $132,000 $132,000 $132,000Maintenance Labor $198,000 $198,000 $198,000 $198,000 $198,000 $198,000Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $330,000 $330,000 $330,000 $330,000 $330,000 $330,000Variable Costs

Reagent $301,192 $301,192 $326,816 $326,816 $257,830 $257,830 EPA CCM does provide for certain raw material costs such as rea

Catalyst Replacement $150,000 $150,000 $150,000 $150,000 $150,000 $150,000 The EPA Control Cost Manual does provide for SCR catalyst repl

NDEP's estimate is not clear, however, and it is difficult to determusing the CCM might compare.

Auxiliary Power $248,609 $248,609 $271,735 $271,735 $263,063 $263,063 The EPA Control Cost Manual does provide for utility costs, such 

equipment. 

Subtotal, variable costs $699,801 $699,801 $748,551 $748,551 $670,893 $670,893Debt Service/Capital Recovery1 $3,703,556 $2,533,506 $3,703,556 $2,533,506 $3,703,556 $2,533,506 Regarding interest rates, EPA calculated capital recoveries using 3

determining cost effectiveness for the Regulatory Impact Analysis rule and the Guidelines for BART Determinations under the RegioControl Cost Manual uses 7% interest rate in SCR example calculIn addition, the CCM also recommends a 20 year economic lifetimlifetimes have often been specified in BART and BACT analyses.

Total Annual Costs $4,733,357 $3,563,307 $4,782,107 $3,612,057 $4,704,449 $3,534,399

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materialincluded in the revised EPA estimate, although no basis was provi

SCR+LNB+OFA

Page 11 of 13
Printed 4/2/2012

Control Cost Comparison - SCR+ROFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Capital Costs

Rotating Overfire Air (ROFA)

Major Materials Design and Supply Construction 

$2,880,000 $2,880,000 $2,880,000 $2,880,000 $2,880,000 $2,880,000 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

although this line item description suggests it includes more than jdetailed guidance on what constituent elements may be included iappendix does not provide sufficient detail to make more specific 

Construction $742,500 $742,500 $742,500 $742,500 $742,500 $742,500 Vendor estimate. Comparable to Indirect installation costs as desc

detailed guidance on what constituent elements are allowed in this does not provide sufficient detail to make this evaluation

Balance of Plant $1,440,000 50% $1,440,000 50% $1,440,000 $1,440,000 $1,440,000 $1,440,000 Balance of plant is construed to refer to other capital expenditures 

in the CCM, and are considered part of direct capital costs (DCC)

Electrical (Allowance) $864,000 30% $864,000 30% $864,000 $864,000 $864,000 $864,000 Electrical equipment is included in the EPA control cost manual a

and so are retained here without revision

Owner's Costs $288,000 10% $0 0% $288,000 $0 $288,000 $0 Owner's costs such as project management, advisory fees, legal, e

Cost Manual. Although it is possible that certain CCM-allowed cadditional details would be needed to make that determination.

Surcharge $460,800 16% $0 0% $460,800 $0 $460,800 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $345,600 12% $0 0% $345,600 $0 $345,600 $0 AFUDC is not allowed for any of the applications listed in the EP

Subtotal, ROFA Capital Cost $7,020,900 $5,926,500 $7,020,900 $5,926,500 $7,020,900 $5,926,500Contingency $864,000 30% $432,000 15% $864,000 $432,000 $864,000 $432,000 EPA Control Cost Manual provides for project contingency costs 

capital costs (DCC) and indirect installation costs. 

Total ROFA Capital Cost $7,884,900 $6,358,500 $7,884,900 $6,358,500 $7,884,900 $6,358,500Selective Catalytic Reduction (SCR)

Major Materials Design and Supply Construction 

$20,000,000 $20,000,000 $20,000,000 $20,000,000 $20,000,000 $20,000,000 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

although this line item description suggests it includes more than j

b Construction $0 0.0% $0 0% $0 $0 $0 $0

Balance of Plant $0 0.0% $0 0% $0 $0 $0 $0Electrical (Allowance) $0 0.0% $0 0% $0 $0 $0 $0Owner's Costs $2,000,000 10.0% $0 0% $2,000,000 $0 $2,000,000 $0 Owner's costs such as project management, advisory fees, legal, e

Cost Manual. Although it is possible that certain CCM-allowed cadditional details would be needed to make that determination.

Surcharge $3,200,000 16.0% $0 0% $3,200,000 $0 $3,200,000 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $2,400,000 12.0% $0 0% $2,400,000 $0 $2,400,000 $0 AFUDC is not allowed for SCR in the EPA Control Cost Manual, 

Subtotal, SCR Capital Cost $27,600,000 $20,000,000 $27,600,000 $20,000,000 $27,600,000 $20,000,000Contingency $3,000,000 15% $3,000,000 15% $3,000,000 $3,000,000 $3,000,000 $3,000,000 EPA Control Cost Manual provides for project contingency costs 

capital costs (DCC) and indirect installation costs. 

Total SCR Capital Cost $30,600,000 $23,000,000 $30,600,000 $23,000,000 $30,600,000 $23,000,000

Total Capital Cost $38,484,900 $29,358,500 $38,484,900 $29,358,500 $38,484,900 $29,358,500

Zero estimate provided by NDEP. Based upon the documentation are accounted for elsewhere

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

SCR+ROFA

Page 12 of 13
Printed 4/2/2012

Control Cost Comparison - SCR+ROFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $148,000 $148,000 $148,000 $148,000 $148,000 $148,000Maintenance Labor $222,000 $222,000 $222,000 $222,000 $222,000 $222,000Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $370,000 $370,000 $370,000 $370,000 $370,000 $370,000Variable Costs

Reagent $301,192 $301,192 $326,816 $326,816 $257,830 $257,830 EPA CCM does provide for certain raw material costs such as rea

Catalyst Replacement $112,500 $112,500 $112,500 $112,500 $132,000 $132,000 The EPA Control Cost Manual does provide for SCR catalyst repl

estimate is not clear, however, and it is difficult to determine how CCM might compare.

Auxiliary Power $529,500 $529,500 $578,755 $578,755 $560,284 $560,284 The EPA Control Cost Manual does provide for utility costs, such 

equipment. 

Subtotal, variable costs $943,192 $943,192 $1,018,071 $1,018,071 $950,114 $950,114Debt Service/Capital Recovery1 $4,066,737 $2,771,235 $4,066,737 $2,771,235 $4,066,737 $2,771,235 Regarding interest rates, EPA calculated capital recoveries using 3

determining cost effectiveness for the Regulatory Impact Analysis and the Guidelines for BART Determinations under the Regional Cost Manual uses 7% interest rate in SCR example calculations (Saddition, the CCM also recommends a 20 year economic lifetime lifetimes have often been specified in BART and BACT analyses.

Total Annual Costs $5,379,929 $4,084,427 $5,454,808 $4,159,306 $5,386,851 $4,091,349

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materialin the revised EPA estimate, although no basis was provided.

SCR+ROFA

Page 13 of 13
Page 37 of 40

Appendix B:

EPA Analysis of NOx Control Cost Estimates (2011 update) for Reid Gardner Generating 

Station

See www.regulations.gov, docket ID number EPA-R09-OAR-2011-0130
Printed 4/2/2012

Comparison of SCR Control Costs (Updated, 2011)

Parameter

NDEP Revised EPA NDEP Revised EPA NDEP Revised EPA

Unit Output (kW)

Heat Input (MMBtu/hr)

Boiler Type

Ctrl technologyCtrl Emission Rate (lb/MMBtu) 0.085 0.085 0.083 0.083 0.098 0.098

Total Capital Costs $39,754,076 $30,443,946 $39,754,076 $30,443,946 $39,754,076 $30,443,946

Total Annual Costs

Fixed Costs $330,000 $330,000 $330,000 $330,000 $330,000 $330,000Variable Costs $699,801 $699,801 $748,551 $748,551 $670,893 $670,893

Capital Recovery $4,200,852 $2,873,693 $4,200,852 $2,873,693 $4,200,852 $2,873,693

20 yrs @ 8.5% 20 yrs @ 7.0% 20 yrs @ 8.5% 20 yrs @ 7% 20 yrs @ 8.5% 20 yrs @ 7%

Total Annual Costs $5,230,653 $3,903,494 $5,279,403 $3,952,244 $5,201,745 $3,874,586

NOx Removed from baseline (tpy) 1,850 1,850 2,010 2,009 1,774 1,775

Average Cost per ton ($/ton) $2,827 $2,110 $2,627 $1,967 $2,932 $2,183

Incremental Cost per ton ($/ton) $6,370 $4,534 $6,080 $4,330 $3,856 $2,756

Previous ctrl technology ROFA+Rotamix ROFA+Rotamix ROFA+Rotamix

SCR+LNB+OFA SCR+LNB+OFA SCR+LNB+OFA

Reid Gardner

Unit 2 Unit 3

Wall‐fired Wall‐fired Wall‐fired

1132 1132

100,000

1132

100,000 100,000

Unit 1

SCR Cost Comparisons

Page 1 of 13
Reid Gardner NOx Control Effectiveness Summary ‐ EPA Revised Costs

Unit No. Annual Heat Input1

(MMBtu/yr)

Unit 1 9,818,313Unit 2 10,501,749Unit 3 10,063,851

Unit No. Parameter Units Baseline2 LNB+OFA LNB+OFA+SNCR ROFA+Rotamix SCR+LNB+OFA SCR+ROF

Emission Rate (tpy) 2,267 1,784 1,340 959 417 417

Removed (tpy) ‐‐ 483 927 1,308 1,850 1,850Removal Rate (%) ‐‐ 21.3% 40.9% 57.7% 81.6% 81.6%

Emission Factor (lb/MMBtu) 0.462 0.363 0.273 0.195 0.085 0.085

Annual Cost ($) $491,140 $1,019,864 $1,448,604 $3,903,494 $4,447,12

Average Cost Effectiveness ($/ton) $1,017 $1,100 $1,107 $2,110 $2,404

Incremental Cost Effectiveness ($/ton) ‐‐ $1,191 $1,124 $4,534 $5,538

Previous ctrl technology ‐‐ LNB+OFA LNB+OFA+SNCR ROFA+Rotamix ROFA+Rota

Emission Rate (tpy) 2,445 1,866 1,401 1,003 436 436

Removed (tpy) ‐‐ 579 1,044 1,442 2,009 2,009

Removal Rate (%) ‐‐ 23.7% 42.7% 59.0% 82.2% 82.2%

Emission Factor (lb/MMBtu) 0.466 0.355 0.267 0.191 0.083 0.083

Annual Cost ($) $491,140 $1,042,273 $1,496,413 $3,952,244 $4,522,00

Average Cost Effectiveness ($/ton) $848 $998 $1,038 $1,967 $2,251

Incremental Cost Effectiveness ($/ton) ‐‐ $1,185 $1,141 $4,330 $5,334

Previous ctrl technology ‐‐ LNB+OFA LNB+OFA+SNCR ROFA+Rotamix ROFA+Rota

Emission Rate (tpy) 2,268 2,118 1,590 1,399 493 493

Removed (tpy) ‐‐ 150 678 869 1,775 1,775

Removal Rate (%) ‐‐ 7% 30% 38% 78% 78%

Emission Factor (lb/MMBtu) 0.451 0.421 0.316 0.278 0.098 0.098

Annual Cost ($) $491,140 $969,586 $1,378,220 $3,874,586 $4,454,04

Average Cost Effectiveness ($/ton) $3,284 $1,430 $1,586 $2,183 $2,510

Incremental Cost Effectiveness ($/ton) ‐‐ $906 $2,137 $2,756 $3,396

Previous ctrl technology ‐‐ LNB+OFA LNB+OFA+SNCR ROFA+Rotamix ROFA+Rota

1) Based on NDEP Reid‐Gardner BART Determination, October 22, 2009, Table 1. Heat input values appear to be based on 1.0 capacity factor

and 1152 MMBtu/hr

2) Baseline emissions and control option emissions based upon NDEP's October 22, 2009 BART determination, Table 1.

Based on NDEP baseline, which is higher than NVE submittal. By comparison, NVE's Unit 1 baseline was 1625 tpy NOx

Unit 1Unit 2Unit 3
Reid Gardner NOx Emission Estimates (Based upon NDEP Cost and Control Estimates)

Unit No. Annual Heat Input1

(MMBtu/yr)

Unit 1 9,818,313Unit 2 10,501,749Unit 3 10,063,851Unit No. Parameter Units Baseline2 LNB+OFA LNB+OFA+SNCR ROFA+Rotamix SCR+

Emission Rate (tpy) 2,267 1,784 1,340 959 

Removed (tpy) ‐‐ 483 927 1,308 1Removal Rate (%) ‐‐ 21.3% 40.9% 57.7% 8

Emission Factor (lb/MMBtu) 0.462 0.363 0.273 0.195 0

Annual Cost ($) $613,138 $1,228,736 $1,778,147 $5,Average Cost Effectiveness3 ($/ton) $1,269 $1,325 $1,359 $

Incremental Cost Effectiveness3 ($/ton) ‐‐ $1,386 $1,442 $

Emission Rate (tpy) 2,445 1,866 1,401 1,003 

Removed (tpy) ‐‐ 579 1,044 1,442 2

Removal Rate (%) ‐‐ 23.7% 42.7% 59.0% 8

Emission Factor (lb/MMBtu) 0.466 0.355 0.267 0.191 0

Annual Cost ($) $613,138 $1,251,145 $1,825,956 $5,Average Cost Effectiveness3 ($/ton) $1,059 $1,198 $1,266 $

Incremental Cost Effectiveness3 ($/ton) ‐‐ $1,372 $1,444 $

Emission Rate (tpy) 2,268 2,121 1,590 1,400 

Removed (tpy) ‐‐ 147 678 868 1

Removal Rate (%) ‐‐ 6.5% 29.9% 38.3% 7

Emission Factor (lb/MMBtu) 0.451 0.421 0.316 0.278 0

Annual Cost ($) $613,138 $1,178,458 $1,707,763 $5,Average Cost Effectiveness3 ($/ton) $4,171 $1,738 $1,967 $

Incremental Cost Effectiveness3 ($/ton) ‐‐ $1,065 $2,786 $

1) As listed in NDEP Reid‐Gardner BART Determination, October 22, 2009, Table 1, "Base Heat Input."

Based on listed emission rates and emission factors, "base heat input" and not "total heat input" was used.

2) Baseline emissions and control option emissions based upon NDEP's October 22, 2009 BART determination, Table 1.

Based on NDEP baseline, which is higher than NVE submittal. By comparison, NVE's Unit 1 baseline was 1625 tpy NOx

3) Average and incremental cost effectiveness values as reported in NDEP's October 22, 2009 BART determination, Table 1.

Unit 1Unit 2Unit 3
Printed 4/2/2012

Control Cost Comparison - LNB+OFA (enhanced)

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Capital Costs

Low NOx Burners (Upgrade) + OFA/ROFA

Major Materials Design and Supply Construction 

$1,814,842 $1,814,842 $1,814,842 $1,814,842 $1,814,842 $1,814,842 Vendor estimate. Comparable to Purchased Equipment Cost (P

although this line item description suggests it includes more thadetailed guidance on what constituent elements may be includeappendix does not provide sufficient detail to make more specif

Construction $1,270,389 70% $1,270,389 70% $1,270,389 $1,270,389 $1,270,389 $1,270,389 Vendor estimate. Comparable to Indirect installation costs as d

detailed guidance on what constituent elements are allowed in t

Balance of Plant $907,421 50% $907,421 50% $907,421 $907,421 $907,421 $907,421 Balance of plant is construed to refer to other capital expenditu

in the CCM, and are considered part of direct capital costs (DC

Electrical (Allowance) $90,742 5% $90,742 5% $90,742 $90,742 $90,742 $90,742 Electrical equipment is included in the EPA control cost manua

and so are retained here without revision

Owner's Costs $181,484 10% $0 0% $181,484 $0 $181,484 $0 Owner's costs such as project management, advisory fees, legal

Cost Manual. Although it is possible that certain CCM-allowed additional details would be needed to make that dete

Surcharge $290,375 16% $0 0% $290,375 $0 $290,375 $0 There is no provision for surcharge in the EPA Control Cost MAFUDC $217,781 12% $0 0% $217,781 $0 $217,781 $0 AFUDC is not allowed for any of the applications listed in the 

Subtotal, LNB+OFA Capital Cost $4,773,034 $4,083,395 $4,773,034 $4,083,395 $4,773,034 $4,083,395Contingency $272,226 15% $272,226 15% $272,226 $272,226 $272,226 $272,226 EPA Control Cost Manual provides for project contingency cos

capital costs (DCC) and indirect installation costs. For examplTables 1.4 and 2.5 allow a project contingency of 15% for SNC

Total LNB+OFA Capital Cost $5,045,261 $4,355,621 $5,045,261 $4,355,621 $5,045,261 $4,355,621

Total Capital Cost $5,045,261 $4,355,621 $5,045,261 $4,355,621 $5,045,261 $4,355,621

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

LNB+OFA

Page 4 of 13
Printed 4/2/2012

Control Cost Comparison - LNB+OFA (enhanced)

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $32,000 $32,000 $32,000 $32,000 $32,000 $32,000Maintenance Labor $48,000 $48,000 $48,000 $48,000 $48,000 $48,000Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $80,000 $80,000 $80,000 $80,000 $80,000 $80,000Variable Costs

Reagent $0 $0 $0 $0 $0 $0 EPA CCM does provide for certain raw material costs such as rCatalyst Replacement $0 $0 $0 $0 $0 $0 The EPA Control Cost Manual does provide for SCR catalyst r

estimate is not clear, however, and it is difficult to determine hoCCM might compare.

Auxiliary Power $0 $0 $0 $0 $0 $0 The EPA Control Cost Manual does provide for utility costs, su

equipment. 

Subtotal, variable costs $0 $0 $0 $0 $0 $0Debt Service/Capital Recovery1 $533,138 $411,140 $533,138 $411,140 $533,138 $411,140 Regarding interest rates, EPA calculated capital recoveries usin

determining cost effectiveness for the Regulatory Impact Analyand the Guidelines for BART Determinations under the RegionCost Manual uses 7% interest rate in SNCR example calculatioaddition, the CCM also recommends a 20 year economic lifetimlifetimes have often been specified in BART and BACT analys

Total Annual Costs $613,138 $491,140 $613,138 $491,140 $613,138 $491,140

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materin the revised EPA estimate, although no basis was provided.

LNB+OFA

Page 5 of 13
Printed 4/2/2012

Control Cost Comparison - LNB+OFA+SNCR

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Capital Costs

Low NOx Burners (Upgrade) + OFA

Major Materials Design and Supply Construction 

$1,814,842 $1,814,842 $1,814,842 $1,814,842 $1,814,842 $1,814,842 Vendor estimate. Comparable to Purchased Equipment Cost (P

although this line item description suggests it includes more thamore detailed guidance on what constituent elements may be inNDEP appendix does not provide sufficient detail to make mor

Construction $1,270,389 70% $1,270,389 70% $1,270,389 $1,270,389 $1,270,389 $1,270,389 Vendor estimate. Comparable to Indirect installation costs as d

more detailed guidance on what constituent elements are allow

Balance of Plant $907,421 50% $907,421 50% $907,421 $907,421 $907,421 $907,421 Balance of plant is construed to refer to other capital expenditu

allowed in the CCM, and are considered part of direct capital c

Electrical (Allowance) $90,742 5% $90,742 5% $90,742 $90,742 $90,742 $90,742 Electrical equipment is included in the EPA control cost manua

(DCC), and so are retained here without revision

Owner's Costs $181,484 10% $0 0% $181,484 $0 $181,484 $0 Owner's costs such as project management, advisory fees, legal

Control Cost Manual. Although it is possible that certain CCM

line item, additional details would be needed to make that dete

Surcharge $290,375 16% $0 0% $290,375 $0 $290,375 $0 There is no provision for surcharge in the EPA Control Cost MAFUDC $217,781 12% $0 0% $217,781 $0 $217,781 $0 AFUDC is not allowed for any of the applications listed in the 

Subtotal, LNB+OFA Capital Cost $4,773,034 $4,083,395 $4,773,034 $4,083,395 $4,773,034 $4,083,395Contingency $272,226 15% $272,226 15% $272,226 $272,226 $272,226 $272,226 EPA Control Cost Manual provides for project contingency cos

direct capital costs (DCC) and indirect installation costs. For eCombustion), Tables 1.4 and 2.5 allow a project contingency o

Total LNB+OFA Capital Cost $5,045,261 $4,355,621 $5,045,261 $4,355,621 $5,045,261 $4,355,621Selective Non-Catalytic Reduction (SNCR)

Major Materials Design and Supply Construction 

$1,531,273 $1,531,273 $1,531,273 $1,531,273 $1,531,273 $1,531,273 Vendor estimate. Comparable to Purchased Equipment Cost (P

although this line item description suggests it includes more tha

Construction $229,691 OA b 15.0% $229,691 15% $229,691 $229,691 $229,691 $229,691

Balance of Plant $183,753 12.0% $183,753 12% $183,753 $183,753 $183,753 $183,753Electrical (Allowance) $76,564 5.0% $76,564 5% $76,564 $76,564 $76,564 $76,564

Owner's Costs $153,127 10.0% $0 0% $153,127 $0 $153,127 $0 Owner's costs such as project management, advisory fees, legal

Control Cost Manual. Although it is possible that certain CCM

line item, additional details would be needed to make that dete

Surcharge $245,004 16.0% $0 0% $245,004 $0 $245,004 $0 There is no provision for surcharge in the EPA Control Cost M

AFUDC $183,753 12.0% $0 0% $183,753 $0 $183,753 $0 AFUDC is not allowed for SCR in the EPA Control Cost Manu

Subtotal, SCR Capital Cost $2,603,164 $2,021,280 $2,603,164 $2,021,280 $2,603,164 $2,021,280Contingency $229,691 15% $229,691 15% $229,691 $229,691 $229,691 $229,691 EPA Control Cost Manual provides for project contingency cos

direct capital costs (DCC) and indirect installation costs. For eCombustion), Tables 1.4 and 2.5 allow a project contingency oapplications.

Total SNCR Capital Cost $2,832,855 $2,250,971 $2,832,855 $2,250,971 $2,832,855 $2,250,971

Total Capital Cost $7,878,116 $6,606,592 $7,878,116 $6,606,592 $7,878,116 $6,606,592

See comments in LNB+OFA section above. While these costs CCM line items, they are comparable to certain allowed costs. retained without revision. 

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

SNCR+LNB+OFA

Page 6 of 13
Printed 4/2/2012

Control Cost Comparison - LNB+OFA+SNCR

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $83,000 $83,000 $83,000 $83,000 $83,000 $83,000Maintenance Labor $124,500 $124,500 $124,500 $124,500 $124,500 $124,500

Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $207,500 $207,500 $207,500 $207,500 $207,500 $207,500Variable Costs

Reagent $151,080 $151,080 $169,985 $169,985 $98,612 $98,612 EPA CCM does provide for certain raw material costs such as rCatalyst Replacement $0 $0 $0 $0 $0 $0 The EPA Control Cost Manual does provide for SCR catalyst r

NDEP's estimate is not clear, however, and it is difficult to detedetermined using the CCM might compare.

Auxiliary Power $37,668 $37,668 $41,172 $41,172 $39,858 $39,858 The EPA Control Cost Manual does provide for utility costs, su

SCR equipment. 

Subtotal, variable costs $188,748 $188,748 $211,157 $211,157 $138,470 $138,470Debt Service/Capital Recovery1 $832,488 $623,616 $832,488 $623,616 $832,488 $623,616

Regarding interest rates, EPA calculated capital recoveries usindetermining cost effectiveness for the Regulatory Impact AnalyVisibility rule and the Guidelines for BART Determinations unThe EPA Control Cost Manual uses 7% interest rate in SNCR eChap 1, p1-37). In addition, the CCM also recommends a 20 y(p1-37), although 30 year lifetimes have often been specified in 

Total Annual Costs $1,228,736 $1,019,864 $1,251,145 $1,042,273 $1,178,458 $969,586

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materincluded in the revised EPA estimate, although no basis was pr

SNCR+LNB+OFA

Page 7 of 13
Printed 4/2/2012

Control Cost Comparison - ROFA+Rotami

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

C

NDEP EPA Revised 

C Value % Value % Comments

Capital Costs

Rotating Overfire Air (ROFA)

Major Materials Design and Supply Construction 

$3,266,715 $3,266,715 $3,266,715 $3,266,715 $3,266,715 $3,266,715 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

this line item description suggests it includes more than just PEC. guidance on what constituent elements may be included in this line provide sufficient detail to make more specific determinations.

Construction $742,500 $742,500 $742,500 $742,500 $742,500 $742,500 Vendor estimate. Comparable to Indirect installation costs as desc

detailed guidance on what constituent elements are allowed in this not provide sufficient detail to make this evaluation

Balance of Plant $1,633,358 50% $1,633,358 50% $1,633,358 $1,633,358 $1,633,358 $1,633,358 Balance of plant is construed to refer to other capital expenditures 

the CCM, and are considered part of direct capital costs (DCC).

Electrical (Allowance) $980,015 30% $980,015 30% $980,015 $980,015 $980,015 $980,015 Electrical equipment is included in the EPA control cost manual as 

so are retained here without revision

Owner's Costs $326,672 10% $0 0% $326,672 $0 $326,672 $0 Owner's costs such as project management, advisory fees, legal, etc

Manual. Although it is possible that certain CCM-allowed costs ardetails would be needed to make that determination.

Surcharge $522,674 16% $0 0% $522,674 $0 $522,674 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $392,006 12% $0 0% $392,006 $0 $392,006 $0 AFUDC is not allowed for any of the applications listed in the EPA 

Subtotal, ROFA Capital Cost $7,863,939 $6,622,587 $7,863,939 $6,622,587 $7,863,939 $6,622,587Contingency $980,015 30% $490,007 15% $980,015 $490,007 $980,015 $490,007 EPA Control Cost Manual provides for project contingency costs o

costs (DCC) and indirect installation costs. For example, Section 4and 2.5 allow a project contingency of 15% for SNCR and SCR ap

Total ROFA Capital Cost $8,843,953 $7,112,594 $8,843,953 $7,112,594 $8,843,953 $7,112,594Rotamix

Major Materials Design and Supply Construction 

$1,167,100 $1,167,100 $1,167,100 $1,167,100 $1,167,100 $1,167,100 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

this line item description suggests it includes more than just PEC. 

Construction $247,500 $247,500 $247,500 $247,500 $247,500 $247,500 Vendor estimate. Comparable to Indirect installation costs as desc

detailed guidance on what constituent elements are allowed in this not provide sufficient detail to make this evaluation

Balance of Plant $140,052 12.0% $140,052 12% $140,052 $140,052 $140,052 $140,052 Balance of plant is construed to refer to other capital expenditures 

the CCM, and are considered part of direct capital costs (DCC).

Electrical (Allowance) $0 0.0% $0 0% $0 $0 $0 $0 Zero estimate provided by NDEP. Based upon the documentation 

accounted for elsewhere

Owner's Costs $116,710 10.0% $0 0% $116,710 $0 $116,710 $0 Owner's costs such as project management, advisory fees, legal, etc

Manual. Although it is possible that certain CCM-allowed costs ardetails would be needed to make that determination.

Surcharge $186,736 16.0% $0 0% $186,736 $0 $186,736 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $140,052 12.0% $0 0% $140,052 $0 $140,052 $0 AFUDC is not allowed for SNCR (comparable to Rotamix) in the E

Subtotal, Rotamix Capital Cost $1,998,150 $1,554,652 $1,998,150 $1,554,652 $1,998,150 $1,554,652Contingency $175,065 15% $175,065 15% $175,065 $175,065 $175,065 $175,065 EPA Control Cost Manual provides for project contingency costs o

costs (DCC) and indirect installation costs. For example, Section 4and 2.5 allow a project contingency of 15% for SNCR and SCR ap

Total Rotamix Capital Cost $2,173,215 $1,729,717 $2,173,215 $1,729,717 $2,173,215 $1,729,717

Total Capital Cost $11,017,168 $8,842,311 $11,017,168 $8,842,311 $11,017,168 $8,842,311

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

ROFA+Rotamix

Page 8 of 13
Printed 4/2/2012

Control Cost Comparison - ROFA+Rotami

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

C

NDEP EPA Revised 

C Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $48,000 $48,000 $48,000 $48,000 $48,000 $48,000

Maintenance Labor $72,000 $72,000 $72,000 $72,000 $72,000 $72,000Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $120,000 $120,000 $120,000 $120,000 $120,000 $120,000Variable Costs

Reagent $213,062 $213,062 $234,741 $234,741 $126,347 $126,347 EPA CCM does provide for certain raw material costs such as reag

Catalyst Replacement $0 $0 $0 $0 $0 $0Auxiliary Power $280,890 $280,890 $307,020 $307,020 $297,221 $297,221 The EPA Control Cost Manual does provide for utility costs, such 

(comparable to Rotamix) equipment. 

Subtotal, variable costs $493,952 $493,952 $541,761 $541,761 $423,568 $423,568Debt Service/Capital Recovery1 $1,164,195 $834,652 $1,164,195 $834,652 $1,164,195 $834,652 Regarding interest rates, EPA calculated capital recoveries using 3

cost effectiveness for the Regulatory Impact Analysis for the Final Guidelines for BART Determinations under the Regional Haze reguses 7% interest rate in SNCR example calculations (Section 4-2, Calso recommends a 20 year economic lifetime for SNCR (p1-37), abeen specified in BART and BACT analyses.

Total Annual Costs $1,778,147 $1,448,604 $1,825,956 $1,496,413 $1,707,763 $1,378,220

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materials the revised EPA estimate, although no basis was provided.

ROFA+Rotamix

Page 9 of 13
Printed 4/2/2012

Control Cost Comparison - SCR+LNB+OFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Capital Costs

Low NOx Burners (Upgrade) + OFA

Major Materials Design and Supply Construction 

$1,814,842 $1,814,842 $1,814,842 $1,814,842 $1,814,842 $1,814,842 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

although this line item description suggests it includes more than jdetailed guidance on what constituent elements may be included i

Construction $1,270,389 70% $1,270,389 70% $1,270,389 $1,270,389 $1,270,389 $1,270,389 Vendor estimate. Comparable to Indirect installation costs as desc

detailed guidance on what constituent elements are allowed in this 

Balance of Plant $907,421 50% $907,421 50% $907,421 $907,421 $907,421 $907,421 Balance of plant is construed to refer to other capital expenditures 

allowed in the CCM, and are considered part of direct capital cost

Electrical (Allowance) $90,742 5% $90,742 5% $90,742 $90,742 $90,742 $90,742 Electrical equipment is included in the EPA control cost manual a

and so are retained here without revision

Owner's Costs $181,484 10% $0 0% $181,484 $0 $181,484 $0 Owner's costs such as project management, advisory fees, legal, e

Cost Manual. Although it is possible that certain CCM-allowed cadditional details would be needed to make that dete

Surcharge $290,375 16% $0 0% $290,375 $0 $290,375 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $217,781 12% $0 0% $217,781 $0 $217,781 $0 AFUDC is not allowed for SCR in the EPA Control Cost Manual, 

Subtotal, LNB+OFA Capital Cost $4,773,034 $4,083,395 $4,773,034 $4,083,395 $4,773,034 $4,083,395Contingency $272,226 15% $272,226 15% $272,226 $272,226 $272,226 $272,226 EPA Control Cost Manual provides for project contingency costs 

capital costs (DCC) and indirect installation costs. For example, STables 1.4 and 2.5 allow a project contingency of 15% for SNCR 

Total ROFA Capital Cost $5,045,261 $4,355,621 $5,045,261 $4,355,621 $5,045,261 $4,355,621Selective Catalytic Reduction (SCR)

Major Materials Design and Supply Construction 

$22,685,500 $22,685,500 $22,685,500 $22,685,500 $22,685,500 $22,685,500 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

although this line item description suggests it includes more than j

b Construction $0 0.0% $0 0% $0 $0 $0 $0

Balance of Plant $0 0.0% $0 0% $0 $0 $0 $0Electrical (Allowance) $0 0.0% $0 0% $0 $0 $0 $0Owner's Costs $2,268,550 10.0% $0 0% $2,268,550 $0 $2,268,550 $0 Owner's costs such as project management, advisory fees, legal, e

Cost Manual. Although it is possible that certain CCM-allowed cadditional details would be needed to make that dete

Surcharge $3,629,680 16.0% $0 0% $3,629,680 $0 $3,629,680 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $2,722,260 12.0% $0 0% $2,722,260 $0 $2,722,260 $0 AFUDC is not allowed for SCR in the EPA Control Cost Manual

Subtotal, SCR Capital Cost $31,305,990 $22,685,500 $31,305,990 $22,685,500 $31,305,990 $22,685,500Contingency $3,402,825 15% $3,402,825 15% $3,402,825 $3,402,825 $3,402,825 $3,402,825 EPA Control Cost Manual provides for project contingency costs 

capital costs (DCC) and indirect installation costs. For example, STables 1.4 and 2.5 allow a project contingency of 15% for SNCR 

Total SCR Capital Cost $34,708,815 $26,088,325 $34,708,815 $26,088,325 $34,708,815 $26,088,325

Total Capital Cost $39,754,076 $30,443,946 $39,754,076 $30,443,946 $39,754,076 $30,443,946

Zero estimate provided by NDEP. Based upon the documentation are accounted for elsewhere

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

SCR+LNB+OFA

Page 10 of 13
Printed 4/2/2012

Control Cost Comparison - SCR+LNB+OFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $132,000 $132,000 $132,000 $132,000 $132,000 $132,000Maintenance Labor $198,000 $198,000 $198,000 $198,000 $198,000 $198,000Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $330,000 $330,000 $330,000 $330,000 $330,000 $330,000Variable Costs

Reagent $301,192 $301,192 $326,816 $326,816 $257,830 $257,830 EPA CCM does provide for certain raw material costs such as rea

Catalyst Replacement $150,000 $150,000 $150,000 $150,000 $150,000 $150,000 The EPA Control Cost Manual does provide for SCR catalyst repl

NDEP's estimate is not clear, however, and it is difficult to determusing the CCM might compare.

Auxiliary Power $248,609 $248,609 $271,735 $271,735 $263,063 $263,063 The EPA Control Cost Manual does provide for utility costs, such 

equipment. 

Subtotal, variable costs $699,801 $699,801 $748,551 $748,551 $670,893 $670,893Debt Service/Capital Recovery1 $4,200,852 $2,873,693 $4,200,852 $2,873,693 $4,200,852 $2,873,693 Regarding interest rates, EPA calculated capital recoveries using 3

determining cost effectiveness for the Regulatory Impact Analysis rule and the Guidelines for BART Determinations under the RegioControl Cost Manual uses 7% interest rate in SCR example calculIn addition, the CCM also recommends a 20 year economic lifetimlifetimes have often been specified in BART and BACT analyses.

Total Annual Costs $5,230,653 $3,903,494 $5,279,403 $3,952,244 $5,201,745 $3,874,586

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materialincluded in the revised EPA estimate, although no basis was provi

SCR+LNB+OFA

Page 11 of 13
Printed 4/2/2012

Control Cost Comparison - SCR+ROFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Capital Costs

Rotating Overfire Air (ROFA)

Major Materials Design and Supply Construction 

$3,266,715 $3,266,715 $3,266,715 $3,266,715 $3,266,715 $3,266,715 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

although this line item description suggests it includes more than jdetailed guidance on what constituent elements may be included iappendix does not provide sufficient detail to make more specific 

Construction $742,500 $742,500 $742,500 $742,500 $742,500 $742,500 Vendor estimate. Comparable to Indirect installation costs as desc

detailed guidance on what constituent elements are allowed in this does not provide sufficient detail to make this evaluation

Balance of Plant $1,633,358 50% $1,633,358 50% $1,633,358 $1,633,358 $1,633,358 $1,633,358 Balance of plant is construed to refer to other capital expenditures 

in the CCM, and are considered part of direct capital costs (DCC)

Electrical (Allowance) $980,015 30% $980,015 30% $980,015 $980,015 $980,015 $980,015 Electrical equipment is included in the EPA control cost manual a

and so are retained here without revision

Owner's Costs $326,672 10% $0 0% $326,672 $0 $326,672 $0 Owner's costs such as project management, advisory fees, legal, e

Cost Manual. Although it is possible that certain CCM-allowed cadditional details would be needed to make that determination.

Surcharge $522,674 16% $0 0% $522,674 $0 $522,674 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $392,006 12% $0 0% $392,006 $0 $392,006 $0 AFUDC is not allowed for any of the applications listed in the EP

Subtotal, ROFA Capital Cost $7,863,939 $6,622,587 $7,863,939 $6,622,587 $7,863,939 $6,622,587Contingency $980,015 30% $490,007 15% $980,015 $490,007 $980,015 $490,007 EPA Control Cost Manual provides for project contingency costs 

capital costs (DCC) and indirect installation costs. For example, STables 1.4 and 2.5 allow a project contingency of 15% for SNCR 

Total ROFA Capital Cost $8,843,953 $7,112,594 $8,843,953 $7,112,594 $8,843,953 $7,112,594Selective Catalytic Reduction (SCR)

Major Materials Design and Supply Construction 

$22,685,522 $22,685,522 $22,685,522 $22,685,522 $22,685,522 $22,685,522 Vendor estimate. Comparable to Purchased Equipment Cost (PEC

although this line item description suggests it includes more than j

b Construction $0 0.0% $0 0% $0 $0 $0 $0

Balance of Plant $0 0.0% $0 0% $0 $0 $0 $0Electrical (Allowance) $0 0.0% $0 0% $0 $0 $0 $0Owner's Costs $2,268,552 10.0% $0 0% $2,268,552 $0 $2,268,552 $0 Owner's costs such as project management, advisory fees, legal, e

Cost Manual. Although it is possible that certain CCM-allowed cadditional details would be needed to make that determination.

Surcharge $3,629,684 16.0% $0 0% $3,629,684 $0 $3,629,684 $0 There is no provision for surcharge in the EPA Control Cost ManuAFUDC $2,722,263 12.0% $0 0% $2,722,263 $0 $2,722,263 $0 AFUDC is not allowed for SCR in the EPA Control Cost Manual, 

Subtotal, SCR Capital Cost $31,306,020 $22,685,522 $31,306,020 $22,685,522 $31,306,020 $22,685,522Contingency $3,402,828 15% $3,402,828 15% $3,402,828 $3,402,828 $3,402,828 $3,402,828 EPA Control Cost Manual provides for project contingency costs 

capital costs (DCC) and indirect installation costs. For example, STables 1.4 and 2.5 allow a project contingency of 15% for SNCR 

Total SCR Capital Cost $34,708,849 $26,088,350 $34,708,849 $26,088,350 $34,708,849 $26,088,350

Total Capital Cost $43,552,802 $33,200,945 $43,552,802 $33,200,945 $43,552,802 $33,200,945

Zero estimate provided by NDEP. Based upon the documentation are accounted for elsewhere

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

SCR+ROFA

Page 12 of 13
Printed 4/2/2012

Control Cost Comparison - SCR+ROFA

NDEP costs not allowed by EPA Control Cost ManualNDEP costs allowed by EPA Control Cost Manual, but modified from NDEP estimate

NDEP EPA Revised 

Cost

NDEP EPA Revised 

Cost

Value % Value % Comments

Unit 1 Unit 2 Unit 3

NDEP EPA Revised Cost

Annual Costs

Fixed O&M Costs

Operating Labor $0 $0 $0 $0 $0 $0 No estimate of additional operating labor was provided.Maintenance Materials $148,000 $148,000 $148,000 $148,000 $148,000 $148,000Maintenance Labor $222,000 $222,000 $222,000 $222,000 $222,000 $222,000Administrative Labor $0 $0 $0 $0 $0 $0 No estimate of additional administrative labor was provided.

Subtotal, fixed O&M costs $370,000 $370,000 $370,000 $370,000 $370,000 $370,000Variable Costs

Reagent $301,192 $301,192 $326,816 $326,816 $257,830 $257,830 EPA CCM does provide for certain raw material costs such as rea

Catalyst Replacement $112,500 $112,500 $112,500 $112,500 $132,000 $132,000 The EPA Control Cost Manual does provide for SCR catalyst repl

estimate is not clear, however, and it is difficult to determine how CCM might compare.

Auxiliary Power $529,500 $529,500 $578,755 $578,755 $560,284 $560,284 The EPA Control Cost Manual does provide for utility costs, such 

equipment. 

Subtotal, variable costs $943,192 $943,192 $1,018,071 $1,018,071 $950,114 $950,114Debt Service/Capital Recovery1 $4,602,267 $3,133,934 $4,602,267 $3,133,934 $4,602,267 $3,133,934 Regarding interest rates, EPA calculated capital recoveries using 3

determining cost effectiveness for the Regulatory Impact Analysis and the Guidelines for BART Determinations under the Regional Cost Manual uses 7% interest rate in SCR example calculations (Saddition, the CCM also recommends a 20 year economic lifetime lifetimes have often been specified in BART and BACT analyses.

Total Annual Costs $5,915,459 $4,447,126 $5,990,338 $4,522,005 $5,922,381 $4,454,048

1) Debt Service/Capital Recovery

Interest rate (%) = 8.5% 7.0%Equipment lifetime (years) = 20 20

The EPA Control Cost Manual provides for maintenance materialin the revised EPA estimate, although no basis was provided.

SCR+ROFA

Page 13 of 13
Page 38 of 40

Appendix C:

Model Emission Rate Calculations for Reid Gardner Generating Station

See www.regulations.gov, docket ID number EPA-R09-OAR-2011-0130
Modeling Scenarios for EPA's RH SIP Action on Reid Gardner Generating Station

updated 2012-03-07

Code Name Description NOx SO2 PM10

00 Baseline 1 WRAP Baseline None Wet Soda Ash Scrubber Mechanical Flyash 

Collector

02 Baseline 1a WRAP Baseline (NOx), NDEP 

BART determination (PM10, SO2) None Wet Soda Ash Scrubber (upgraded) Fabric Filter

04 Baseline 2

NDEP adjusted baseline (NOx), 

NDEP BART determination (PM10, 

SO2)

LNB w/ OFA Wet Soda Ash Scrubber 

(upgraded) Fabric Filter

11 Control Option 1 LNB + OFA (enhanced) LNB + OFA (enhanced) Wet Soda Ash Scrubber 

(upgraded) Fabric Filter

12 Control Option 2 SNCR + LNB w/ OFA SNCR + LNB w/ OFA Wet Soda Ash Scrubber 

(upgraded) Fabric Filter

13 Control Option 3 ROFA w/ Rotamix ROFA w/ Rotamix Wet Soda Ash Scrubber 

(upgraded) Fabric Filter

14 Control Option 4 SCR + ROFA SCR + ROFA Wet Soda Ash Scrubber 

(upgraded) Fabric Filter

15 Control Option 5 SCR + LNB w/ OFA SCR + LNB w/ OFA Wet Soda Ash Scrubber 

(upgraded) Fabric Filter

16 Control Option 6 SCR + LNB w/ OFA @.06 SCR + LNB w/ OFA @.06 Wet Soda Ash Scrubber 

(upgraded) Fabric Filter

Code is the number appearing in the CALPUFF model file name, e.g. cf_c11_2002.inp for CALPUFF, code 11 for control option 1, 2002 meteorolo

Control Technology
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 1

U.S. EPA, Region 9

Printed 4/2/2012

Elevation 

above MSL

Stack 

Height

Stack 

Diameter

Stack Crossec 

Area Exit Temp Exit Velocity Exit Flowrate

Annual Unit 

Capacity 

Factor

Boiler Heat 

Input (100% 

load)

(feet) (feet) (feet) (ft2) (deg F) (ft/s) (acfm) (percent) (MMBtu/hr) Notes

Reid Gardner Unit 1 1573 200 13.3 139 135 52.4 436702 86% 1215 1

Reid Gardner Unit 2 1572 249 13.3 139 145 50.3 419288 94% 1215 2

Reid Gardner Unit 3 1570 270 12.9 131 151 71.4 559911 91% 1237 3

436793.0311

1 Per Table 2-1, Reid Gardner 1 NVE BART Analysis submittal to NDEP, p.2-2 (p.13 in PDF)

2 Per Table 2-1, Reid Gardner 2 NVE BART Analysis submittal to NDEP, p.2-2 (p.13 in PDF)

3 Per Table 2-1, Reid Gardner 3 NVE BART Analysis submittal to NDEP, p.2-2 (p.13 in PDF)

in metric units, converted from the above m_per_ft 0.3048

kJ_per_BTU 1.05506

stack parm abbrevs ES HS DS TS VS

Elevation 

above MSL

Stack 

Height

Stack 

Diameter

Stack Crossec 

Area Exit Temp Exit Velocity Exit Flowrate

Annual Unit 

Capacity 

Factor

Boiler Heat 

Input (100% 

load)

(m) (m) (m) (m2) (deg K) (m/s) (acmm) (percent) (GJ/hr)

Reid Gardner Unit 1 479.5 60.96 4.05 12.9 330.37 15.97 12366 86% 1282

Reid Gardner Unit 2 479.1 75.90 4.05 12.9 335.93 15.33 11873 94% 1282

Reid Gardner Unit 3 478.5 82.30 3.93 12.1 339.26 21.76 15855 91% 1305

The stack parameters are identical to those used in BART modeling for the WRAP, except WRAP elevations were about 8 m higher.

Since WRAP stack coordinates (latitude and longitude) are about 700 m away from plant location in CAMD, whereas the values used in 

 the CH2MHill modeing were about 7000 m away, WRAP stack location and elevations will be used.

(The meteorological inputs are in the WRAP coordinate system for Arizona, which we will be using.)

Calculated values below are in italics (coordinate conversions done using Golden Software's MapViewer 6.2)

info source

Dist. from 

CAMD, 

km WRAP coordinate system Geographic coordinates CH2MHill coordinate system

X km Y km longitude latitude X km Y km

Plant location CAMD 0 -1556.0167 -218.6810 -114.6364 36.6531

Reid Gardner Unit 1 WRAP 0.7 -1555.5060 -218.2230 -114.6318 36.6581

Reid Gardner Unit 2 WRAP 0.7 -1555.5120 -218.2522 -114.6318 36.6578

Reid Gardner Unit 3 WRAP 0.6 -1555.5210 -218.2911 -114.6318 36.6574

Reid Gardner Unit 1 CH2MHill 7.0 -1550.0586 -222.4074 210.827 -366.266

Reid Gardner Unit 2 CH2MHill 7.0 -1550.0649 -222.4367 210.827 -366.296

Reid Gardner Unit 3 CH2MHill 7.1 -1550.0731 -222.4757 210.82729 -366.336
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 2

U.S. EPA, Region 9

Printed 4/2/2012

Unit No.

(1-hr, 24-hr)1 (Annual Ave)2

Reid Gardner Unit 1 1215 1132

Reid Gardner Unit 2 1215 1082

Reid Gardner Unit 3 1237 1135

1

 Max heat input as listed in TV Permit No. AP4911-0897. These values were also used by NV Energy to develop the maximum 24-hr ave emission rates used in visibility mode 

2 Annual average based on 0.86 annual capacity factor, as indicated by Nevada Energy in Appendix A of each unit's respective NVE BART Analysis (October 22, 2008). 

Baseline Emission Factors

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 WRAP Emission Rate 0.591 718 0.329 400 0.0474 58 2

NDEP baseline (SIP) 0.462 561 -- -- -- -- 3

CAMD 2001-03 (NVE) 0.576 700 0.332 403 -- -- 2

CAMD 2001-03 (EPA) 0.566 731 0.36 400 -- --

CAMD 2005-07 (EPA) 0.458 545 0.19 236 -- --

Reid Gardner Unit 2 WRAP Emission Rate 0.635 772 0.28 340 0.044 53 2

NDEP baseline (SIP) 0.466 566 -- -- -- -- 3

CAMD 2001-03 (NVE) 0.613 745 0.277 337 -- -- 2

CAMD 2001-03 (EPA) 0.571 804 0.276 375 -- --

CAMD 2005-07 (EPA) 0.425 655 0.39 399 -- --

Reid Gardner Unit 3 WRAP Emission Rate 0.592 732 0.32 396 0.04 49 2

NDEP baseline (SIP) 0.451 558 -- -- -- -- 3

CAMD 2001-03 (NVE) 0.579 716 0.29 359 -- -- 2

CAMD 2001-03 (EPA) 0.548 732 0.29 396 -- --

CAMD 2005-07 (EPA) 0.448 658 0.195 246 -- --

Reid Gardner Unit 1 from Title V permit limit 0.46 0.55 0.2

Reid Gardner Unit 2 NVE reports Title V permit limit 0.46 0.55 0.2

Reid Gardner Unit 3 Table 2- 1 Title V permit limit 0.46 0.55 0.1

1

 lb/MMBtu value based on Table 2-1 from each unit's respective NVE BART Analysis submittal to NDEP (October 22, 2008)

2 Corresponds to the revised NOx emission rate used as the baseline in the Nevada RH SIP. NDEP did not revise SO2 or PM10 emissions.

(MMBtu/hr)

Heat Input

Notes

NOx SO2 PM10
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 2 of 2

U.S. EPA, Region 9

Printed 4/2/2012

NOx Control Scenario Emission Factors

Control Technology

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 LNB w/ OFA (enhancement) 0.364 442 0.30 365 0.015 18 0.15 182

SNCR w/ LNB and OFA 0.273 332 0.23 279 0.015 18 0.15 182

ROFA w/ Rotamix 0.195 237 0.16 194 0.015 18 0.15 182

SCR w/ ROFA 0.085 103 0.07 85 0.015 18 0.15 182

SCR w/ LNB and OFA 0.085 103 0.07 85 0.015 18 0.15 182

SCR w/ LNB and OFA @.06 0.06 73 0.015 18 0.15 182

Reid Gardner Unit 2 LNB w/ OFA (enhancement) 0.355 431 0.30 365 0.015 18 0.15 182

SNCR w/ LNB and OFA 0.267 324 0.23 279 0.015 18 0.15 182

ROFA w/ Rotamix 0.191 232 0.16 194 0.015 18 0.15 182

SCR w/ ROFA 0.083 101 0.07 85 0.015 18 0.15 182

SCR w/ LNB and OFA 0.083 101 0.07 85 0.015 18 0.15 182

SCR w/ LNB and OFA @.06 0.06 73 0.015 18 0.15 182

Reid Gardner Unit 3 LNB w/ OFA (enhancement) 0.421 521 0.30 371 0.015 19 0.15 186

SNCR w/ LNB and OFA 0.316 391 0.23 285 0.015 19 0.15 186

ROFA w/ Rotamix 0.278 344 0.16 198 0.015 19 0.15 186

SCR w/ ROFA 0.098 121 0.07 87 0.015 19 0.15 186

SCR w/ LNB and OFA 0.098 121 0.07 87 0.015 19 0.15 186

SCR w/ LNB and OFA @.06 0.06 74 0.015 19 0.15 186

1

 Control technology performance as used by NDEP in development of the Regional Haze SIP. As summarized in Table 1, NDEP Reid Gardner BART Determination Review (Oc 

2

 Control technology performance as indicated by Nevada Energy in Appendix A of each unit's respective NVE BART Analysis (October 2008)

3

 SO2 emissions based upon Nevada's SO2 BART determination of upgraded wet soda ash scrubber. Per the NV RH SIP, this emission rate is based on a 24-hr ave 

4

 PM10 emissions based upon Nevada's PM10 BART determination of fabric filters. Per the NV RH SIP, this emission rate is based on a 3-hr averaging period

5

 EPA estimate for SCR of 0.06 lb/MMBtu NOx

NV Energy Estimates2

NOx PM103 SO24

NDEP Estimates1,5
Coal Properties

Average2 Highest

Property Bowie Skyline Sufco Dugout Aberdeen Crandall West Ridge Value Value

Moist. % 8.5 9.79 9.69 5.53 6.83 7.5 5.78 7.66 9.79

Ash % 9.06 7.64 7.97 8.65 8.5 8 7.48 8.19 9.06

Volatile Matter % 33.53 38.2 35.95 33.05 38 41.05 34.91 36.38 41.05

Fixed Carbon % 48.91 44.37 46.39 52.77 46.16 43 51.84 47.63 52.77

Sulfur % 0.46 0.57 0.29 0.51 0.51 0.45 1.35 0.59 1.35

HHV Btu/lb 12,012 11,712 11,463 12,469 12,276 12,400 12,856 12,170 12,856

Notes:

1 Coal properties as presented in Table 2-2 of respective NVE BART Analyses

2 Average values used in calculations below, where necessary. Note that NV Energy used Skyline coal in most of its calculations (per Appendix A of NVE BART Analyses)

PM10 Speciation 

Option 1a (Total PM10, scrubber)

Assuming WRAP emissions represent Total PM10 (filterable PM10 + condensable PM10). This option is basically identical to NPS' approach

Based on scrubber as emission control

Emission Factor1,2

(lb/MMBtu) (%) (lb/MMBtu) (%) (lb/MMBtu) (%) CALPUFF Species

Inorganic CPM 0.016 10% SO4

Condensable PM10 0.020 12%

Organic CPM 0.004 2% SOA

PM Coarse (10-2.5 μm) 0.040 29% PM Coarse 0.040 25% PMC

Filterable PM10 0.1413 88%

Fine Soil 0.097 60% PMF

PM Fine (<2.5 μm) 0.101 71%

Fine EC 0.004 2% EC

Total 100% Total 100%

1 Condensable PM10 EF calculated using , AP-42, Table 1.1-5 (9/98), PC boiler, with FGD control

2 Filterable PM10 EF calculated based on AP-42, Table 1.1-6 (9/98) for particles < 10 μm. Based on scrubber as particulate control.

3 PM2.5 EF calculated based on AP-42, Table 1.1-6 (9/98) for particles < 2.5 μm. Based on scrubber as particulate control.

4 Organic/Inorganic CPM emission factors based upon AP-42, Table 1.1-5 (9/98), PC boiler

5 EC fraction based on black carbon % as listed in Table 6 of "Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon, Jan 2002 Draft"

Option 1b (Total PM10, fabric filter/baghouse)

Assuming WRAP emissions represent Total PM10 (filterable PM10 + condensable PM10). This option is basically identical to NPS' approach

Based on fabric filter as emission control

Emission Factor1,2

(lb/MMBtu) (%) (lb/MMBtu) (%) (lb/MMBtu) (%) CALPUFF Species

Inorganic CPM 0.0160 60% SO4

Condensable PM10 0.020 75%

Organic CPM 0.0040 15% SOA

PM Coarse (10-2.5 μm) 0.0034 50% PM Coarse 0.0034 13% PMC

Filterable PM10 0.0067 25%

Fine Soil 0.0032 12% PMF

PM Fine (<2.5 μm) 0.0034 50%

Fine EC 0.00012 0.47% EC

Total 100% Total 100%

1 Condensable PM10 EF calculated using , AP-42, Table 1.1-5 (9/98), PC boiler, with FGD control

2 Filterable PM10 EF calculated based on AP-42, Table 1.1-6 (9/98) for particles < 10 μm. Based on baghouse as particulate control.

3 PM2.5 EF calculated based on AP-42, Table 1.1-6 (9/98) for particles < 2.5 μm, based on baghouse as particulate control

4 Organic/Inorganic CPM emission factors based upon AP-42, Table 1.1-5 (9/98), PC boiler

5 EC fraction based on black carbon % as listed in Table 6 of "Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon, Jan 2002 Draft"

Emission Rate

 (Total PM10)

Coal Type1

Emission Factor3 Emission Factor4,5

Emission Factor3 Emission Factor4,5

Emission Rate 

(Total PM10)
Option 2 (Method 5 + back half, scrubber)

Assuming WRAP emissions are based on Method 5 (Total filterable PM) including back-half catch (condensables). Reid Gardner's 2004 TV permit renewal requires Method 5 + back half catch testing for compliance demonstration.

Based on scrubber as emission control

Emission Factor1,2,6

(lb/MMBtu) (%) (lb/MMBtu) (%) (lb/MMBtu) (%) CALPUFF Species

Inorganic CPM 0.016 9% SO4

Condensable PM10 0.020 11%

Organic CPM 0.004 2% SOA

Total PM10

PM Coarse (10-2.5 μm) 0.040 29% PM Coarse 0.040 22% PMC

Filterable PM10 0.1413 78%

Fine Soil 0.097 54% PMF

PM Fine (<2.5 μm) 0.101 71%

Fine EC 0.004 2% EC

Filterable PM10+ 0.0202 11% PM10+ 0.0202 11% Not included

Total 100% Total 100%

1 Condensable PM10 EF calculated using , AP-42, Table 1.1-5 (9/98), PC boiler

2 Filterable PM10 EF calculated based on AP-42, Table 1.1-6 (9/98) for particles < 10 μm. Based on scrubber as particulate control.

3 PM2.5 EF calculated based on AP-42, Table 1.1-6 (9/98) for particles < 2.5 μm. Based on scrubber as particulate control.

4 Organic/Inorganic CPM emission factors based upon AP-42, Table 1.1-5 (9/98), PC boiler

5 EC fraction based on black carbon % as listed in Table 6 of "Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon, Jan 2002 Draft"

6 Filterable PM10+ EF calculated based on AP-42, Table 1.1-6 (9/98), using the difference between PM10 and PM15 Efs. Scrubber as particulate control

Option 3 (Filterable PM, scrubber)

Assuming WRAP emissions are based on Method 5 only (Total filterable PM). No back-half catch (condensables).

Based on scrubber as emission control

Emission Factor1,2

(lb/MMBtu) (%) (lb/MMBtu) (%) (lb/MMBtu) (%) CALPUFF Species

Inorganic CPM SO4

Condensable PM10 must be calculated separately using this option

Organic CPM SOA

PM Coarse (10-2.5 μm) 0.040 29% PM Coarse 0.040 25% PMC

Filterable PM10 0.1413 88%

Fine Soil 0.097 60% PMF

PM Fine (<2.5 μm) 0.101 71%

Fine EC 0.004 2% EC

Filterable PM10+ 0.0202 13% PM10+ 0.0202 13% Not included

Total 100% Total 100%

1 Filterable PM10+ EF calculated based on AP-42, Table 1.1-6 (9/98), using the difference between PM10 and PM15 Efs. Scrubber as particulate control

2 Filterable PM10 EF calculated based on AP-42, Table 1.1-6 (9/98) for particles < 10 μm. Based on scrubber as particulate control.

3 PM2.5 EF calculated based on AP-42, Table 1.1-6 (9/98) for particles < 2.5 μm. Based on scrubber as particulate control.

4 Organic/Inorganic CPM emission factors based upon AP-42, Table 1.1-5 (9/98), PC boiler

5 EC fraction based on black carbon % as listed in Table 6 of "Catalog of Global Emissions Inventories and Emission Inventory Tools for Black Carbon, Jan 2002 Draft"

Emission Factor3 Emission Factor4,5

Emission Rate 

(Method 5 only)

Emission Factor3 Emission Factor4,5

Emission Rate 

(Method 5 + back half)
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 2

U.S. EPA, Region 9

Printed 4/2/2012

Reid Gardner Generating Station

Baseline Emission Calculations

Baseline 1: WRAP emission baseline

Unit Name Heat Input HHV Fuel Sulfur Moisture

NOx SO2 PM10 (MMBtu/hr) (Btu/lb) wt% wt%

Reid Gardner Unit 1 None Wet Soda 

Ash Scrubber

Mechanical 

Flyash 

Collector

1215 12,170 0.59 7.66

Reid Gardner Unit 2 None Wet Soda 

Ash Scrubber

Mechanical 

Flyash 

Collector

1215 12,170 0.59 7.66

Reid Gardner Unit 3 None Wet Soda 

Ash Scrubber

Mechanical 

Flyash 

Collector

1237 12,170 0.59 7.66

00 Baseline 1 uses WRAP emission factors for NOx, SO2, and filterable PM

Unit Name H2SO41 SO4

SO4 SOA Coarse Fine Soil EC

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/hr) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 0.591 718 0.329 400 0.572 0.560 0.0474 58 4.86 14.40 34.66 1.33

Reid Gardner Unit 2 0.635 772 0.28 340 0.572 0.560 0.044 53 4.86 13.37 32.18 1.24

Reid Gardner Unit 3 0.592 732 0.32 396 0.582 0.570 0.04 49 4.95 12.37 29.78 1.14

1

H2SO4 Emission Calculations based upon "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, April 2010

ER = E2 * K * F1 * F2, based upon Equations 4-1 and 4-3 (fuel combustion only)

Where,

ER = H2SO4 emissions, (lb/hr)

E2 = SO2 emissions, (lb/hr)

K = 1.53 SO2 to H2SO4 mol wt conversion

F1 = 0.00111 Fuel impact factor, western bituminous coal, dry bottom boiler

F2 = 0.5 Table 4-3, air heater removal factor. Although fuel sulfur content is low, Reid Gardner coal ash is still assumed to be acidic (using lo 

0.65 Table 4-5, wet venturi scrubber

(lb/hr)

Control Technology

NOx SO2 Speciated PM10 Emissions3 Filterable PM2
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 2 of 2

U.S. EPA, Region 9

Printed 4/2/2012

E2 = K1 * K2 * C1 * S1, based upon Equation 4-2b. Although SO2 CEMS data exists, it was not used in the calculation because insufficient data exists to calculate the 

E2 = SO2 emissions (lb/hr)

K1 = 2.00 S to SO2 mol wt ratio

K2 = 0.95 Sulfur Conversion to SO2, bituminous coal

C1 = Dry coal burn rate (ton/hr)

S1 = Coal sulfur dry wt fraction

2 Although these emissions are represented in WRAP documenation as PM10, they were represented in NV Energy visibility modeling as filterable PM and speciated as such. They are also con 

filterable PM in this baseline run in order to be consistent.

3

 PM10 speciation is based upon Option 3, which assumes the WRAP PM10 emission rate represents results of Method 5 testing (filterable PM)

PM species (wt%)

Inorganic CPM (SO4) -- Inorganic CPM based upon SO4 emissions generated from H2SO4

Organic CPM (SOA) -- Organic CPM emissions based upon AP-42 (9/98), Table 1.1-5 (20% of CPM-TOT emission factor)

Coarse (PMC) 25%

Fine Soil (PMF) 60%

Elemental Carbon (EC) 2%
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 1

U.S. EPA, Region 9

Printed 4/2/2012

Reid Gardner Generating Station

Baseline Emission Calculations

Baseline 1a: WRAP emission baseline NOx, NDEP BART for SO2 and PM10

Unit Name Control Technology Heat Input HHV Fuel Sulfur Moisture

NOx SO2 PM10 (MMBtu/hr) (Btu/lb) wt% wt%

Reid Gardner Unit 1 None

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 2 None

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 3 None

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1237 12,170 0.59 7.66

02 Baseline 1a uses WRAP emission factors for NOx, and NDEP's BART determination for SO2 and PM10

Unit Name

SO4 (pre-rxn) SOA Coarse Fine Soil EC

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 0.591 718 0.15 182 0.015 18 10.91 2.73 2.29 2.21 0.08

Reid Gardner Unit 2 0.635 772 0.15 182 0.015 18 10.91 2.73 2.29 2.21 0.08

Reid Gardner Unit 3 0.592 732 0.15 186 0.015 19 11.11 2.78 2.33 2.25 0.09

1 SO2 emissions based upon Nevada's SO2 BART determination of upgraded wet soda ash scrubber

2 PM10 emissions based upon Nevada's PM10 BART determination of fabric filters. 

3

 PM10 speciation is based upon Option 1b (Total PM10, fabric filter/baghouse). Per TV Permit No. AP4911-0897, PM10 source testing must consist of Method 201A and 202, which would indicate that total PM10 test dat 

PM species (wt%)

Inorganic CPM (SO4) 60%

Organic CPM (SOA) 15%

Coarse (PMC) 13%

Fine Soil (PMF) 12%

Elemental Carbon (EC) 0.47%

NOx SO21 PM102 Speciated PM10 Emissions3

(lb/hr)
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 1

U.S. EPA, Region 9

Printed 4/2/2012

Reid Gardner Generating Station

Baseline Emission Calculations

Baseline 2: EPA baseline (NDEP baseline NOx, NDEP BART for SO2 and PM10)

Unit Name Control Technology Heat Input HHV Fuel Sulfur Moisture

NOx SO2 PM10 (MMBtu/hr) (Btu/lb) wt% wt%

Reid Gardner Unit 1 LNB w/ OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 2 LNB w/ OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 3 LNB w/ OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1237 12,170 0.59 7.66

04 Baseline 2 uses NDEP SIP's baseline emission factors for NOx, and NDEP's BART determination for SO2 and PM10

Unit Name

SO4 (pre-rxn) SOA Coarse Fine Soil EC

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 0.462 561 0.15 182 0.015 18 10.91 2.73 2.29 2.21 0.08

Reid Gardner Unit 2 0.466 566 0.15 182 0.015 18 10.91 2.73 2.29 2.21 0.08

Reid Gardner Unit 3 0.451 558 0.15 186 0.015 19 11.11 2.78 2.33 2.25 0.09

1 SO2 emissions based upon Nevada's SO2 BART determination of upgraded wet soda ash scrubber

2 PM10 emissions based upon Nevada's PM10 BART determination of fabric filters. 

3

 PM10 speciation is based upon Option 1b (Total PM10, fabric filter/baghouse). Per TV Permit No. AP4911-0897, PM10 source testing must consist of Method 201A and 202, which would indicate that 

PM species (wt%)

Inorganic CPM (SO4) 60%

Organic CPM (SOA) 15%

Coarse (PMC) 13%

Fine Soil (PMF) 12%

Elemental Carbon (EC) 0.47%

NOx SO21 PM102 Speciated PM10 Emissions3

(lb/hr)
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 1

U.S. EPA, Region 9

Printed 4/2/2012

Reid Gardner Generating Station

NOx Control Scenario Emission Calculations

Control Scenario 1: Upgraded LNB

Unit Name Control Technology Heat Input HHV Fuel Sulfur Moisture

NOx SO2 PM10 (MMBtu/hr) (Btu/lb) wt% wt%

Reid Gardner Unit 1 LNB + OFA 

(enhanced)

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 2 LNB + OFA 

(enhanced)

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 3 LNB + OFA 

(enhanced)

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1237 12,170 0.59 7.66

Control 1 emissions based on NDEP estimate of NOx for LNB+OFA, NDEP's BART determination for SO2 and PM10

Unit Name

SO4 (pre-rxn) SOA Coarse Fine Soil EC

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 0.364 442 0.15 182 0.015 18 10.91 2.73 2.29 2.21 0.08

Reid Gardner Unit 2 0.355 431 0.15 182 0.015 18 10.91 2.73 2.29 2.21 0.08

Reid Gardner Unit 3 0.421 521 0.15 186 0.015 19 11.11 2.78 2.33 2.25 0.09

1 SO2 emissions based upon Nevada's SO2 BART determination of upgraded wet soda ash scrubber

2 PM10 emissions based upon Nevada's PM10 BART determination of fabric filters. 

3

 PM10 speciation is based upon Option 1b (Total PM10, fabric filter/baghouse). Although the basis for the BART PM10 limit is unclear, TV Permit No. AP4911-0897 requires that PM10 source testin 

PM species (wt%)

Inorganic CPM (SO4) 60%

Organic CPM (SOA) 15%

Coarse (PMC) 13%

Fine Soil (PMF) 12%

Elemental Carbon (EC) 0.47%

Speciated PM10 Emissions3

(lb/hr)

NOx SO21 PM102
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 2

U.S. EPA, Region 9

Printed 4/2/2012

Reid Gardner Generating Station

NOx Control Scenario Emission Calculations

Control Scenario 2: SNCR with LNB w/ OFA

Unit Name Control Technology Heat Input HHV Fuel Sulfur Moisture

NOx SO2 PM10 (MMBtu/hr) (Btu/lb) wt% wt%

Reid Gardner Unit 1

SNCR + 

LNB w/ 

OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 2

SNCR + 

LNB w/ 

OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 3

SNCR + 

LNB w/ 

OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1237 12,170 0.59 7.66

Control 2 emissions based on NDEP estimate of NOx for SNCR+LNB+OFA, NDEP's BART determination for SO2 and PM10

Unit Name

SO4 (pre-rxn) SO4 (post rxn)4 SOA Coarse Fine Soil EC

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 0.273 332 0.15 182 0.015 18 10.91 0.00 2.73 2.29 2.21 0.08

Reid Gardner Unit 2 0.267 324 0.15 182 0.015 18 10.91 0.00 2.73 2.29 2.21 0.08

Reid Gardner Unit 3 0.316 391 0.15 186 0.015 19 11.11 0.00 2.78 2.33 2.25 0.09

1 SO2 emissions based upon Nevada's SO2 BART determination of upgraded wet soda ash scrubber

2 PM10 emissions based upon Nevada's PM10 BART determination of fabric filters. 

3

 PM10 speciation is based upon Option 1b (Total PM10, fabric filter/baghouse). Although the basis for the BART PM10 limit is unclear, TV Permit No. AP4911-0897 requires that PM10 source testing must consist o 

PM species (wt%)

Inorganic CPM (SO4) 60%

Organic CPM (SOA) 15%

Coarse (PMC) 13%

Fine Soil (PMF) 12%

Elemental Carbon (EC) 0.47%

Speciated PM10 Emissions3

(lb/hr)

NOx SO21 PM102
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 2 of 2

U.S. EPA, Region 9

Printed 4/2/2012

4

 H2SO4 from SCR based upon "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, April 2010

ER[NH3] = Ammonia Slip calculation

9780 dscf/MMBtu, from Method 19, Table 19-2 "Fuel F-factors". Fd-factor listed for bituminous coal @ 0% O2.

5 ppmv @ 6% O2 (ammonia slip). ROFA+Rotamix guarantee, as indicated in NVE BART analyses, p3-6

385.6 SCF/lbmol, molar volume @ STP.

17.0 lb/lbmol, NH3 MW

Unit No. Sample Calc (Unit 1):

SCFH lbmol/hr lb/hr

Unit 1 83.34 0.216 3.67 1215 MMBtu 9780 dscf 5 parts NH3 (20.9 - 0) O2 lbmol 17 lb NH3 = 3.67 lb

Unit 2 83.34 0.216 3.67 hr MMBtu 1,000,000 (20.9 - 6) O2 385.6 SCF lbmol hr

Unit 3 84.85 0.220 3.74

ER = ((EMSO4 - ERNH3)*98.6) * F2, based on modified equation 4-7

Where,

ER = H2SO4 emitted (lb/hr)

EM = H2SO4 manufactured (lbmol/hr)

ER[NH3] = Ammonia slip (lbmol/hr)

F2 = 0.5 Table 4-3, air heater removal factor. Although fuel sulfur content is low, Reid Gardner coal ash is still assumed to be acidic (using low S eastern bituminous factor per EPR 

0.10 Table 4-4, baghouse

0.65 Table 4-5, wet venturi scrubber

Unit No.

lb/hr lbmol/hr lbmol/hr lb/hr

Unit 1 10.91 0.111 -0.105 -0.34

Unit 2 10.91 0.111 -0.105 -0.34

Unit 3 11.11 0.113 -0.107 -0.34

Ammonia Emission Rate

H2SO4

EM

(pre-reaction)

ER

(post-reaction)
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 2

U.S. EPA, Region 9

Printed 4/2/2012

Reid Gardner Generating Station

NOx Control Scenario Emission Calculations

Control Scenario 3: ROFA w/ Rotamix

Unit Name Control Technology Heat Input HHV Fuel Sulfur Moisture

NOx SO2 PM10 (MMBtu/hr) (Btu/lb) wt% wt%

Reid Gardner Unit 1 ROFA w/ 

Rotamix

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 2 ROFA w/ 

Rotamix

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 3 ROFA w/ 

Rotamix

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1237 12,170 0.59 7.66

Control 3 emissions based on NDEP estimate of NOx for ROFA+Rotamix, NDEP's BART determination for SO2 and PM10

Unit Name

SO4 (pre-rxn) SO4 (post rxn)4 SOA Coarse Fine Soil EC

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 0.195 237 0.15 182 0.015 18 10.91 0.00 2.73 2.29 2.21 0.08

Reid Gardner Unit 2 0.191 232 0.15 182 0.015 18 10.91 0.00 2.73 2.29 2.21 0.08

Reid Gardner Unit 3 0.278 344 0.15 186 0.015 19 11.11 0.00 2.78 2.33 2.25 0.09

1 SO2 emissions based upon Nevada's SO2 BART determination of upgraded wet soda ash scrubber

2 PM10 emissions based upon Nevada's PM10 BART determination of fabric filters. 

3

 PM10 speciation is based upon Option 1b (Total PM10, fabric filter/baghouse). Although the basis for the BART PM10 limit is unclear, TV Permit No. AP4911-0897 requires that PM10 source testing must consist o 

PM species (wt%)

Inorganic CPM (SO4) 60%

Organic CPM (SOA) 15%

Coarse (PMC) 13%

Fine Soil (PMF) 12%

Elemental Carbon (EC) 0.47%

Speciated PM10 Emissions3

(lb/hr)

NOx SO21 PM102
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 2 of 2

U.S. EPA, Region 9

Printed 4/2/2012

4

 H2SO4 from SCR based upon "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, April 2010

ER[NH3] = Ammonia Slip calculation

9780 dscf/MMBtu, from Method 19, Table 19-2 "Fuel F-factors". Fd-factor listed for bituminous coal @ 0% O2.

5 ppmv @ 6% O2 (ammonia slip). ROFA+Rotamix guarantee, as indicated in NVE BART analyses, p3-6

385.6 SCF/lbmol, molar volume @ STP.

17.0 lb/lbmol, NH3 MW

Unit No. Sample Calc (Unit 1):

SCFH lbmol/hr lb/hr

Unit 1 83.34 0.216 3.67 1215 MMBtu 9780 dscf 5 parts NH3 (20.9 - 0) O2 lbmol 17 lb NH3 = 3.67 lb

Unit 2 83.34 0.216 3.67 hr MMBtu 1,000,000 (20.9 - 6) O2 385.6 SCF lbmol hr

Unit 3 84.85 0.220 3.74

ER = ((EMSO4 - ERNH3)*98.6) * F2, based on modified equation 4-7

Where,

ER = H2SO4 emitted (lb/hr)

EM = H2SO4 manufactured (lbmol/hr)

ER[NH3] = Ammonia slip (lbmol/hr)

F2 = 0.5 Table 4-3, air heater removal factor. Although fuel sulfur content is low, Reid Gardner coal ash is still assumed to be acidic (using low S eastern bituminous factor per EPR 

0.10 Table 4-4, baghouse

0.65 Table 4-5, wet venturi scrubber

Unit No.

lb/hr lbmol/hr lbmol/hr lb/hr

Unit 1 10.91 0.111 -0.105 -0.34

Unit 2 10.91 0.111 -0.105 -0.34

Unit 3 11.11 0.113 -0.107 -0.34

H2SO4

EM

(pre-reaction)

ER

(post-reaction)

Ammonia Emission Rate
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 3

U.S. EPA, Region 9

Printed 4/2/2012

Reid Gardner Generating Station

NOx Control Scenario Emission Calculations

Control Scenario 4: SCR with ROFA

Unit Name Control Technology Heat Input HHV Fuel Sulfur Moisture

NOx SO2 PM10 (MMBtu/hr) (Btu/lb) wt% wt%

Reid Gardner Unit 1 SCR + 

ROFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 2 SCR + 

ROFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 3 SCR + 

ROFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1237 12,170 0.59 7.66

Control 4 emissions based on NDEP estimate of NOx for SCR+ROFA, NDEP's BART determination for SO2 and PM10

Unit Name H2SO44 SO4

 (from SCR) SO4 SO4 (total) SOA Coarse Fine Soil EC

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/hr) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 0.085 103 0.15 182 0.15 0.145 0.015 18 10.91 11.06 2.73 2.29 2.21 0.08

Reid Gardner Unit 2 0.083 101 0.15 182 0.15 0.145 0.015 18 10.91 11.06 2.73 2.29 2.21 0.08

Reid Gardner Unit 3 0.098 121 0.15 186 0.15 0.148 0.015 19 11.11 11.26 2.78 2.33 2.25 0.09

1 SO2 emissions based upon Nevada's SO2 BART determination of upgraded wet soda ash scrubber

2 PM10 emissions based upon Nevada's PM10 BART determination of fabric filters. 

3

 PM10 speciation is based upon Option 1b (Total PM10, fabric filter/baghouse). Although the basis for the BART PM10 limit is unclear, TV Permit No. AP4911-0897 requires that PM10 source testing must consist of Method 201A and 

PM species (wt%)

Inorganic CPM (SO4) 60%

Organic CPM (SOA) 15%

Coarse (PMC) 13%

Fine Soil (PMF) 12%

Elemental Carbon (EC) 0.47%

PM102 Speciated PM10 Emissions3

(lb/hr)

NOx SO21
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 2 of 3

U.S. EPA, Region 9

Printed 4/2/2012

4

 H2SO4 from SCR based upon "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, April 2010

E2 = K1 * K2 * C1 * S1, based upon Equation 4-2b. Although SO2 CEMS data exists, it was not used in the calculation because insufficient data exists to calculate the CEMS correction factor

Where,

E2 = SO2 emissions (lb/hr)

K1 = 2.00 S to SO2 mol wt ratio

K2 = 0.95 Sulfur Conversion to SO2, bituminous coal

C1 = Dry coal burn rate (lb/hr)

S1 = Coal sulfur dry wt fraction

Unit No.

C1 E2

(lb/hr) (lb/hr)

Unit 1 99838 1034.66

Unit 2 99838 1034.66

Unit 3 101646 1053.40

EM = K * S2 * f[sops] * E2 * F3[scr], based on equation 4-6

Where,

EM = H2SO4 manufactured (lb/hr)

K = 1.53 SO2 to H2SO4 molecular wt conversion

S2 = 0.0050 SCR catalyst SO2 oxidation rate, based upon 3 layers of catalyst

f[sops] = 0.98 Operating factor of SCR system. Corresponds to baseload operation, per Equation 4-6

F3[scr] = 1 SCR technology impact factor, non-PRB coal, per Equation 4-6

E2 = SO2 emissions, (lb/hr)

Unit No. H2SO4

EM

(ton/hr)

Unit 1 7.76

Unit 2 7.76

Unit 3 7.90

ERNH3 = Ammonia Slip calculation

9780 dscf/MMBtu, from Method 19, Table 19-2 "Fuel F-factors". Fd-factor listed for bituminous coal @ 0% O2.

0.75 ppmv @ 6% O2 (ammonia slip), per Equation 4-6. 

385.6 SCF/lbmol, molar volume @ STP.

17.0 lb/lbmol, NH3 MW

Unit No. Sample Calc (Unit 1):

SCFH lbmol/hr lb/hr

Unit 1 12.50 0.032 0.55 1215 MMBtu 9780 dscf 0.75 parts NH3 (20.9 - 0) O2 lbmol 17 lb NH3 = 0.55 lb

Unit 2 12.50 0.032 0.55 hr MMBtu 1,000,000 (20.9 - 6) O2 385.6 SCF lbmol hr

Unit 3 12.73 0.033 0.56

SO2

Ammonia Emission Rate
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 3 of 3

U.S. EPA, Region 9

Printed 4/2/2012

ER = ((EMH2SO4 - ERNH3)*MWH2SO4) * F2, based on modified equation 4-7

Where,

ER = H2SO4 emitted (lb/hr)

EMSO4 = H2SO4 manufactured (lbmol/hr)

ERNH3 = Ammonia slip (lbmol/hr)

MWH2SO4 = 98.6 lb/lbmol

F2 = 0.5 Table 4-3, air heater removal factor. Although fuel sulfur content is low, Reid Gardner coal ash is still assumed to be acidic (using low S eastern bituminous factor per EPRI recommendation)

0.10 Table 4-4, baghouse

0.65 Table 4-5, wet venturi scrubber

Unit No.

lb/hr lbmol/hr lbmol/hr lb/hr

Unit 1 7.76 0.079 0.046 0.15

Unit 2 7.76 0.079 0.046 0.15

Unit 3 7.90 0.080 0.047 0.15

H2SO4

EM

(pre-reaction)

ER

(post-reaction)
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 3

U.S. EPA, Region 9

Printed 4/2/2012

Reid Gardner Generating Station

NOx Control Scenario Emission Calculations

Control Scenario 5: SCR with LNB and OFA

Unit Name Control Technology Heat Input HHV Fuel Sulfur Moisture

NOx SO2 PM10 (MMBtu/hr) (Btu/lb) wt% wt%

Reid Gardner Unit 1

SCR + 

LNB w/ 

OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 2

SCR + 

LNB w/ 

OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 3

SCR + 

LNB w/ 

OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1237 12,170 0.59 7.66

Control 5 emissions based on NDEP estimate of NOx for SCR+LNB+OFA, NDEP's BART detemination for SO2 and PM10

Unit Name H2SO44 SO4

 (from SCR) SO4 SO4 (total) SOA Coarse Fine Soil EC

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/hr) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 0.085 103 0.15 182 0.15 0.145 0.015 18 10.91 11.06 2.73 2.29 2.21 0.08

Reid Gardner Unit 2 0.083 101 0.15 182 0.15 0.145 0.015 18 10.91 11.06 2.73 2.29 2.21 0.08

Reid Gardner Unit 3 0.098 121 0.15 186 0.15 0.148 0.015 19 11.11 11.26 2.78 2.33 2.25 0.09

1 SO2 emissions based upon Nevada's SO2 BART determination of upgraded wet soda ash scrubber

2 PM10 emissions based upon Nevada's PM10 BART determination of fabric filters. 

3

 PM10 speciation is based upon Option 1b (Total PM10, fabric filter/baghouse). Although the basis for the BART PM10 limit is unclear, TV Permit No. AP4911-0897 requires that PM10 source testing must consist of Metho 

PM species (wt%)

Inorganic CPM (SO4) 60%

Organic CPM (SOA) 15%

Coarse (PMC) 13%

Fine Soil (PMF) 12%

Elemental Carbon (EC) 0.47%

Speciated PM10 Emissions3

(lb/hr)

NOx SO21 PM102
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 2 of 3

U.S. EPA, Region 9

Printed 4/2/2012

4

 H2SO4 from SCR based upon "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, April 2010

E2 = K1 * K2 * C1 * S1, based upon Equation 4-2b. Although SO2 CEMS data exists, it was not used in the calculation because insufficient data exists to calculate the CEMS correction factor

Where,

E2 = SO2 emissions (lb/hr)

K1 = 2.00 S to SO2 mol wt ratio

K2 = 0.95 Sulfur Conversion to SO2, bituminous coal

C1 = Dry coal burn rate (lb/hr)

S1 = Coal sulfur dry wt fraction

Unit No.

C1 E2

(lb/hr) (lb/hr)

Unit 1 99838 1034.66

Unit 2 99838 1034.66

Unit 3 101646 1053.40

EM = K * S2 * f[sops] * E2 * F3[scr], based on equation 4-6

Where,

EM = H2SO4 manufactured (lb/hr)

K = 1.53 SO2 to H2SO4 molecular wt conversion

S2 = 0.0050 SCR catalyst SO2 oxidation rate, based upon 0.5% conversion at 3 layers of catalyst

f[sops] = 0.98 Operating factor of SCR system. Corresponds to baseload operation, per Equation 4-6

F3[scr] = 1 SCR technology impact factor, non-PRB coal, per Equation 4-6

E2 = SO2 emissions, (lb/hr)

Unit No. H2SO4

EM

(ton/hr)

Unit 1 7.76

Unit 2 7.76

Unit 3 7.90

ERNH3 = Ammonia Slip calculation

9780 dscf/MMBtu, from Method 19, Table 19-2 "Fuel F-factors". Fd-factor listed for bituminous coal @ 0% O2.

0.75 ppmv @ 6% O2 (ammonia slip), per Equation 4-6. 

385.6 SCF/lbmol, molar volume @ STP.

17.0 lb/lbmol, NH3 MW

Unit No. Sample Calc (Unit 1):

SCFH lbmol/hr lb/hr

Unit 1 12.50 0.032 0.55 1215 MMBtu 9780 dscf 0.75 parts NH3 (20.9 - 0) O2 lbmol 17 lb NH3 = 0.55 lb

Unit 2 12.50 0.032 0.55 hr MMBtu 1,000,000 (20.9 - 6) O2 385.6 SCF lbmol hr

Unit 3 12.73 0.033 0.56

Ammonia Emission Rate

SO2
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 3 of 3

U.S. EPA, Region 9

Printed 4/2/2012

ER = ((EMH2SO4 - ERNH3)*MWH2SO4) * F2, based on modified equation 4-7

Where,

ER = H2SO4 emitted (lb/hr)

EMSO4 = H2SO4 manufactured (lbmol/hr)

ERNH3 = Ammonia slip (lbmol/hr)

MWH2SO4 = 98.6 lb/lbmol

F2 = 0.5 Table 4-3, air heater removal factor. Although fuel sulfur content is low, Reid Gardner coal ash is still assumed to be acidic (using low S eastern bituminous factor per EPRI recom

0.10 Table 4-4, baghouse

0.65 Table 4-5, wet venturi scrubber

Unit No.

lb/hr lbmol/hr lbmol/hr lb/hr

Unit 1 7.76 0.079 0.046 0.15

Unit 2 7.76 0.079 0.046 0.15

Unit 3 7.90 0.080 0.047 0.15

H2SO4

ER

(post-reaction)

EM

(pre-reaction)
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 1 of 3

U.S. EPA, Region 9

Printed 4/2/2012

Reid Gardner Generating Station

NOx Control Scenario Emission Calculations

Control Scenario 6: SCR with LNB and OFA, EPA estimate of 0.06 lb/MMBtu NOx

Unit Name Control Technology Heat Input HHV Fuel Sulfur Moisture

NOx SO2 PM10 (MMBtu/hr) (Btu/lb) wt% wt%

Reid Gardner Unit 1 SCR + LNB 

w/ OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 2 SCR + LNB 

w/ OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1215 12,170 0.59 7.66

Reid Gardner Unit 3 SCR + LNB 

w/ OFA

Wet Soda Ash 

Scrubber 

(upgraded)

Fabric Filter 1237 12,170 0.59 7.66

Control 6 emissions based on EPA estimate of NOx for SCR+LNB+OFA, NDEP's BART determination for SO2 and PM10

Unit Name H2SO44 SO4

 (from SCR) SO4 SO4 (total) SOA Coarse Fine Soil EC

(lb/MMBtu) (lb/hr) (lb/MMBtu) (lb/hr) (lb/hr) (lb/hr) (lb/MMBtu) (lb/hr)

Reid Gardner Unit 1 0.060 73 0.15 182 0.15 0.145 0.015 18 10.91 11.06 2.73 2.29 2.21 0.08

Reid Gardner Unit 2 0.060 73 0.15 182 0.15 0.145 0.015 18 10.91 11.06 2.73 2.29 2.21 0.08

Reid Gardner Unit 3 0.060 74 0.15 186 0.15 0.148 0.015 19 11.11 11.26 2.78 2.33 2.25 0.09

1 SO2 emissions based upon Nevada's SO2 BART determination of upgraded wet soda ash scrubber

2 PM10 emissions based upon Nevada's PM10 BART determination of fabric filters. 

3

 PM10 speciation is based upon Option 1b (Total PM10, fabric filter/baghouse). Although the basis for the BART PM10 limit is unclear, TV Permit No. AP4911-0897 requires that PM10 source testing must consist of Method 201A and 

PM species (wt%)

Inorganic CPM (SO4) 60%

Organic CPM (SOA) 15%

Coarse (PMC) 13%

Fine Soil (PMF) 12%

Elemental Carbon (EC) 0.47%

NOx SO21 PM102 Speciated PM10 Emissions3

(lb/hr)
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 2 of 3

U.S. EPA, Region 9

Printed 4/2/2012

4

 H2SO4 from SCR based upon "Estimating Total Sulfuric Acid Emissions from Stationary Power Plants," EPRI, Technical Update, April 2010

E2 = K1 * K2 * C1 * S1, based upon Equation 4-2b. Although SO2 CEMS data exists, it was not used in the calculation because insufficient data exists to calculate the CEMS correction factor

Where,

E2 = SO2 emissions (lb/hr)

K1 = 2.00 S to SO2 mol wt ratio

K2 = 0.95 Sulfur Conversion to SO2, bituminous coal

C1 = Dry coal burn rate (lb/hr)

S1 = Coal sulfur dry wt fraction

Unit No.

C1 E2

(lb/hr) (lb/hr)

Unit 1 99838 1034.66

Unit 2 99838 1034.66

Unit 3 101646 1053.40

EM = K * S2 * f[sops] * E2 * F3[scr], based on equation 4-6

Where,

EM = H2SO4 manufactured (lb/hr)

K = 1.53 SO2 to H2SO4 molecular wt conversion

S2 = 0.0050 SCR catalyst SO2 oxidation rate, based upon 0.5% conversion at 3 layers of catalyst

f[sops] = 0.98 Operating factor of SCR system. Corresponds to baseload operation, per Equation 4-6

F3[scr] = 1 SCR technology impact factor, non-PRB coal, per Equation 4-6

E2 = SO2 emissions, (lb/hr)

Unit No. H2SO4

EM

(ton/hr)

Unit 1 7.76

Unit 2 7.76

Unit 3 7.90

ERNH3 = Ammonia Slip calculation

9780 dscf/MMBtu, from Method 19, Table 19-2 "Fuel F-factors". Fd-factor listed for bituminous coal @ 0% O2.

0.75 ppmv @ 6% O2 (ammonia slip), per Equation 4-6. 

385.6 SCF/lbmol, molar volume @ STP.

17.0 lb/lbmol, NH3 MW

Unit No. Sample Calc (Unit 1):

SCFH lbmol/hr lb/hr

Unit 1 12.50 0.032 0.55 1215 MMBtu 9780 dscf 0.75 parts NH3 (20.9 - 0) O2 lbmol 17 lb NH3 = 0.55 lb

Unit 2 12.50 0.032 0.55 hr MMBtu 1,000,000 (20.9 - 6) O2 385.6 SCF lbmol hr

Unit 3 12.73 0.033 0.56

SO2

Ammonia Emission Rate
Reid Gardner Generating Station

Nevada Regiona Haze SIP Page 3 of 3

U.S. EPA, Region 9

Printed 4/2/2012

ER = ((EMH2SO4 - ERNH3)*MWH2SO4) * F2, based on modified equation 4-7

Where,

ER = H2SO4 emitted (lb/hr)

EMSO4 = H2SO4 manufactured (lbmol/hr)

ERNH3 = Ammonia slip (lbmol/hr)

MWH2SO4 = 98.6 lb/lbmol

F2 = 0.5 Table 4-3, air heater removal factor. Although fuel sulfur content is low, Reid Gardner coal ash is still assumed to be acidic (using low S eastern bituminous factor per EPRI recommendation)

0.10 Table 4-4, baghouse

0.65 Table 4-5, wet venturi scrubber

Unit No.

lb/hr lbmol/hr lbmol/hr lb/hr

Unit 1 7.76 0.079 0.046 0.15

Unit 2 7.76 0.079 0.046 0.15

Unit 3 7.90 0.080 0.047 0.15

H2SO4

EM

(pre-reaction)

ER

(post-reaction)
Page 39 of 40

Appendix D:

Historical Emissions for Reid Gardner Generating Station (as reported in CAMD)

See www.regulations.gov, docket ID number EPA-R09-OAR-2011-0130
Reid Gardner Generating Station

Nevada Regional Haze SIP

Page 1 of 1

Reid Gardner 2001-10 (Annual)

U.S. EPA Region 9

Printed 4/2/2012

STATE FACILITY_NAME ORISPL_COUNITID OP_YEAR ASSOC_STAPRG_CODE SUM_OP_TNUM_MONSO2_MASS SO2_RATE NOX_RATE NOX_MASS CO2_MASS HEAT_INPUT CO2_RATE OWN_DISPLAY UNIT_TYPE_INFO PRIMARY_FSECONDAR SO2_CONT NOX_CONTPART_CONTCAPACITY_INPUT

(tons/yr) (lb/MMBtu) (lb/MMBtu) (tons/yr) (tons/yr) (MMBtu/yr) (tons/MMBtu) (MMBtu/hr)

NV Reid Gardner 2324 1 2001 ARP 7211.5 12 587.506 0.15 0.42 1652.943 790,945 7,894,057 0.100 NV Energy (Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 1 2002 ARP 7673.5 12 492.827 0.10 0.47 2221.394 956,356 9,491,928 0.101 NV Energy (Operator) (Ended Dec 3 Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 1 2003 ARP 8271.5 12 749.629 0.15 0.45 2312.514 1,031,866 10,138,698 0.102 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 1 2004 ARP 7598.5 12 215.018 0.05 0.38 1771.312 933,887 9,237,466 0.101 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 1 2005 ARP 7902.75 12 186.87 0.04 0.37 1780.584 974,563 9,578,809 0.102 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 1 2006 ARP 7911.25 12 247.374 0.05 0.36 1663.686 934,613 9,088,376 0.103 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 1 2007 ARP 6583.68 12 132.603 0.04 0.38 1412.933 732,650 7,345,334 0.100 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 1 2008 ARP 6665.5 12 137.398 0.04 0.39 1340.789 671,618 6,732,582 0.100 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse ( 1215

NV Reid Gardner 2324 1 2009 ARP 6235.59 12 172.236 0.05 0.31 997.701 645,540 6,374,908 0.101 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 1215

NV Reid Gardner 2324 1 2010 ARP 6481.17 12 200.513 0.06 0.27 856.633 631,645 6,339,957 0.100 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 1215

NV Reid Gardner 2324 1 2011 ARP 6386.3 12 275.563 0.10 0.24 677.033 569,220 5,440,729 0.105 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 1215

NV Reid Gardner 2324 2 2001 ARP 7492.5 12 436.285 0.10 0.43 1947.113 905,107 9,031,359 0.100 NV Energy (Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 2 2002 ARP 8074.75 12 254.464 0.05 0.46 2504.151 1,099,225 10,841,071 0.101 NV Energy (Operator) (Ended Dec 3 Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 2 2003 ARP 7599 12 527.698 0.10 0.46 2386.279 1,034,507 10,162,427 0.102 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 2 2004 ARP 8035 12 268.916 0.05 0.40 2285.593 1,165,348 11,556,209 0.101 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 2 2005 ARP 6992.5 12 224.022 0.05 0.39 1861.09 961,732 9,530,909 0.101 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 2 2006 ARP 7590.75 12 249.144 0.05 0.39 2053.589 1,058,480 10,323,703 0.103 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 2 2007 ARP 8157.26 12 188.967 0.04 0.40 1952.307 1,006,145 9,771,674 0.103 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 2 2008 ARP 7752.75 12 122.196 0.03 0.40 1606.043 821,436 8,048,541 0.102 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1215

NV Reid Gardner 2324 2 2009 ARP 5406.78 12 153.722 0.05 0.33 949.288 572,183 5,590,251 0.102 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse ( 1215

NV Reid Gardner 2324 2 2010 ARP 6755.55 12 219.063 0.06 0.29 1045.961 699,409 6,967,468 0.100 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 1215

NV Reid Gardner 2324 2 2011 ARP 6065.84 12 261.760 0.10 0.25 669.406 546,329 5,287,823 0.103 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 1215

NV Reid Gardner 2324 3 2001 ARP 8172.25 12 571.735 0.11 0.44 2216.213 995,971 9,973,357 0.100 NV Energy (Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1237

NV Reid Gardner 2324 3 2002 ARP 8068.25 12 272.945 0.05 0.45 2320.33 1,014,028 10,154,344 0.100 NV Energy (Operator) (Ended Dec 3 Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1237

NV Reid Gardner 2324 3 2003 ARP 7698 12 519.154 0.11 0.36 1665.226 1,010,950 9,453,692 0.107 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1237

NV Reid Gardner 2324 3 2004 ARP 8022.5 12 235.284 0.05 0.32 1672.191 1,041,994 10,365,003 0.101 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1237

NV Reid Gardner 2324 3 2005 ARP 7875.25 12 270.388 0.06 0.30 1440.373 1,031,676 9,590,769 0.108 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1237

NV Reid Gardner 2324 3 2006 ARP 6948.25 12 195.758 0.04 0.33 1504.294 943,403 9,009,871 0.105 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1237

NV Reid Gardner 2324 3 2007 ARP 6833.33 12 141.604 0.03 0.28 1176.845 840,818 8,126,408 0.103 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1237

NV Reid Gardner 2324 3 2008 ARP 7091.43 12 160.794 0.04 0.25 1032.485 841,932 8,101,831 0.104 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Other 1237

NV Reid Gardner 2324 3 2009 ARP 6747.79 12 221.27 0.06 0.26 969.336 783,836 7,549,004 0.104 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse ( 1237

NV Reid Gardner 2324 3 2010 ARP 7231.19 12 243.069 0.06 0.23 930.935 828,066 8,080,157 0.102 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 1237

NV Reid Gardner 2324 3 2011 ARP 5965.13 12 295.296 0.10 0.21 578.259 592,631 5,642,747 0.105 NV Energy (Owner/Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 1237

NV Reid Gardner 2324 4 2001 ARP 7979.75 12 571.831 0.06 0.30 3221.881 2,118,040 20,697,548 0.102 NV Energy (Operator) Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2002 ARP 8379.5 12 957.296 0.09 0.33 3688.655 2,282,248 21,802,457 0.105 NV Energy (Operator) (Ended Dec 3 Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2003 ARP 7528.25 12 2843.657 0.25 0.37 4347.952 2,401,537 23,157,911 0.104 NV Energy (Owner/Operator) Califo Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2004 ARP 7537.5 12 1017.362 0.10 0.29 3189.406 2,147,230 21,031,588 0.102 NV Energy (Owner/Operator) Califo Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2005 ARP 7893 12 1412.474 0.13 0.34 3933.081 2,285,140 22,583,722 0.101 NV Energy (Owner/Operator) Califo Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2006 ARP 7690.5 12 1322.722 0.12 0.30 3421.548 2,230,077 22,152,886 0.101 NV Energy (Owner/Operator) Califo Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2007 ARP 7802.58 12 689.848 0.07 0.27 2829 2,139,141 20,913,608 0.102 NV Energy (Owner/Operator) Califo Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2008 ARP 6792.28 12 520.515 0.07 0.22 1684.931 1,538,533 14,757,038 0.104 NV Energy (Owner/Operator) Califo Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2009 ARP 7918.23 12 698.18 0.09 0.23 1725.657 1,558,907 14,863,684 0.105 NV Energy (Owner/Operator) Califo Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2010 ARP 6974.02 12 576.771 0.10 0.20 1232.07 1,260,586 12,019,305 0.105 NV Energy (Owner/Operator) Califo Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956

NV Reid Gardner 2324 4 2011 ARP 6034.2 12 595.557 0.11 0.19 1141.287 1,126,632 10,742,124 0.105 NV Energy (Owner/Operator) Califo Dry bottom wall-fired Coal Sodium BasLow NOx Bu Baghouse 2956
Reid Gardner Generating Station

Nevada Regional Haze SIP

Page 1 of 2

Reid Gardner 2010-11 (monthly)

U.S. EPA Region 9

Printed 4/2/2012

STATE FACILITY_NORISPL_CUNITID OP_YEAR ASSOC_NTH PRG_CODE SUM_OP_TIME GLOAD SLOAD SO2_MASS NOX_RATE NOX_MASS CO2_MASS HEAT_INPUT CO2_Rate PRIMARY_FSECONDAR SO2_CONT NOX_CONTPART_CONTROL_INFO

(hours/month) (MWh/month) (tons/month) (lb/MMBtu) (tons/month) (tons/month) (MMBtu/month) (tons/MMBtu)

(Measured) (Measured) (Calculated)

NV Reid Gardne 2324 1 2010 1 ARP 730 77698 18 0.27 107 77321 780991 0.099 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 2 ARP 672 73606 31 0.28 104 75374 748523 0.101 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 3 ARP 595 63029 29 0.30 99 63854 642373 0.099 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 4 ARP 515 48364 15 0.27 68 48722 488562 0.100 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 5 ARP 744 69680 14 0.28 99 70021 707571 0.099 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 6 ARP 636 59186 22 0.25 78 61609 618698 0.100 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 7 ARP 744 75120 26 0.28 111 78330 790081 0.099 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 8 ARP 557 53008 20 0.22 63 54948 554486 0.099 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 9 ARP 412 32317 12 0.24 41 33507 334823 0.100 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 10 ARP 222 18579 6 0.25 24 18835 189179 0.100 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 11 ARP 22 77 0 0.09 0 213 2468 0.086 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2010 12 ARP 633 43695 7 0.25 62 48909 482204 0.101 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 1 ARP 474 38998 12 0.23 48 43574 422126 0.103 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 2 ARP 0 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 3 ARP 58 1837 1 0.21 3 2096 22714 0.092 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 4 ARP 294 23626 11 0.24 33 26733 259754 0.103 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 5 ARP 565 43573 26 0.29 71 49012 479250 0.102 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 6 ARP 720 66595 56 0.27 98 77082 727630 0.106 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 7 ARP 743 66981 44 0.26 88 72052 681521 0.106 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 8 ARP 744 65516 27 0.25 77 65492 624454 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 9 ARP 717 58036 29 0.24 67 58399 556823 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 10 ARP 608 45449 20 0.23 54 49091 468074 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 11 ARP 720 59924 29 0.23 70 64074 610917 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 1 2011 12 ARP 744 57604 20 0.23 68 61613 587467 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 1 ARP 684 70401 17 0.31 117 77549 752217 0.103 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 2 ARP 630 67548 24 0.31 112 73781 726047 0.102 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 3 ARP 595 63169 27 0.35 123 68485 681122 0.101 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 4 ARP 547 54346 22 0.32 97 58932 588523 0.100 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 5 ARP 744 70012 24 0.31 117 76517 763142 0.100 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 6 ARP 650 62525 21 0.30 107 69091 693868 0.100 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 7 ARP 483 41873 17 0.28 69 46135 475897 0.097 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 8 ARP 660 64159 22 0.26 96 72586 728205 0.100 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 9 ARP 675 54543 21 0.25 79 63156 626957 0.101 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 10 ARP 426 33888 13 0.26 53 39289 387095 0.101 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 11 ARP 10 0 0 0.04 0 47 713 0.066 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2010 12 ARP 652 47943 11 0.27 75 53841 543682 0.099 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 1 ARP 514 41314 12 0.29 69 46580 459082 0.101 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 2 ARP 310 25868 19 0.26 39 29417 289361 0.102 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 3 ARP 0 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 4 ARP 0 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 5 ARP 621 46425 26 0.25 72 53342 537280 0.099 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 6 ARP 563 45916 38 0.24 68 55171 544195 0.101 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 7 ARP 743 65741 48 0.25 88 73730 711074 0.104 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 8 ARP 744 62252 30 0.24 75 65999 629266 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 9 ARP 599 44743 20 0.26 61 48819 465481 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 10 ARP 744 54721 23 0.23 68 61974 590899 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 11 ARP 720 59202 30 0.24 76 65626 625716 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 2 2011 12 ARP 507 40950 18 0.25 54 45671 435468 0.105 Coal Sodium BasLow NOx Bu Baghouse
Reid Gardner Generating Station

Nevada Regional Haze SIP

Page 2 of 2

Reid Gardner 2010-11 (monthly)

U.S. EPA Region 9

Printed 4/2/2012

STATE FACILITY_NORISPL_CUNITID OP_YEAR ASSOC_NTH PRG_CODE SUM_OP_TIME GLOAD SLOAD SO2_MASS NOX_RATE NOX_MASS CO2_MASS HEAT_INPUT CO2_Rate PRIMARY_FSECONDAR SO2_CONT NOX_CONTPART_CONTROL_INFO

(hours/month) (MWh/month) (tons/month) (lb/MMBtu) (tons/month) (tons/month) (MMBtu/month) (tons/MMBtu)

(Measured) (Measured) (Calculated)

NV Reid Gardne 2324 3 2010 1 ARP 707 77024 23 0.25 106 87858 842894 0.104 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 2 ARP 670 74279 21 0.24 97 84132 813445 0.103 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 3 ARP 593 64219 19 0.26 95 73197 710223 0.103 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 4 ARP 719 73106 25 0.24 98 84712 827120 0.102 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 5 ARP 564 49496 17 0.22 63 57475 565832 0.102 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 6 ARP 712 69416 23 0.23 92 80183 793660 0.101 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 7 ARP 716 73449 30 0.23 99 86489 851718 0.102 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 8 ARP 695 65800 25 0.20 84 84691 818442 0.103 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 9 ARP 658 54401 19 0.20 66 66451 650978 0.102 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 10 ARP 482 46185 24 0.23 65 58265 562684 0.104 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 11 ARP 79 5175 1 0.19 7 6411 63216 0.101 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2010 12 ARP 635 46988 16 0.19 58 58201 579944 0.100 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 1 ARP 685 60715 24 0.20 75 76920 735798 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 2 ARP 412 37941 23 0.20 45 47706 455431 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 3 ARP 0 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 4 ARP 260 20360 6 0.21 27 25497 238626 0.107 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 5 ARP 445 27936 22 0.23 40 34850 328082 0.106 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 6 ARP 709 67371 65 0.19 78 84044 797957 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 7 ARP 682 63662 49 0.21 75 73278 699952 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 8 ARP 715 63312 35 0.21 72 71198 678864 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 9 ARP 568 43737 22 0.20 46 50155 478210 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 10 ARP 590 45679 22 0.20 48 51578 491782 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 11 ARP 650 52704 23 0.19 54 59156 564046 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 3 2011 12 ARP 250 16643 4 0.24 19 18249 173998 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 1 ARP 633 147714 88 0.22 160 149597 1426374 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 2 ARP 321 85569 39 0.21 89 87140 830860 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 3 ARP 56 0 0 0.03 0 400 3817 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 4 ARP 627 96658 33 0.21 107 102556 977833 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 5 ARP 639 72380 27 0.21 84 82594 787501 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 6 ARP 572 97455 46 0.21 104 100665 959813 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 7 ARP 744 146529 76 0.20 137 150608 1436003 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 8 ARP 733 136697 51 0.19 127 141694 1351015 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 9 ARP 616 110989 47 0.19 107 116637 1112104 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 10 ARP 669 106081 33 0.19 109 116342 1109292 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 11 ARP 647 82251 42 0.21 93 95108 906817 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2010 12 ARP 718 103274 97 0.20 115 117244 1117877 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 1 ARP 15 0 0 0.06 0 246 2347 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 2 ARP 620 89922 55 0.22 110 101878 971377 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 3 ARP 192 17585 7 0.17 22 20377 194295 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 4 ARP 0 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 5 ARP 556 102011 44 0.18 98 107913 1028925 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 6 ARP 648 130140 80 0.22 142 134642 1283777 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 7 ARP 744 157867 97 0.20 151 162505 1549441 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 8 ARP 686 136139 90 0.21 144 141577 1349895 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 9 ARP 647 137850 94 0.22 147 142205 1355874 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 10 ARP 561 116332 55 0.20 116 117480 1120130 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 11 ARP 666 86361 28 0.21 90 88739 846115 0.105 Coal Sodium BasLow NOx Bu Baghouse

NV Reid Gardne 2324 4 2011 12 ARP 699 103695 44 0.22 121 109070 1039947 0.105 Coal Sodium BasLow NOx Bu Baghouse
Reid Gardner Generating Station

Nevada Regional Haze SIP

Page 1 of 2

Graphs

U.S. EPA Region 9

Printed 4/2/2012

2011 Unit 1 Nox lb/Mmbtu

0.23 0.000 (

0.21 0.000

0.24 0.000

0.29 0.000

0.27 0.000

0.26 0.000

0.25 0.000

0.24 0.000

0.23 0.000

0.23 0.000

0.23 0.000

Unit 2 Nox lb/Mmbtu (

0.29

0.26

0.25

0.24

0.25

0.24

0.26

0.23

0.24

0.25

Unit 3 NOx lb/Mmbtu (

0.20

0.20

0.21

0.23

0.19

0.21

0.21

0.20

0.20

0.19

0.24

0.00

0.05

0.10

0.15

0.20

0.25

0.30

1 2 3 4 5 6 7 8 9 10 11 12

Unit 1 Nox lb/Mmbtu

Unit 1 Nox lb/Mmbtu

0.00

0.05

0.10

0.15

0.20

0.25

0.30

1 2 3 4 5 6 7 8 9 10 11 12

Unit 2 Nox lb/Mmbtu

Unit 2 Nox lb/Mmbtu

0.00

0.05

0.10

0.15

0.20

0.25

1 2 3 4 5 6 7 8 9 10 11 12

Unit 3 NOx lb/Mmbtu

Unit 3 NOx lb/Mmbtu
Reid Gardner Generating Station

Nevada Regional Haze SIP

Page 2 of 2

Graphs

U.S. EPA Region 9

Printed 4/2/2012

NOX_RATE

(lb/MMBtu)year

0.42 2001

0.47 2002

0.45 2003

0.38 2004

0.37 2005

0.36 2006

0.38 2007

0.39 2008

0.31 2009

0.27 2010

0.24 2011

NOX_RATE

(lb/MMBtu)

0.43 2001

0.46 2002

0.46 2003

0.40 2004

0.39 2005

0.39 2006

0.40 2007

0.40 2008

0.33 2009

0.29 2010

0.25 2011

NOX_RATE

(lb/MMBtu)

0.44 2001

0.45 2002

0.36 2003

0.32 2004

0.30 2005

0.33 2006

0.28 2007

0.25 2008

0.26 2009

0.23 2010

0.21 2011

0.00

0.10

0.20

0.30

0.40

0.50

1 2 3 4 5 6 7 8 9 10 11

NOX_RATE (lb/MMBtu)

NOX_RATE (lb/MMBtu)

0.00

0.10

0.20

0.30

0.40

0.50

1 2 3 4 5 6 7 8 9 10 11

NOX_RATE (lb/MMBtu)

NOX_RATE (lb/MMBtu)

0.00

0.10

0.20

0.30

0.40

0.50

1 2 3 4 5 6 7 8 9 10 11

NOX_RATE (lb/MMBtu)

NOX_RATE (lb/MMBtu)
Page 40 of 40

Appendix E:

The files and spreadsheets listed below are too voluminous to be included in a hardcopy version, 

and are available electronically on www.regulations.gov, under Docket ID number EPA-R09-

OAR-2011-0130

In addition, the CALPUFF modeling input and output files, including meteorological data, will 

be made available electronically upon request.

Model File list (mod_files.txt)

Comparison of EPA’s RGGS CALPUFF modeling and variants to WRAP BART modeling 

results (WRAP_compare_tables.xls)

CALPUFF Model Results (RGGS_TSD_CALPUFF_tables.xls)

EPA results for 98th percentile delta deciviews, with NOx emissions

Visibility Method 6, annual avg. background

Visibility Method 6, best 20% background

Visibility Method 8, annual avg. background

Visibility Method 8, best 20% background

EPA results for 98th percentile delta deciviews, with individual years

Visibility Method 6, annual avg. background

Visibility Method 6, best 20% background

Visibility Method 8, annual avg. background

Visibility Method 8, best 20% background

EPA results for Number of days over 0.5 and 1.0 deciviews

Visibility Method 6, annual avg. background

Visibility Method 6, best 20% background

Visibility Method 8, annual avg. background

Visibility Method 8, best 20% background

Modeling results from CH2MHill for Nevada Energy

RGGS control scenario names in Nevada Energy in BART analysis 

Unit 1 Reid Gardner G.S. Visibility Impacts as Modeled by CH2MHill in 2008

Unit 2 Reid Gardner G.S. Visibility Impacts as Modeled by CH2MHill in 2008

Unit 3 Reid Gardner G.S. Visibility Impacts as Modeled by CH2MHill in 2008