APPENDIX D

TO NEW MEXICO’S REGIONAL HAZE SIP

UNDER 40 C.F.R. § 51.309(g)

New Mexico Environment Department

Air Quality Bureau

Revised BART Determination

Public Service Company of New Mexico

San Juan Generating Station, Units 1-4

May 21, 2013

Revised June 27, 2013
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PREFACE

This document is a revised version of the BART Determination for Public Service Company of New 

Mexico (PNM) San Juan Generating Station Units 1-4 that was attached as Appendix D to New 

Mexico’s June 2011 Regional Haze [SIP] State Implementation Plan (SIP), submitted pursuant to 

40 CFR § 51.309(g). As explained within, it has been revised to incorporate new information 

submitted by PNM in April 2013. The new information was submitted in accordance with the terms 

of a tentative [settlement] agreement between NMED, EPA, and PNM [to], which when fully 

implemented would resolve a dispute over the determination of [BART] Best Available Retrofit 

Technology (BART) for Nitrogen Oxides (NOx) for the San Juan Generating Station.
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Regulatory Background and Introduction:

In 1999, the [EPA] U.S. Environmental Protection Agency (EPA) published a final rule to address a type 

of visibility impairment known as regional haze (64 FR 35714, July 1, 1999). This rule requires States to 

submit state implementation plans (SIPs) to address regional haze visibility impairment in 156 Federallyprotected parks and wilderness areas. The 1999 rule was issued to fulfill a long-standing EPA 

commitment to address regional haze under the authority and requirements of sections 169A and 169B of 

the Clean Air Act (CAA).1

As required by the CAA, the EPA included in the final regional haze rule a requirement for Best 

Available Retrofit Technology (BART) for certain large stationary sources. The regulatory requirements 

for BART were codified at 40 CFR 50.308(e) and in definitions that appear in 40 CFR 50.301.

The BART-eligible sources are those sources which (1) have the potential to emit 250 tons per year or 

more of a visibility impairing air pollutant; (2) were put in place between August 7, 1962 and August 7, 

1977; and (3) whose operations fall within one or more of 26 specifically listed source categories. Under 

the CAA, BART is required for any BART-eligible source which a State determines “emits any air 

pollutant which may reasonably be anticipated to cause or contribute to any impairment of visibility in 

any such area.” Accordingly, for stationary sources meeting these criteria, States must address the BART 

requirement when they develop their regional haze SIPs. 1

The EPA published a second Regional Haze rulemaking on June 6, 2005 that made changes to the Final 

Rule published July 1, 1999. This second rulemaking was in response to a U.S. District Court of Appeals 

ruling that vacated part of the regional haze rule. The June 6, 2005 Final Rule (1) required the BART 

analysis to include an analysis of the degree of visibility improvement resulting from the use of control 

technology at BART-subject sources; (2) revised certain other BART provisions; (3) included new BART 

Guidelines contained in a new Appendix Y to Part 51 (Guidelines); and (4) added the requirement that 

States use the Guidelines for determining BART at certain large electrical generating units (EGUs).

1

The Guidelines also contained specific presumptive limits for SO2 and NOx for certain large EGUs based 

on fuel type, unit size, cost effectiveness, and presence or absence of pre-existing controls. For NOx

emissions, the EPA directs states to generally require owners and operators to meet the presumptive limits 

at coal-fired EGUs greater than 200 MW with a total facility-wide generating capacity greater than 750 

MW, unless it is determined that an alternative control level is justified based on consideration of the 

statutory factors. The presumptive limits for NOx are based on coal type, boiler type and whether SCR or 

SNCR are already installed at the source.

Analysis of BART Eligible Sources in NM:

In May 2006, the New Mexico Environment Department, Air Quality Bureau (Department) conducted an 

internal review of sources potentially subject to the BART rule. 

Section II of the Guidelines prescribes how to identify BART-eligible sources. States are required to 

identify those sources that satisfy the following criteria: (1) sources that fall within the 26 listed source 

categories as listed in the CAA; (2) sources that were “in existence” on August 7, 1977 but were not “in 

operation” before August 7, 1962; and (3) sources that have a current potential to emit that is greater than 

250 tons per year of any single visibility impairing pollutant. New Mexico identified 11 sources as 

BART-eligible sources as part of this review.

2

 
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The Guidelines then prescribe to the states how to identify those sources that are subject to BART. At 

this point, states are directed to either (1) make BART determinations for all BART-eligible sources, or 

(2) to consider exempting some of the sources from BART because they may not reasonably be 

anticipated to cause or contribute to any visibility impairment in a Class I area. New Mexico opted to 

perform an initial screening model on each of these BART-eligible sources to determine whether each

source did cause or contribute to any visibility impairment. The Guidelines direct States that if the 

analysis shows that an individual source or group of sources is not reasonably anticipated to cause or 

contribute to any visibility impairment in a Class I area, then the States do not need to make a BART 

determination for that source or group of sources. 1

 The guidelines provide that the threshold for 

determining whether a source “contributes” to visibility impairment should be set no higher than 0.5 

deciview (dv).

The Western Regional Air Partnership (WRAP) performed the initial BART modeling for the state of 

New Mexico. The procedures used are outlined in the WRAP Regional Modeling Center (RMC) BART 

Modeling Protocol that is available at:

http://pah.cert.ucr.edu/aqm/308/bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf

The basic assumptions in the WRAP BART CALMET/CALPUFF modeling used for New Mexico are as 

follows:

i. Use of three years of modeling of 2001, 2002, and 2003.

ii. Visibility impacts due to emissions of SO2, NOx and primary PM emissions were 

calculated. PM emissions were modeled as PM2.5. 

iii. Visibility was calculated using the Original IMPROVE equation and Annual Average 

Natural Conditions.

Initial modeling was performed for the 11 source complexes in New Mexico to assess visibility impacts

from SO2, NOx, and PM emissions.

Of the 11 source complexes analyzed, only one source complex’s visibility impacts at any Class I area 

due to combined SO2, NOx, and PM emissions exceeded the 0.5 dv threshold. This source was PNM San 

Juan Generating Station, Boilers #1-4 (“SJGS”). Of the 10 other source complexes, none exceed a 0.33 

dv impact. Therefore, for the SJGS only, the separate contribution to visibility at Class I areas was 

assessed for SO2 alone (SO4), NOx alone (NO3), PM alone (PMF), and combined NOx plus PM emissions 

(NO3 + PMF).2

 

On November 9, 2006, the Department informed PNM that the modeling performed by the WRAP 

indicated the visibility impairment from the SJGS was over the 0.5 dv threshold, and SJGS was therefore 

subject to a BART analysis. In response, Black & Veatch (B&V), on behalf of PNM, submitted the 

BART Modeling Protocol document which described the CALPUFF modeling methodology to be used as 

part of the BART engineering evaluation for SJGS.

SJGS Source Description:

The SJGS consists of four coal-fired generating units and associated support facilities. Each coal-fired 

unit burns pulverized coal and No. 2 diesel oil (for startup) in a boiler and produces high-pressure steam,

which powers a steam turbine coupled with an electric generator. Electric power produced by the units is 
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supplied to the electric power grid for sale. Coal for the units is supplied by the adjacent San Juan Mine 

and is delivered to the facility by conveyor.

The SJGS Boiler Units 1 and 2 have a unit capacity of 350 and 360 MW, respectively. The units are 

equipped with Foster Wheeler subcritical, wall-fired boilers that operate in a forced draft mode. The 

SJGS Boiler Units 3 and 4 each have a unit capacity of 544 MW and are equipped with B&W subcritical, 

opposed wall-fired boilers that operate in a forced draft mode. 

Consent Decree:

On March 5, 2005, PNM entered into a consent decree with the Grand Canyon Trust, the Sierra Club, and 

the Department to settle alleged violations of the CAA. The consent decree required PNM to meet a PM 

average emission rate of 0.015 pounds per million British thermal units (lb/MMBtu) (measured using 

EPA Reference Method 5), and a 0.30 lb/MMBtu emission rate for NOx (daily rolling, thirty day 

average), for each of Units 1, 2, 3, and 4. As a result, PNM installed Low NOx burners (LNB) with 

overfire air (OFA) ports and a neural network (NN) system to reduce NOx emissions, and pulse jet fabric 

filters (PJFF) to reduce the PM emissions (See Table 1). 

Table.1: SJGS Characteristics 

SJGS Characteristics 

Unit SJGS 1 SJGS 2 SJGS 3 SJGS 4

Fuel Type Sub-bituminous Sub-bituminous Sub-bituminous Sub-bituminous

HHV of Fuel (btu/lb) 9692 9692 9692 9692

Unit Rating, MW 

(gross) 360 350 544 544

Boiler Heat Input 

(Mbtu/hr) 3707 3688 5758 5649

Type of Boiler Wall-fired Wall-fired Opposed Wall-fired Opposed Wall-fired

Steam Cycle Subcritical Subcritical Subcritical Subcritical

Draft of Boiler Forced Forced Forced Forced

Existing Emissions Controls

PM PJFF PJFF PJFF PJFF

SO2 Wet FGD Wet FGD Wet FGD Wet FGD

NOx LNB/OFA/NN LNB/OFA/NN LNB/OFA/NN LNB/OFA/NN

BART Analysis Overview:

Per 40 CFR 51.308 Regional haze program requirements, the determination of BART must be based on 

an analysis of the best system of continuous emission control technology available and associated 

emission reductions achievable for each BART-eligible source that is subject to BART within the State. 

In this analysis, the State must take into consideration each available technology, the associated costs of 

compliance of each, the energy and non-air quality environmental impacts of compliance, any pollution 

control equipment in use at the source, the remaining useful life of the source, and the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such technology.1

 

The determination of BART for fossil-fuel power plants having a total generating capacity in excess of 

750 megawatts must be made pursuant to the Guidelines.

1
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PNM’s BART Analysis for NOx and PM:

PNM submitted a BART analysis for the SJGS to the Department on June 6, 2007. The BART analysis 

was performed in two stages. First, a BART analysis was performed for the consent decree technologies 

being implemented at the SJGS. In the second stage, additional control technology alternatives to the 

consent decree technologies were identified and evaluated. To determine the visibility improvements 

from both the consent decree technology upgrades and additional control technology, the Department

determined it was appropriate to review both pre-consent decree to consent decree visibility improvement 

and improvement projected from the consent decree plus additional control technologies.

Per Appendix Y to 40 CFR Part 51 – Guidelines, PNM followed the 5 Step Process in the SJGS BART 

Analysis:

Step 1 – Identify All Available Retrofit Control Technologies

Step 2 – Eliminate Technically Infeasible Options

Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies

Step 4 – Evaluate Impacts and Document the Results

a) Costs of Compliance

b) Energy Impacts

c) Air quality environmental impacts

d) Non-air environmental impacts

e) Remaining useful life

Step 5 – Evaluate Visibility Impacts

In response to the Department’s requests, PNM submitted multiple amendments to the original June 2007 

BART Analysis application. What follows is a summary of the original and additional submittals:

June 6, 2007

The original BART analysis application included a five factor analysis of NOx technology. Modeling 

analyses were performed to provide SJGS plant-wide regional haze visibility impacts at 16 Class I areas. 

These analyses were based on a constant 1 ppb background ammonia concentration and no nitrate 

repartitioning. The NOx control technologies analyzed were the Selective Catalytic Reduction (SCR) and 

SNCR/SCR Hybrid.3

November 6, 2007 

Modeling analyses were performed to provide SJGS plant-wide regional haze visibility impacts at 16 

Class I areas. The analysis was based on refinements which included using the nitrate repartitioning 

methodology and monthly variable background ammonia concentrations. Again, the NOx control 

technologies analyzed were the SCR and SNCR/SCR Hybrid.3

March 29, 2008

PNM submitted an additional discussion of cost estimation methods used to determine costs of SCR 

installation and a discussion of Nalco Mobotec ROFA and Rotamix technology.3

 

March 31, 2008

Two modeling analyses were performed to provide SJGS plant-wide and unit specific regional haze 

visibility impacts at 16 Class I areas for the SCR NOx control technology only. One of the analyses, 

believed by PNM to be the more representative of ammonia chemistry of the area, was based on the 

November 6, 2007 refinements which included using nitrate repartitioning methodology and monthly 
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variable background ammonia concentrations. The other analysis included nitrate repartitioning and a 

constant background ammonia concentration as requested by the Department.

3

May 30, 2008

Two modeling analyses were performed to provide SJGS plant-wide and unit specific regional haze 

visibility impacts at 16 Class I areas for the SNCR NOx control technology only. Similar to the March 

31, 2008 analyses, one of the analyses was based on the November 6, 2007 refinements which included 

using nitrate repartitioning methodology and monthly variable background ammonia concentrations. The 

other analysis used nitrate repartitioning methodology and constant background ammonia concentration. 

It should be noted that PNM modeled all variants of SNCR together (including Fuel Tech and Nalco 

Mobotec) as one technology called SNCR. This is the same approach that is used for modeling SCR 

control technology, where all variants are modeled generically as SCR.3

At the request of the Department, PNM and B&V also provided a five-factor BART analysis for SNCR 

technology and a discussion of coal characteristics of the coal burned at the SJGS. 

August 29, 2008 

Three modeling analyses were performed to provide SJGS plant-wide and unit specific regional haze 

visibility impacts at 16 Class I areas for the ROFA with Rotamix, Rotamix, ROFA, and WESP PM 

control technologies (the NOx and PM analyses were submitted separately). Similar to the May 30, 2008 

analyses, these analyses were also based on the November 6, 2007 refinements, which included using the 

nitrate repartitioning methodology and monthly variable background ammonia concentrations.3

At the request of the Department, PNM and B&V also provided a five-factor BART analysis of Nalco

Mobotec control technology, including ROFA, Rotamix and ROFA/Rotamix and a five-factor BART 

analysis of additional PM control technology.

3

March 16, 2009 

Four modeling analyses were performed to provide SJGS plant-wide and unit specific regional haze 

visibility impacts at 16 Class I areas. These include SCR technology, SCR/SNCR Hybrid technology,

SCR technology with sorbent injection, and SCR/SNCR Hybrid technology with sorbent injection. As 

requested by the Department, for each of these cases, the modeling also took into consideration inherent 

SO3 removal of the SO3 formed from the catalyst oxidation of SO2 to SO3.

3

February 15, 2011

A revised analysis of SNCR technology was submitted after PNM received a lower vendor-guaranteed 

emission rate from Fuel Tech, a vendor of SNCR technology. The analysis also included updated cost 

estimates for SCR, SNCR/SCR Hybrid, ROFA/Rotamix, Rotamix (SNCR), ROFA, and SNCR (Fuel 

Tech) technologies. 

The submittal further included a ratepayer impact analysis which estimated the cost impact to residential 

ratepayers from installation of SNCR and SCR technologies. 

 

One modeling analysis was performed to provide SJGS plant-wide and unit specific regional haze 

visibility impacts at 16 Class I areas assuming the revised SNCR control technology on all four units.3

April 1, 2013

This submittal compares new information as contained in a non-binding term sheet signed by the EPA, 

NMED and PNM on February 15, 2013. This update considers the emissions reductions and economic 

analysis of three specific control scenarios at SJGS, as contained in the EPA’s Federal Implementation 
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Plan, issued August 22, 2011 (SCR on all four units, or 4 SCR); the State of New Mexico’s State 

Implementation Plan, approved by the State Environmental Improvement Board on June 2, 2011 (SNCR 

on all four units, or 4 SNCR); and an alternative entitled the State Alternative Plan, not previously 

analyzed, which considers the voluntary retirement of Units 2 and 3 (SNCR on Units 1 and 4 and the 

shutdown of Units 2 and 3, or 2 SNCR/2 Shutdown).

An updated cost analysis of installing SCR control on all four units, SNCR control on all four units, and 

installing SNCR on Units 1 and 4 was prepared by Sargent & Lundy (S&L) at the request of PNM. This 

analysis reflected the approach described in the EPA’s Control Cost Manual. 

An updated visibility analysis based on the installation of SCR on all four units, SNCR on all four units, 

and SNCR on Units 1 and 4 and a two-unit shut down scenario was also submitted. This analysis is 

included in addition to the previous modeling analysis and is presented as the Updated Visibility 

Modeling Assessment Submitted April 1, 2013 of Step 5 of this document.

The updated visibility analysis for the installation of SCR on all four units and SNCR on all four units 

incorporated the SO2 and total particulate matter (TPM) emission rates of 0.15 lb/MMBtu and 0.034 

lb/MMBtu, respectively, from the current NSR Permit issued August 31, 2012. The updated visibility 

analysis for the installation of SNCR on Units 1 and 4 and a two-unit retirement incorporated the new 

TPM emission rate of 0.034 lb/MMBtu and an SO2 emission rate of 0.10 lb/MMBtu. This new SO2

emission rate will be incorporated into the facility’s NSR Permit as a federally-enforceable permit 

condition should this scenario be determined as BART for the source.

Step 1 of the BART Analysis: Identification of All Available Retrofit Emissions Control 

Technologies

NOx Control Technologies

The main strategies for reducing NOx emissions take two forms: 1) modification to the combustion 

process to control fuel and air mixing and reduce flame temperatures, and 2) post-combustion treatment 

of the flue gas to remove NOx. PNM and B&V identified the following available NOx control 

technologies and a discussion of each of the technologies:

1) Low NOx Burners, Overfire Air, and Neural Network

Low NOx burners slow and control the rate of fuel and air mixing, thereby reducing the oxygen 

availability in the ignition and main combustion zones. Overfire Air uses low excess air levels in 

the primary combustion zone with the remaining (overfire) air added higher in the furnace to 

complete combustion. Neural Network provides improvements in the heat rate and reduces

combustion-related emissions by fine-tuning the combustion process.3

 

2) Selective Non Catalytic Reduction (SNCR)

SNCR is based on the chemical reduction of the NO molecule into molecular nitrogen and water 

vapor. A nitrogen based reducing agent (reagent), such as ammonia or urea, is injected into the 

post combustion flue gas. The reduction with NO is favored over other chemical reaction 

processes at temperatures ranging between 1600F and 2100F (870C to 1150C), therefore, it is 

considered a selective chemical process.

4

3) Selective Catalytic Reduction (SCR)
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The SCR process chemically reduces the NO molecule into molecular nitrogen and water vapor

in the presence of a reducing catalyst. A nitrogen based reducing reagent such as ammonia or 

urea is injected into the ductwork, downstream of the combustion unit. The waste gas mixes with 

the reagent and enters a reactor module containing catalyst. The hot flue gas and reagent diffuse 

through the catalyst. The reagent reacts selectively with the NO within a specific temperature 

range and in the presence of the catalyst and excess oxygen.5

Sorbent injection removes SO3 in the flue gas by reaction of the SO3 with an alkaline sorbent 

material to form a particulate that is subsequently removed in a particulate control device. The 

alkaline material injected can be a magnesium, sodium, or calcium-based sorbent. The injection 

points for the reagents may vary. For this analysis, hydrated lime was selected.4

4) SNCR/SCR Hybrid

The SNCR/SCR hybrid systems use components and operating characteristics of both SNCR and 

SCR systems. Hybrid systems were developed to combine the low capital cost and high ammonia 

slip associated with SNCR systems with the high reduction potential and low ammonia slip 

inherent in the catalyst of SCR systems.3

SNCR/SCR Hybrid plus Sorbent Injection

Sorbent injection removes SO3 in the flue gas by reaction of the SO3 with an alkaline sorbent 

material to form a particulate that is subsequently removed in a particulate control device. The 

alkaline material injected can be a magnesium, sodium, or calcium-based sorbent. The injection 

points for the reagents may vary. For this analysis, hydrated lime was selected.4

5) Gas Reburn

The gas reburn process combusts auxiliary natural gas, along with coal, in the boiler. Three 

separate combustion zones in the boiler are manipulated to reduce NOx emissions.4

6) Nalco Mobotec ROFA and Rotamix

ROFA and Rotamix are proprietary control technologies developed by Nalco Mobotec. ROFA, 

or Rotating Opposed Firing Air, is a modified overfire air technology that utilizes rotation of flue 

gases and turbulent mixing to reduce NOx emissions. Rotamix is a version of SNCR technology 

and operates under the same principles as other SNCR technology.3

 

7) NOxStar

NOxStar is the trademarked name for a NOx control technology that involves the injection of 

ammonia and a hydrocarbon (typically natural gas) into the flue gas path of a coal-fired boiler at 

around 1600F to 1800F for the reduction of NOx.3

 

8) ECOTUBE

The ECOTUBE system utilizes retractable lance tubes that penetrate the boiler above the primary 

combustion burner zone and inject high-velocity air as well as reagents. The lance tubes work to 
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create turbulent airflow and to increase the residence time for the air/fuel mixture. In principle, 

the OFA and SNCR processes are combined in this technology.3

 

9) PowerSpan ECO

The PowerSpan ECO system is a multi-pollutant technology with limited experience. The 

PowerSpan ECO system is located downstream of an existing particulate control device and treats 

the power plant’s flue gas in three process steps to achieve multi-pollutant removal of sulfur 

dioxide (SO2), nitrogen oxides (NOx), oxidized mercury, and fine particulate matter.3

 

10) Phenix Clean Combustion

The Phenix Clean Combustion System is an advanced hybrid coal gasification/combustion 

process that prevents the formation of NOx and SO2 emissions when burning coal.3

 

11) e-SCRUB

The e-SCRUB process is similar to the PowerSpan technology in that it uses an energy source to 

oxidize pollutants in the flue gas. However, there are some variations in the oxidation energy 

source and the byproduct recovery systems.

PM Control Technologies

 

Particulate matter emissions can only be controlled by post-combustion control technologies. PNM 

identified the following technologies as available in their BART analysis for PM.

1) Flue Gas Conditioning with Hot-Side ESP

Flue gas conditioning improves the collection efficiency of particulate matter in the ESP. Flue 

gas leaving the air heater into the ESP can be conditioned by addition of ionic compounds, such 

as SO3 or ammonia. These compounds combine with the moisture in the flue gas and are 

deposited on the surface of the fly ash particles. This will increase the conductivity of the fly ash 

and make it more suitable for capture.3

2) Pulse Jet Fabric Filter (PJFF)

In PJFFs, the flue gas typically enters the compartment hopper and passes from the outside of the 

bag to the inside of the bag, depositing particulate on the outside of the bag. To prevent collapse 

of the bag, a metal cage is installed on the inside of the bag. The flue gas passes up through the 

center of the bag into the output plenum. Cleaning is performed by initiating a downward pulse 

of air into the top of the bag. The pulse causes a ripple effect along the length of the bag. This 

releases the dust cake from the bag’s exterior surface, allowing the dust to fall into the hopper.3

3) Compact Hybrid Particulate Collector

A variant of the PJFF is the compact hybrid particulate collector. This is a high air to cloth (A/C)

ratio fabric filter installed downstream of existing particulate collection devices where the 

majority of PM has been removed.3

 

4) Max-9 Electrostatic Fabric Filter
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The Max-9 filter is essentially a high-efficiency PJFF utilizing a discharge electrode as in an ESP. 

However, there are no collector plates. When the dust particles are charged, they are attracted to 

the grounded metal cage inside the filter element, just as they would be attracted to the collecting 

plates in an ordinary precipitator.3

 

Step 2 of the BART Analysis: Eliminate Technically Infeasible Control Technologies

NOx Control Technologies

PNM excluded several of the identified NOx controls due to technical infeasibility. In the BART analysis 

application, PNM excluded the following NOx control technologies:

1) Selective Non-Catalytic Reduction

PNM determined in its submittal of June 6, 2007 that SNCR technology was technically 

infeasible because the technology was unable to meet the presumptive limits for NOx; determined 

by EPA to be 0.23 lb NOx/MMBtu for dry bottom, wall-fired boilers burning sub-bituminous 

coal. A vendor estimated that the technology could only achieve 0.24 lb NOx/MMBtu. In order 

for the technology to achieve the presumptive limit, PNM stated that ammonia slip limit would 

need to be raised from 5 ppm to 10 ppm, and that this higher ammonia slip posed additional 

operational problems. 

The Department did not agree with PNM’s argument that because SNCR could not meet the 

presumptive limits the technology should be eliminated as technically infeasible. Therefore the 

Department requested PNM to perform the complete 5-factor BART analysis required by the 

Guidelines on SNCR. PNM submitted the five-factor analysis of SNCR in a subsequent 

submittal dated May 30, 2008, an updated analysis of Fuel Tech’s SNCR on February 11, 2011, 

and an additional updated analysis on April 1, 2013. 

2) Natural Gas Reburn

PNM determined that the current boiler space inhibits sufficient residence time for the natural gas 

reburn zone. The Department accepts PNM’s elimination of this technology due to space 

limitations. 

3) Nalco Mobotec ROFA and Rotamix

PNM determined the Rotamix technology was technically infeasible due to limited application at 

coal-fired boilers equivalent to the size of Units 1-4 at SJGS. PNM determined ROFA 

technology was technically infeasible because ROFA is a variant of OFA, which at the time was 

being installed at Units 1-4 at SJGS.

The Department did not agree with PNM’s position that Rotamix has limited application at coalfired boilers equivalent to the size of Units 1-4 at SJGS. The Department did not agree that 

because ROFA is a variant of OFA, the technology can be eliminated as technically infeasible. 

Therefore, the Department requested PNM perform the complete 5-factor analysis for ROFA and 

Rotamix. PNM performed the analysis and submitted the analysis in two subsequent submittals

dated March 29, 2008 and August 29, 2008.
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4) NOxStar

NOxStar currently has only one major installation in the US. In addition, PNM stated that in 

recent discussions the supplier has identified limited ability and willingness to market the 

commercial technology. The Department agrees that this technology has limited application to 

large coal-fired boilers and is not technically feasible.

5) ECOTUBE

The ECOTUBE technology has been demonstrated on industrial/small boilers firing solid waste, 

wood, and biomass.3

 ECOTUBE has limited application to boilers similar to Units 1-4 at the 

SJGS. The Department agrees that this technology has limited application to large coal-fired 

boilers and is not technically feasible.

6) PowerSpan

PowerSpan has not been demonstrated on large boilers, such as Units 1-4 at SJGS. The 

Department agrees that this technology has limited application to large coal-fired boilers and is 

not technically feasible.

7) Phenix Clean Combustion

PNM determined that the Phenix Clean Combustion system is still in the demonstration and 

testing stage and there are no commercial retrofits at facilities similar to SJGS. The Department

agrees that this technology has no demonstrated application to the source type and is not 

technically feasible.

8) e-SCRUB

PNM determined that the e-SCRUB technology has only one known medium scale installation 

with limited data. The Department agrees that the technology should be considered technically 

infeasible due to limited demonstrated applications.

PM Control Technologies

PNM excluded the following PM control technologies as technically infeasible:

1) Flue Gas Conditioning with Hot-Side ESP

Flue gas conditioning does improve collection efficiencies, but will not achieve an emission limit 

lower than the current PM limit in their air quality permit. The Department agrees that flue gas 

conditioning control technology should not be considered in the BART analysis. Because the 

vendor was unable to guarantee a lower emission rate, the technology does not need to undergo 

the three additional factors of the five factor analysis. 

2) Compact Hybrid Particulate Collector

The compact hybrid particulate collector does not provide a performance guarantee lower than 

the current permitted limit for PM. The Department agrees that the compact hybrid PM control 

technology should not be considered in the BART analysis. Because the vendor was unable to 
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guarantee a lower emission rate, the technology does not need to undergo the three additional 

factors of the five factor analysis. 

3) Max-9 Electrostatic Fabric Filter

The Max-9 electrostatic fabric filter has been installed in a small-sized utility boiler, but there are 

no commercial installations of a similar size to Units 1-4 at SJGS. The Department agrees that 

the limited application of this technology to large utility boilers justifies removing the technology 

as technically infeasible.

During the Department review of available PM control technologies, the Department requested PNM to 

perform a complete five-factor BART analysis on Wet Electrostatic Precipitator (WESP). The 

Department believes this technology should have been identified as technically feasible in Step 1 of the 

PM BART analysis. PNM performed a complete five-factor BART analysis on WESP and PJFF and 

submitted a report in a subsequent submittal dated August 28, 2008.

Step 3 of the BART Analysis: Evaluate Control Effectiveness of Remaining Control Technologies

PNM contracted with B&V and S&L to determine the control effectiveness of each remaining available 

NOx and PM control technology for Units 1-4. The control efficiencies of each of the NOx control 

technologies are summarized in Tables 2 – 5, and the control efficiencies of the PM control technologies 

are summarized in Tables 6 – 9.

Table 2: NOx Control Effectiveness for Unit 1

Control Technology Control 

Efficiency

(%)

Baseline 

Emissions

(tpy)

Emissions 

Reduction

(tpy)

Controlled 

Emission Rate

(lb/MMBtu)

Controlled 

Emission Rate

(tpy)

Pre-Consent Decree 

(Pre-CD)

NA NA NA 0.43 5394

CD 23 5394 1254 0.30 4140

ROFA 13 4140 552 0.26 3588

Rotamix (SNCR) 23 4140 966 0.23 3174

SNCR 23 4140 966 0.23 3174

ROFA/Rotamix 33 4140 1380 0.20 2760

SCR/SNCR Hybrid 40 4140 1656 0.18 2484

SCR 83 4140 3450 0.05 690
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Table 3: NOx Control Effectiveness for Unit 2

Control Technology Control 

Efficiency

(%)

Baseline 

Emissions

(tpy)

Emissions 

Reduction

(tpy)

Controlled 

Emission Rate

(lb/MMBtu)

Controlled 

Emission Rate

(tpy)

Pre-Consent Decree 

(Pre-CD)

NA NA NA 0.45 6179

CD 33 6179 2060 0.30 4119

ROFA 13 4119 549 0.26 3570

Rotamix (SNCR) 23 4119 961 0.23 3158

SNCR 23 4119 961 0.23 3158

ROFA/Rotamix 33 4119 1373 0.20 2746

SCR/SNCR Hybrid 40 4119 1648 0.18 2471

SCR 83 4119 3432 0.05 687

Table 4: NOx Control Effectiveness for Unit 3

Control Technology Control 

Efficiency

(%)

Baseline 

Emissions

(tpy)

Emissions 

Reduction

(tpy)

Controlled 

Emission Rate

(lb/MMBtu)

Controlled 

Emission Rate

(tpy)

Pre-Consent Decree 

(Pre-CD)

NA NA NA 0.42 9004

CD 29 9004 2573 0.30 6431

ROFA 13 6431 857 0.26 5574

Rotamix (SNCR) 23 6431 1500 0.23 4931

SNCR 23 6431 1500 0.23 4931

ROFA/Rotamix 33 6431 2144 0.20 4287

SCR/SNCR Hybrid 40 6431 2572 0.18 3859

SCR 83 6431 5359 0.05 1072

Table 5: NOx Control Effectiveness for Unit 4

Control Technology Control 

Efficiency

(%)

Baseline 

Emissions

(tpy)

Emissions 

Reduction

(tpy)

Controlled 

Emission Rate

(lb/MMBtu)

Controlled 

Emission Rate

(tpy)

Pre-Consent Decree 

(Pre-CD)

NA NA NA 0.42 8833

CD 29 8833 2524 0.30 6309

ROFA 15 6309 841 0.26 5468

Rotamix (SNCR) 23 6309 1472 0.23 4837

SNCR 23 6309 1472 0.23 4837

ROFA/Rotamix 33 6309 2103 0.20 4206

SCR/SNCR Hybrid 40 6309 2524 0.18 3786

SCR 83 6309 5257 0.05 1052

Table 6: PM Control Effectiveness for Unit 1 

Control Technology Control 

Efficiency

(%)

Baseline 

Emissions

(tpy)

Emissions 

Reduction

(tpy)

Controlled 

Emission Rate

(lb/MMBtu)

Controlled 

Emission Rate

(tpy)

Pre-Consent Decree 

(Pre-CD)

NA NA NA 0.050 690

PJFF (CD) 70 690 483 0.015 207

WESP 33 207 69 0.010 138
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Table 7: PM Control Effectiveness for Unit 2 

Control Technology Control 

Efficiency

(%)

Baseline 

Emissions

(tpy)

Emissions 

Reduction

(tpy)

Controlled 

Emission Rate

(lb/MMBtu)

Controlled 

Emission Rate

(tpy)

Pre-Consent Decree 

(Pre-CD)

NA NA NA 0.050 687

PJFF (CD) 70 687 481 0.015 206

WESP 33 206 69 0.010 137

Table 8: PM Control Effectiveness for Unit 3 

Control Technology Control 

Efficiency

(%)

Baseline 

Emissions

(tpy)

Emissions 

Reduction

(tpy)

Controlled 

Emission Rate

(lb/MMBtu)

Controlled 

Emission Rate

(tpy)

Pre-Consent Decree 

(Pre-CD)

NA NA NA 0.050 1072

PJFF (CD) 70 1072 750 0.015 322

WESP 33 322 108 0.010 214

Table 9: PM Control Effectiveness for Unit 4 

Control Technology Control 

Efficiency

(%)

Baseline 

Emissions

(tpy)

Emissions 

Reduction

(tpy)

Controlled 

Emission Rate

(lb/MMBtu)

Controlled 

Emission Rate

(tpy)

Pre-Consent Decree 

(Pre-CD)

NA NA NA 0.050 1052

PJFF (CD) 70 1052 737 0.015 315

WESP 33 315 105 0.010 210

Step 4 of the BART Analysis: Perform Impacts Analysis of Remaining Control Technologies

The Guidelines require states to consider four types of impact analysis in Step 4 of the BART analysis. 

These four types of impacts consider the costs of compliance, energy impacts, non-air quality 

environmental impacts, and remaining useful life of the facility. These impacts are included in the costeffectiveness of each additional control technology and allow comparisons to be made between the 

remaining controls. B&V performed an impact analysis for the remaining NOx and PM control 

technologies in accordance with the Guidelines.

B&V and S&L prepared the design parameters and developed estimates of capital and annual costs for 

applications of SCR, SNCR, SCR/SNCR Hybrid, ROFA, Rotamix, ROFA/Rotamix, PJFF, and WESP 

technologies. B&V relied on a number of sources to prepare the design parameters, including 

information from the Nalco Mobotec equipment vendors, SCR and SNCR equipment vendors, EPA cost 

manuals, engineering and performance data, and B&V’s own in-house engineering estimates. 

PNM evaluated the energy impacts, non-air quality environmental impacts, and remaining useful life of 

all additional technically feasible control options for NOx and PM. Energy impacts from control 

equipment that consume auxiliary power during operation were considered for all control options. For 

SCR, SNCR and SCR/SNCR Hybrid technology, the non-air quality environmental impacts included the 

consideration of water usage and waste generated from each control technology. For WESP technology, 

PNM considered the auxiliary power consumption to operate the WESP and fans, and the additional water 

consumption and waste water disposal requirements from operating the WESP. Lastly, the remaining 

useful life was defined as 20 years, except for the 2013 analysis for 4 SCR, 4 SNCR and 2 SNCR/2 
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Shutdown which used a remaining useful life of 30 years. Therefore, no additional cost adjustments for a 

short remaining useful boiler life need to be considered. The results of the impact analyses for additional 

NOx and PM control technologies are summarized in Tables 10 and 11 on the following pages.

Following the initial submittal, the Department made additional requests for information on the impact 

analysis for SCR, SNCR, ROFA, Rotamix and WESP, and for further consideration of inherent and 

additional control of SO3 from both the SCR and SCR/SNCR Hybrid technology. 

SCR Costs

The Department reviewed the original cost analysis for SCR technology and subsequently requested that 

PNM provide additional information on the basis of their cost analysis of SCR technology. In response to 

the request, B&V provided additional clarification for the cost analysis for SCR technology and submitted 

it to the Department on March 29, 2008. The submittal discussed how the OAQPS cost control manual is 

an insufficient method for determining actual costs of retrofitting the SJGS with SCR and provided a 

comparison between cost estimation based on the OAQPS manual and the B&V provided estimate.

In April, 2013, PNM submitted an updated cost analysis of SCR prepared by S&L. PNM contracted with 

S&L to prepare a conceptual design, project cost estimate and technical portions of an Engineer, 

Procurement, and Construction plan. S&L used budgetary quotes from equipment vendors for the major 

components and S&L’s in-house database of equipment and material costs for similar projects. For the 

revised 2013 analysis for 4 SCR, 4 SNCR, and 2 SNCR/2 Shutdown, the capital cost estimates are stated 

in 2013 dollars. The previously submitted cost analyses for other alternatives used 2010 dollars. Because 

the rate of inflation between 2013 and 2010 was minimal (1.07 percent), the costs are comparable. 

Consideration of SO3 Control

PNM’s initial analysis of SCR and SCR/SNCR technology took into consideration additional oxidation of 

SO2 to SO3 across the SCR catalyst bed. The Department requested PNM to consider inherent removal of 

SO3 emissions from existing air pollution control equipment, and removal of SO3 emissions through 

installation of sorbent injection. PNM responded with an amended submittal addressing both inherent 

and add-on removal of SO3. PNM’s submittal provided cost estimates of the sorbent injection system and 

updated visibility modeling for both SCR and SCR/SNCR Hybrid technologies.

[The Department understands that there are SCR catalysts now on the market that are capable of a much 

smaller SO2 to SO3 conversion (around 0.5%) as opposed to the assumed 1%. The Department believes 

use of such a catalyst will minimize SO3 oxidation to less than what was represented in PNM’s analysis.] 

The updated 2013 analysis of 4 SCR, 4 SNCR, and 2 SNCR/2 Shutdown uses EPA estimates of SO3

emissions from the 2011 EPA Federal Implementation Plan (FIP) analysis.

SNCR, WESP, ROFA, and Rotamix Review

PNM provided additional impact analyses of SNCR, WESP, ROFA, and Rotamix technologies and 

submitted those updates to the Department. Please refer to the Chronology of Submissions located earlier 

in this document for an overview of the specific updates to these technologies.
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Table 10: Impact Analysis and Cost Effectiveness of Additional NOx Control Technologies

Control 

Technology

Emission 

Performance 

Level 

(lb/MMBtu)

Expected 

Emission 

Rate (tpy)

Expected 

Emission 

Reduction 

(tpy)

Total Capital 

Investment 

(TCI) (1,000$)

Total 

Annualized 

Cost 

(TAC) (1,000$)

Cost 

Effectiveness 

($/ton) 

Incremental 

Cost 

Effectiveness 

($/ton)

Energy 

Impacts 

(1,000$)

Non-Air 

Impacts 

(1,000$)

Unit 1

SCR + sorbent

(FIP) 0.05 690 3,450 180,862 22,165 6,425 6,749 746 NA1

SNCR/SCR 

Hybrid 0.18 2,484 1,656 110,683 16,816 10,154 35,917 706 1,762

ROFA/Rotamix 0.20 2,760 1,380 30,790 6,902 5,001 7,982 1,413 3

Rotamix 

(SNCR) 0.23 3,174 966 11,822 3,597 3,723 116 51 4

SNCR 0.23 3,174 966 17,392 5,400 5,590 80 43 NA1

ROFA 0.26 3,588 552 19,256 3,549 6,429 -- 1,363 NA1

Consent Decree 0.30 4,140 1,254 14,580 1,422 1,134 NA NA1 NA1

Pre-CD 0.43 5,394 NA NA NA NA NA NA NA1

Unit 2

SCR + sorbent

(FIP) 0.05 687 3,433 203,360 24,562 7,157 7,755 729 NA1

SNCR/SCR 

Hybrid 0.18 2,471 1,648 115,151 17,306 10,503 37,887 346 1,762

ROFA/Rotamix 0.20 2,746 1,373 30,790 6,902 5,027 8,024 1,413 3

Rotamix 

(SNCR) 0.23 3,158 961 11,822 3,597 3,742 117 51 4

SNCR 0.23 3,158 961 17,392 5,400 5,618 80 43 NA1

ROFA 0.26 3,570 549 19,256 3,549 6,462 -- 1,363 NA1

Consent Decree 0.30 4,119 2,060 14,126 1,378 669 NA NA1 NA1

Pre-CD 0.45 6,179 NA NA NA NA NA NA NA1

Unit 3

SCR + sorbent

(FIP) 0.05 1,072 5,359 264,208 32,585 6,080 6,313 1,107 NA1

SNCR/SCR 

Hybrid 0.18 3,859 2,572 178,759 26,604 10,342 39,171 507 2,658

ROFA/Rotamix 0.20 4,287 2,144 35,724 9,810 4,576 7,498 2,810 5

Rotamix 

(SNCR) 0.23 4,931 1,501 13,919 4,988 3,324 -378 84 5

SNCR 0.23 4,931 1,501 17,163 8,224 5,480 -578 51 NA1

ROFA 0.26 5,574 857 22,081 5,231 6,100 -- 2,725 NA1

Consent Decree 0.30 6,431 2,573 12,715 1,240 482 NA NA1 NA1

Pre-CD 0.42 9,004 NA NA NA NA NA NA NA1

Unit 4

SCR + sorbent

(FIP) 0.05 1,052 5,257 235,940 29,508 5,613 5,623 1,102 NA1

SNCR/SCR 

Hybrid 0.18 3,786 2,524 171,412 25,808 10,226 38,034 507 2,658

ROFA/Rotamix 0.20 4,206 2,103 35,724 9,810 4,664 7,643 2,810 5

Rotamix 

(SNCR) 0.23 4,837 1,472 13,919 4,988 3,388 -385 84 5

SNCR 0.23 4,837 1,472 17,163 8,224 5,587 -590 51 NA1

ROFA 0.26 5,468 841 22,081 5,231 6,218 -- 2,725 NA1

Consent Decree 0.30 6,309 2,524 12,870 1,256 498 NA NA1 NA1

Pre-CD 0.42 8,833 NA NA NA NA NA NA NA1

1 PNM performed an impact analysis for these technologies and incorporated any monetized energy or non-air environmental impacts into the 

cost analysis.
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Table 11: Impact Analysis and Cost Effectiveness of Additional PM Control Technologies

1 PNM performed an impact analysis for these technologies and incorporated any monetized energy or non-air environmental impacts

into the cost analysis.

Step 5 of the BART Analysis: Visibility Impacts Analysis of Remaining Control Technologies

The Guidelines require states to assess visibility improvement based on the modeled change in visibility 

impacts for the pre-control and post-control emission scenarios. 

The objective of this source-specific, refined modeling analysis report is to describe the methodologies 

and procedures of visibility modeling to support the BART engineering analysis for PNM’s SJGS Units 

1, 2, 3, and 4. These units were identified as subject-to-BART by the Department based on BART 

screening exemption modeling conducted by the Western Regional Air Partnership’s (WRAP) Regional 

Modeling Center (RMC). Based on the results of the WRAP screening modeling, PNM SJGS was 

required to conduct a refined BART analysis that included CALPUFF visibility modeling for the facility. 

The modeling approach followed the requirements described in the WRAP’s BART modeling protocol, 

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

United States dated August 15, 2006.

 

The CALPUFF modeling system is described below, followed by a description of the modeling analysis 

performed in 2011, and, finally, by a description of the updated modeling performed in 2013 that takes 

Control 

Technology

Emission 

Performance 

Level 

(lb/MMBtu)

Expected 

Emission 

Rate (tpy)

Expected 

Emission 

Reduction 

(tpy)

Total Capital 

Investment 

(TCI) (1,000$)

Total 

Annualized 

Cost (TAC) 

(1,000$)

Incremental 

Cost 

Effectiveness 

($/ton)

Cost 

Effectiveness

($/ton) 

Energy 

Impacts 

(1,000$)

Non-Air 

Impacts 

(1,000$)

Unit 1

WESP 0.010 138 69 99,308 11,855 20,696 171,812 1,112 NA1

PJFF 

(CD)

0.015 207 483 67,072 10,427 NA 21,588 4,488 NA1

Pre-CD 0.050 690 NA NA NA NA NA NA NA

Unit 2

WESP 0.010 137 70 99,663 11,895 16,157 169,929 1,112 NA1

PJFF 

(CD)

0.015 207 480 69,840 10,764 NA 22,425 4,488 NA1

Pre-CD 0.050 687 NA NA NA NA NA NA NA

Unit 3

WESP 0.010 214 108 129,565 15,558 28,741 144,056 1,728 NA1

PJFF 

(CD)

0.015 322 750 72,696 12,454 NA 16,605 6,895 NA1

Pre-CD 0.050 1072 NA NA NA NA NA NA NA

Unit 4

WESP 0.010 210 105 130,012 15,609 29,352 148,657 1,728 NA1

PJFF 

(CD)

0.015 315 737 73,328 12,527 NA 16,997 6,895 NA1

Pre-CD 0.050 1052 NA NA NA NA NA NA NA
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into consideration the State Alternative (2 SNCR/2 Shutdown), and compares it to the state’s 2011 NOx 

BART determination of 4 SNCRs and the EPA FIP BART determination of 4 SCRs.

CALPUFF System

The CALPUFF modeling system consists of a meteorological data pre-processor (CALMET), an air 

dispersion model (CALPUFF), and post-processor programs (POSTUTIL, CALSUM, CALPOST). The 

CALPUFF model was developed as a non-steady-state air quality modeling system for assessing the 

effects of time-varying and space-varying meteorological conditions on pollutant transport, 

transformation, and removal.

CALMET is a diagnostic wind model that develops hourly wind and temperature fields in a threedimensional, gridded modeling domain. Meteorological inputs to CALMET can include surface and 

upper-air observations from multiple meteorological monitoring stations. Additionally, the CALMET 

model can utilize gridded analysis fields from various mesoscale models such as MM5 to better represent 

regional wind flows and complex terrain circulations. Associated two-dimensional fields such as mixing 

height, land use, and surface roughness are included in the input to CALMET. The CALMET model 

allows the user to “weight” various terrain influence parameters in the vertical and horizontal directions 

by defining the radius of influence for surface and upper-air stations.

CALPUFF is a multi-layer, Lagrangian puff dispersion model. CALPUFF can be driven by the threedimensional wind fields developed by the CALMET model (refined mode), or by data from a single 

surface and upper-air station in a format consistent with the meteorological files used to drive steady-state 

dispersion models. All far-field modeling assessments described here were completed using the 

CALPUFF model in the refined mode.

CALSUM is a post-processing program that can operate on multiple CALPUFF output files to combine 

the results for further post-processing. POSTUTIL is a post-processing program that combines the

concentrations, wet and dry deposition flux files created by CALPUFF to calculate the total nitrogen and 

total sulfur deposition fluxes from nitrogen dioxide (NO2), nitrates (NO3

-

), nitric acid (HNO3), sulfur 

dioxide (SO2) and sulfates (SO4

2-

). CALPOST is a post-processing program that can read the CALPUFF 

(or POSTUTIL or CALSUM) output files and calculate the impacts to visibility.

The 2011 refined CALPUFF modeling was conducted with the version of the CALPUFF system 

recommended by the WRAP BART modeling protocol. The 2013 refined CALPUFF modeling was 

conducted with the version of the CALPUFF system recommended by the EPA Version designations of 

the key programs listed in Table 12.

Table 12: CALPUFF System Used

2011 Modeling 2013 Modeling

Version Level Version Level

CALMET 6.211 060414 5.8 070623

CALPUFF 6.112 060412 5.8 070623

POSTUTIL 1.52 060412 1.56 070627

CALSUM 1.33 051122 1.33 051122

CALPOST 6.131 060410 6.221 080724
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Meteorological Data Processing (CALMET)

The CALMET model was used to construct an initial three-dimensional windfield using data from the 

MM5 model. Surface and upper-air data were input to CALMET to adjust the initial windfields. Because 

the MM5 data were afforded to simulate atmospheric variables on the CALMET windfields, the daily 

MM5 meteorological data files provided by the WRAP RMC for the years 2001, 2002, and 2003 were 

utilized as input into CALMET for the 2011 analysis. In the 2013 updated analysis, surface, upper air, 

precipitation, and MM5 data were provided by EPA. Locations of the observations that were input to 

CALMET for both the 2011 analysis and the 2013 analysis, including surface and precipitation stations, 

are shown in Figures 1 and 2. Default settings were used in the CALMET input files for most of the 

technical options. Table 13 lists the key user-defined CALMET settings that were selected.

Figure 1: Surface Stations
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Figure 2: Precipitation Stations
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Table 13: Key User-Defined CALMET Settings

Variable Description Value

2011 Analysis 2013 Analysis

PMAP Map projection LCC LCC

DGRIDKM Grid spacing (km) 4 4

NZ Number of layers 11 11

ZFACE Cell face heights (m)

0, 20, 100, 200, 350, 

500, 750, 1000,

2000, 3000, 4000, 

5000

0, 20, 100, 200, 350, 

500, 750, 1000, 

2000, 3000, 4000, 

5000

NOOBS 1=Use of surface and precipitation (no upper air 

observations); use MM5 for upper air data 1 0

IEXTRP Extrapolate surface wind obs to upper level 1 -4

RMIN2 Minimum distance for extrapolation 4 4

IPROG Use gridded prognostic model output 14 14

RMAX1 Maximum radius of influence (surface layer, 

km) 50 100

RMAX2 Maximum radius of influence (layers aloft, km) 100 200

TERRAD Radius of influence for terrain (km) 10 10

R1 Relative weighting of first guess wind field and 

observation (km) 100 50

R2 Relative weighting aloft (km) 200 100

ITPROG 3D temperature from observations or from 

MM5 1 0

CALPUFF Modeling Setup

To allow chemical transformations within CALPUFF using the recommended chemistry mechanism 

(MESOPUFF II), the model required input of background ozone and ammonia concentrations. 

Background ozone concentrations are important for the photochemical conversion of SO2 and NOx to 

SO4 and NO3, respectively. In the 2011 analysis, for ozone, the hourly ozone concentration files that 

were used by the WRAP RMC in the initial modeling were used for the BART technology evaluation. 

In addition to the hourly ozone data, the same monthly average background ozone value of 80 ppb that 

was used in the initial modeling was used in this modeling for times when hourly ozone data were not 

available. In the 2013 analysis, the hourly ozone concentrations files that came directly from EPA were 

used and the ozone concentration of 80 ppb was used for the missing hours in the ozone data files.

For ammonia, in the 2011 analysis, the monthly variable background ammonia concentrations were used 

for the BART modeling analysis. They are as follows:
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Table 14: Ammonia Background Concentration (ppb)

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

0.2 0.2 0.5 0.5 1.0 1.0 1.0 1.0 1.0 0.5 0.5 0.2

In the 2013 analysis, a constant ammonia background concentration of 1.0 ppb was used.

There are many Class I areas within and surrounding New Mexico. On the basis of distance from BART 

applicable sources, topography, and meteorology, the screening modeling conducted by WRAP RMC 

determined that 16 Class I areas needed to be addressed in the BART analysis. The applicable Class I 

areas included in the BART analysis are located within 300 km of the SJGS facility. As shown in Figure 

3, the nearest Class I area is Mesa Verde National Park, located approximately 40 km north of the facility 

and the most distant Class I area is Grand Canyon National Park, located approximately 300 km west of 

the facility. All Class I area distances from the facility fall within the range recommended for CALPUFF 

application. The 16 Class I areas are identified in Table 15 and an illustration of the receptors used in the

2011 and 2013 modeling analyses for each Class I area is provided in Appendix B. The CALPUFF 

analyses used an array of discrete receptors with receptor elevations for the Class I areas, which were 

created and distributed by the National Park Service (NPS).

Figure 3: Location of SJGS and the Class I Area
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Table 15: Class I Areas

1. Mesa Verde National Park (MEVE) 9. West Elk Wilderness (WEEL)

2. Weminuche Wilderness (WEMI) 10. Arches National Park (ARCH)

3. San Pedro Parks Wilderness (SAPE) 11. Capitol Reef National Park (CARE)

4. La Garita Wilderness (LAGA) 12. Pecos Wilderness (PECO)

5. Canyonlands National Park (CANY) 13. Wheeler Peak Wilderness (WHPE)

6. Black Canyon of the Gunnison National Park (BLCA) 14. Great Sand Dunes National Park (GRSA)

7. Bandelier National Monument (BAND)

8. Petrified Forest National Park (PEFO)

15. Maroon Bells-Snowmass Wilderness 

(MABE)

16. Grand Canyon National Park (GRCA)

CALPUFF Inputs – Pre-Consent Decree, Baseline and Control Options

Source release parameters and emissions for pre-consent decree, baseline and control options for each unit 

are shown in Tables 16 through 19. [The following notes apply to each of these tables:]

(1)Emissions levels (lb/MMBtu) are shown on an annual average basis.

(2)Emissions (lb/hr) calculations were based on the emissions level (lb/MMBtu) and design heat basis.

(3)Emissions levels listed were based on performance guarantees provided by the equipment vendor.

(4) For the 2011 analysis, H2SO4 is assumed to be 100 percent of the SO4 emissions calculated by the NPS 

Speciation Spreadsheet. The 2013 analysis utilizes the Electric Power Research Institute (EPRI) 

methodology.
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Table 16: CALPUFF Inputs for Unit 1

Model Input Data

2011 Analysis 2013 Analysis

PreConsent 

Decree

Consent 

Decree

Rotamix 

or 

ROFA/

ROFA SCR/SNC

R Hybrid

SCR 

with 

Sorbent

Baseline

[EPA 

FIP]

4 SCR

[NMED 

SIP]

4 SNCR

[State 

Alternative]

2 SNCR/2 

SNCR Rotamix Shutdown

Hourly Heat Input 

(MMBtu/hour) 3707 3707 3707 3707 3707 3707 3707 3707 3707 3707 3707

Sulfur Dioxide 

(SO2) (lb/MMBtu) 0.24 0.18 0.18 0.18 0.18 0.18 0.18 0.15 0.15 0.15 0.10

Sulfur Dioxide 

(SO2) (lb/hr) 877.8 667.3 667.3 667.3 667.3 667.3 667.3 556.1 556.1 556.1 370.7

Nitrogen Oxide 

(NOx) (lb/MMBtu) 0.43 0.33 0.23 0.2 0.26 0.18 0.07 0.30 0.05 0.23 0.23

Nitrogen Oxide 

(NOx) (lb/hr) 1592 1223.3 852.6 741.4 963.8 667.3 259.5 1112.1 185.4 852.6 852.6

PM (lb/MMBtu) 0.05 0.015 0.015 0.015 0.015 0.015 0.015 0.034 0.034 0.034 0.034

PM (lb/hr) 185.4 55.6 55.6 55.6 55.6 55.6 55.6 126.04 126.04 126.04 126.04

SO3 as Sulfuric 

Acid (H2SO4) 

(lb/MMBtu)

0.013 0.011 0.011 0.011 0.011 0.031 0.004 4.6E-05 0.00026 4.6E-05 4.6E-05

SO3 as Sulfuric 

Acid (H2SO4)

(a)

(lb/hr)

50 40.5 40.5 40.5 40.5 114.2 16.1 0.17 0.96 0.17 0.17

Stack Conditions

Stack Height 

(meters) 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92

Stack Exit Diameter 

(meters) 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.10 6.10 6.10 6.10

Stack Exit Temp.

(Kelvin) 336 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83

Stack Exit Velocity 

(m/s) 22.6 21.34 21.34 21.34 21.34 21.34 21.34 21.34 21.34 21.34 21.34
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Table 17: CALPUFF Inputs for Unit 2

Model Input Data

2011 Analysis 2013 Analysis

PreConsent 

Decree

Consent 

Decree

Rotamix 

or

ROFA/

ROFA SCR/SNCR 

Hybrid

SCR 

with 

Sorbent

Baseline

[EPA 

FIP]

4 SCR

[NMED 

SIP]

4 SNCR

[State 

Alternative]

2 SNCR/2 

SNCR Rotamix Shutdown

Hourly Heat Input 

(MMBtu/hour) 3688 3688 3688 3688 3688 3688 3688 3688 3688 3688 3688

Sulfur Dioxide 

(SO2) (lb/MMBtu) 0.23 0.18 0.18 0.18 0.18 0.18 0.18 0.15 0.15 0.15 0

Sulfur Dioxide 

(SO2) (lb/hr) 844 663.8 663.8 663.8 663.8 663.8 663.8 553.2 553.2 553.2 0

Nitrogen Oxide 

(NOx) (lb/MMBtu) 0.45 0.33 0.23 0.2 0.26 0.18 0.07 0.30 0.05 0.23 0

Nitrogen Oxide 

(NOx) (lb/hr) 1649.3 1217 848.2 737.6 958.9 663.8 258.2 1106.4 184.4 848.2 0

PM (lb/MMBtu) 0.05 0.015 0.015 0.015 0.015 0.015 0.015 0.034 0.034 0.034 0

PM (lb/hr) 184.4 55.3 55.3 55.3 55.3 55.3 55.3 125.39 125.39 125.39 0

SO3 as Sulfuric 

Acid (H2SO4) 

(lb/MMBtu)

0.013 0.011 0.011 0.011 0.011 0.031 0.004 4.6E-05 0.00026 4.6E-05 0

SO3 as Sulfuric 

Acid (H2SO4)

(a)

(lb/hr)

49.7 40.3 40.3 40.3 40.3 113.6 16 0.17 0.96 0.17 0

Stack Conditions

Stack Height 

(meters) 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 0

Stack Exit Diameter 

(meters) 6.096 6.096 6.096 6.096 6.096 6.096 6.096 6.10 6.10 6.10 0

Stack Exit Temp.

(Kelvin) 338 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83 0

Stack Exit Velocity 

(m/s) 23.5 21.34 21.34 21.34 21.34 21.34 21.34 21.34 21.34 21.34 0
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Table 18: CALPUFF Inputs for Unit 3

Model Input Data

2011 Analysis 2013 Analysis

PreConsent 

Decree

Consent 

Decree

Rotamix

or

SNCR

ROFA/

Rotamix ROFA SCR/SNCR 

Hybrid

SCR 

with 

Sorbent

Baseline

[EPA 

FIP]

4 SCR

[NMED 

SIP]

4 SNCR

[State 

Alternative]

2 SNCR/2 

Shutdown

Hourly Heat Input 

(MMBtu/hour) 5758 5758 5758 5758 5758 5758 5758 5758 5758 5758 5758

Sulfur Dioxide (SO2) 

(lb/MMBtu) 0.28 0.18 0.18 0.18 0.18 0.18 0.18 0.15 0.15 0.15 0

Sulfur Dioxide (SO2) 

(lb/hr) 1591.1 1036.4 1036.4 1036.4 1036.4 1036.4 1036.4 863.7 863.7 863.7 0

Nitrogen Oxide 

(NOx) (lb/MMBtu) 0.42 0.33 0.23 0.2 0.26 0.18 0.07 0.3 0.05 0.23 0

Nitrogen Oxide 

(NOx) (lb/hr) 2405.5 1900.1 1324.3 1151.6 1497.1 1036.4 403.1 1727.4 287.9 1324.3 0

PM (lb/MMBtu) 0.05 0.015 0.015 0.015 0.015 0.015 0.015 0.034 0.034 0.034 0

PM (lb/hr) 287.9 86.4 86.4 86.4 86.4 86.4 86.4 195.77 195.77 195.77 0

SO3 as Sulfuric Acid 

(H2SO4) (lb/MMBtu) 0.013 0.011 0.011 0.011 0.011 0.031 0.004 4.6E-05 0.00026 4.6E-05 0

SO3 as Sulfuric Acid 

(H2SO4)

(a) (lb/hr) 77.7 62.9 62.9 62.9 62.9 177.3 25 0.26 1.50 0.26 0

Stack Conditions

Stack Height (meters) 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 0

Stack Exit Diameter 

(meters) 8.534 8.534 8.534 8.534 8.534 8.534 8.534 8.53 8.53 8.53 0

Stack Exit Temp. 

(Kelvin) 335 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83 0

Stack Exit Velocity 

(m/s) 17.07 17.07 17.07 17.07 17.07 17.07 17.07 17.07 17.07 17.07 0
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Table 19: CALPUFF Inputs for Unit 4

Model Input Data

2011 Analysis 2013 Analysis

PreConsent 

Decree

Consent 

Decree

Rotamix

or

SNCR

ROFA/

Rotamix ROFA SCR/SNC

R Hybrid

SCR 

with 

Sorbent

Baseline

[EPA 

FIP]

4 SCR

[NMED 

SIP]

4 SNCR

[State 

Alternative]

2 SNCR/2 

Shutdown

Hourly Heat Input 

(MMBtu/hour) 5649 5649 5649 5649 5649 5649 5649 5649 5649 5649 5649

Sulfur Dioxide (SO2) 

(lb/MMBtu) 0.29 0.18 0.18 0.18 0.18 0.18 0.18 0.15 0.15 0.15 0.10

Sulfur Dioxide (SO2) 

(lb/hr) 1662.4 1016.8 1016.8 1016.8 1016.8 1016.8 1016.8 847.4 847.4 847.4 564.9

Nitrogen Oxide 

(NOx) (lb/MMBtu) 0.42 0.33 0.23 0.2 0.26 0.18 0.07 0.3 0.05 0.23 0.23

Nitrogen Oxide 

(NOx) (lb/hr) 2399.6 1864.2 1299.3 1129.8 1468.7 1016.8 395.4 1694.7 282.5 1299.3 1299.3

PM (lb/MMBtu) 0.05 0.015 0.015 0.015 0.015 0.015 0.015 0.034 0.034 0.034 0.034

PM (lb/hr) 282.5 84.7 84.7 84.7 84.7 84.7 84.7 192.07 192.07 192.07 192.07

SO3 as Sulfuric Acid 

(H2SO4) (lb/MMBtu) 0.013 0.011 0.011 0.011 0.011 0.031 0.004 4.6E-05 0.00026 4.6E-05 4.6E-05

SO3 as Sulfuric Acid 

(H2SO4)

(a) (lb/hr) 76.2 61.7 61.7 61.7 61.7 174 24.5 0.26 1.47 0.26 0.26

Stack Conditions

Stack Height (meters) 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92 121.92

Stack Exit Diameter 

(meters) 8.534 8.534 8.534 8.534 8.534 8.534 8.534 8.53 8.53 8.53 8.53

Stack Exit 

Temp.(Kelvin) 331 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83 322.83

Stack Exit Velocity 

(m/s) 17.4 16.76 16.76 16.76 16.76 16.76 16.76 16.76 16.76 16.76 16.76
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Visibility Post-Processing (CALPOST)

In the 2011 analysis, visibility (or 98th percentile delta deciview (dv)) was calculated using Method 6 in 

CALPOST and Annual Average Natural Conditions, as recommended by the WRAP RMC protocol. 

The 2013 analysis used the revised IMPROVE equation (Method 8) and the Annual Average Natural 

Conditions, as recommended by EPA. The Annual Average Natural Conditions used in the 2011 and 

2013 analyses are shown in Table 20. They are specifically for the western half of the United States, 

included in Table 2-1 of EPA’s Guidance for Estimating Natural Visibility Conditions Under Regional 

Haze Rule (EPA-454/B-03-005, September 2003).

Table 20: Average Annual Natural Background Levels(a)

Component Average Annual Natural

Background (μg/m3)

Ammonium Sulfate 0.12

Ammonium Nitrate 0.10

Organic Carbon Mass 0.47

Elemental Carbon 0.02

Soil 0.50

Coarse Mass 3.00

(a)Table 2-1 of the EPA’s Guidance for Estimating Natural

Visibility Conditions under the Regional Haze Rule.

Modeling Results of 2011 Analysis

Using the air dispersion modeling methodology outlined in the previous section, a CALPUFF model run 

was conducted, with meteorological data for the years 2001-2003, for the following control technologies 

for each unit: for NOx, pre-consent decree, Consent Decree, SNCR or Rotamix, ROFA/Rotamix, ROFA, 

SCR/SNCR Hybrid (SCR/SNCR Hybrid with Inherent SO3 Removal), SCR with Sorbent (SCR with 

Inherent SO3 Removal and Sorbent Injection); and for PM, pre-consent decree, Consent Decree, PJFF, 

and WESP. To simplify the quantity of the modeling results, total visibility impacts at all 16 Class I areas 

were used to make comparisons of each control technology’s performance. 

For both the facility-wide and unit-by-unit modeling analysis conducted, the expected degree of visibility 

impact for each control technology was determined as the difference between the projected visibility 

impact after installation of that control and annual average natural visibility conditions, for each receptor 

at each of the 16 Class I areas. The difference is given as delta-deciview (delta-dv).

 

Visibility Impact of NOx Control Technology

The results of the visibility modeling for Unit 1, Unit 2, Unit 3, and Unit 4 for each of the NOx control 

technologies are summarized in Figures 4-7:

Figure 4 illustrates the maximum visibility deciview impact for each NOx control technology seen at 

each Class I area for the years 2001-2003 on a facility-wide basis. 

Figure 5 illustrates the maximum visibility deciview impact for each NOx control technology seen at 

each Class I area for the years 2001-2003 on a unit-by-unit basis.
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Figure 6 illustrates the maximum visibility deciview impact for each NOx control technology seen at 

Mesa Verde National Park for the years 2001-2003 on a facility-wide basis. 

Figure 7 illustrates the maximum visibility deciview impact for each NOx control technology seen at 

Mesa Verde National Park for the years 2001-2003 on a unit-by-unit basis. 

Visibility Impact of PM Control Technology

The visibility modeling performed for the WESP control option was performed on a facility-wide and 

unit-by-unit basis. The results of the facility-wide analysis demonstrated a net improvement of 0.62 dv at 

Mesa Verde National Park and a 0.14 dv improvement at San Pedro Parks Wilderness Area. The amount 

of visibility improvement at all other Class I areas was equal to or less than 0.1 dv improvement. 

The results of the unit-by-unit impact analysis demonstrate a 0.21 dv improvement for Units 3 and 4 at 

Mesa Verde National Park. However, all other impact analyses show less than a 0.1 dv improvement at 

any of the Class I areas for Units 1-4. 
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Figure 4: Total Amount of the Visibility Impacts at All 16 Class I Areas Using 2001-2003 Meteorological 

Data (facility-wide impact) (2011 Analysis)
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Figure 5: Total Amount of the Visibility Impacts at All 16 Class I Areas Using 2001-2003 Meteorological 

Data (units 1, 2, 3, and 4) (2011 Analysis)
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Figure 6: Visibility Impact at Mesa Verde National Park Using 2001-2003 Meteorological Data (facilitywide impact) (2011 Analysis)
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Figure 7: Visibility Impact at Mesa Verde National Park Using 2001-2003 Meteorological Data (units 1, 

2, 3, and 4) (2011 Analysis)

Updated Visibility Modeling Assessment Submitted April 1, 2013

PNM submitted updated visibility modeling for SJGS with revised emission estimates for sulfur dioxide 

(SO2), sulfuric acid (H2SO4), and total particulate matter (TPM). The modeling analysis compared 

available nitrogen oxide (NOx) control technologies including selective catalytic reduction (SCR), 

selective non-catalytic reduction (SNCR), as well as unit retirements as an alternative operating scenario 

that had not previously been analyzed, as described in Table 21 below. The previously evaluated 

alternatives (e.g., Consent Decree, ROFA/Rotamix, SCR/SNCR Hybrid, and ROFA) were not further 

evaluated in the 2013 analysis. The results of the analysis for those alternatives are included in Steps 1 

through 5 above. PNM’s updated BART modeling incorporated SJGS’s new SO2 and total particulate 

matter (TPM) emission rates of 0.15 lb/MMBtu and 0.034 lb/MMBtu, respectively, from the current NSR 
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permit effective August 31, 2012. These emission limits have been incorporated into the Baseline 

modeling scenario, including the EPA’s FIP scenario representing four SCRs, and the NMED’s 2011 SIP

scenario representing four SNCRs. The updated BART modeling also incorporated H2SO4 emission rates 

of 0.00026 lb/MMBtu and 0.000046 lb/MMBtu for SCR and non-SCR, respectively, for the scenarios 

detailed in Table 21. 

PNM utilized the EPA-approved CALPUFF version 5.8, the CALMET data set originally created by 

EPA, and modeling input files as modified by EPA to reflect the source specific parameters for the 

specific modeling scenarios. The modeled CALPUFF domain, receptors, ozone data, and CALMET data 

used in this analysis came directly from EPA. Additionally, the surface, upper air, and precipitation 

stations used to make the CALMET files were also directly delivered from the EPA. 

The NMED approved the use of all of the input parameters and data compiled by EPA for the updated

modeling analysis. The condensable particulate matter (PM) emission rates used in the 2013 modeling 

were based on the facility’s total particulate matter emission limit as established in the NSR permit 

effective August 31, 2012. PNM utilized the default ammonia background concentration of 1 ppb and the 

revised IMPROVE equation (Method 8) to calculate the 98th percentile delta deciview (dv) from modeled 

pollutant concentrations. 

The meteorology used for the SJGS BART analysis followed EPA’s methodology described in the

Technical Support Document (TSD) and included with EPA’s proposed 2011 FIP7

. The modeling 

analysis was performed on a year-by-year basis for the facility-wide impact for the four scenarios. 

Ammonia slip (ammonia that is not fully reacted and is emitted to atmosphere) associated with 

combustion NOx reduction systems may be higher than 1 ppb. However, [the] ammonia slip was not 

considered in the modeling analysis [because]. Considering the 1 ppb ammonia background and the 

reductions in NOx, ammonia slip would have a negligible impact on visibility from any of the scenarios.

EPA had determined in the FIP that [it] ammonia slip would not significantly impact visibility 

improvement due to reductions in NOx and SO2 anticipated in the 4-SCR scenario. The CALPUFF 

system used for the 2011 modeling and the updated modeling is summarized in Table 12. The emissions 

and stack parameters for the updated modeling are shown in Tables 16 through 19.
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Table 21: Target Emissions for Modeling Scenarios

Scenario Operation and Target Emissions

Baseline Units 1-4 operating only with existing air pollution control technology and new 

permitted SO2 and Total Particulate Matter (TPM) emission rates of 0.15 

lb/MMBtu and 0.034 lb/MMBtu, respectively.

Sulfuric Acid (H2SO4) emission rate of 0.000046 lb/MMBtu 

[EPA FIP] 4 SCR Units 1-4 operating with existing air pollution control technology and with new 

SCR installation; NOx at 0.05 lb/MMBtu and new permitted SO2 and TPM 

emission rates of 0.15 lb/MMBtu and 0.034 lb/MMBtu, respectively.

Sulfuric Acid (H2SO4) emission rate of 0.00026 lb/MMBtu 

[NMED SIP] 4 SNCR Units 1-4 operating with existing air pollution control technology and with new 

SNCR installation; NOx at 0.23 lb/MMBtu and new permitted SO2 and TPM 

emission rates of 0.15 lb/MMBtu and 0.034 lb/MMBtu, respectively.

Sulfuric Acid (H2SO4) emission rate of 0.000046 lb/MMBtu 

[State Alternative Plan]

2 SNCR/2 Shutdown

Units 2 & 3 retired, Units 1 & 4 operating with existing air pollution control 

technology and with new SNCR installation; NOx at 0.23 lb/MMBtu, permitted 

TPM emission rate of 0.034 lb/MMBtu, and a reduced SO2 emission rate of 0.10 

lb/MMBtu.

Sulfuric Acid (H2SO4) emission rate of 0.000046 lb/MMBtu 

Discussions and Conclusions

PNM remodeled the visibility impacts of SJGS using the revised emission estimates, the EPA-approved 

CALPUFF version 5.8, and the meteorological data provided by EPA as previously discussed. PNM 

provided NMED with all the modeling results performed on a year-by-year basis for the facility-wide 

impact for the four scenarios. NMED explored the modeling results to present the visibility improvement 

in two ways: 98th percentile deciview (dv) at each Class I area for the four scenarios and deciview 

improvement at each Class I area with addition NOx control technologies on the existing air pollution 

control technology.

CALPOST, the postprocessor for CALPUFF, calculates the maximum visibility impacts of all locations 

(receptors) in the 16 Class I areas for each day. Each modeled day and location has an associated delta 

deciview, which is the difference between deciviews and includes the impact at the SJGS and natural 

background, and deciviews of the natural background alone. From these daily values, the value of the 

98th percentile (approximately equivalent to the 8th highest day) recommended by the BART guidelines is 

used for comparing the effects of each scenario in improving visibility. The line and symbol graph in 

Figure 8 shows the 98th percentile at the 16 Class I areas and the impact of each scenario. 

As illustrated in Figure 8, the EPA FIP and State Alternative Plan reduce visibility impairment more than 

the NMED SIP submitted in July 2011 for the three years from 2001 through 2003. Mesa Verde National 

Park shows the highest 98th percentile among the 16 Class I areas and is the nearest Class I area, located 
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approximately 40 km north of the facility. Grand Canyon National Park shows the lowest 98th percentile 

and is located in the most distant area, located approximately 300 km west of the SJGS. When the 

frequency of the occurrence of the peak 98th percentile is compared to each BART technology scenario, 

the figure depicts that the State Alternative Plan and the EPA FIP more significantly reduce the peak 98th

percentiles than the NMED SIP scenario does. The 98th percentile value of the sixteen Class I areas is 

added up for each scenario separately for the comparison of a general visibility improvement, as shown in 

Figure 9. 

The days exceeding a 0.5 dv threshold are determined at each Class I area for each BART technology 

scenario for each of the three years. The average and maximum days exceeding the threshold value are 

calculated and graphed in Figure 10. Figure 10 shows that the State Alternative Plan and the EPA FIP 

significantly improve visibility as compared to the Baseline and NMED SIP scenarios. The State 

Alternative Plan closely matches the EPA FIP scenario. 

The visibility improvement from additional NOx control technologies beyond the base case is shown in 

Figure 11 and Table 22. The results indicate that the State Alternative Plan (2 SNCR/2 Shutdown) and 

the EPA FIP (4 SCR) achieve greater visibility improvement than projected for the NMED SIP scenario

of 4 SNCR. The State Alternative Plan [is virtually indistinguishable from] provides for nearly the same 

visibility improvement as the EPA FIP in improving visibility [, with a difference of less than 0.5 dv at 

any one Class I area]. The largest average differences in visibility improvement from the 4 SCR (FIP) and 

2 SNCR/2 Shutdown (State Alternative) scenarios are 0.28 dv at Mesa Verde National Park, and 0.16 dv 

at Canyonlands National Park.
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Figure 8: [98th Percentile on the 16 Class I Areas] Visibility Impact of the EPA FIP, NMED SIP, and 

State Alternative Scenarios (2013 Analysis)*

*EPA FIP = 4 SCR; NMED SIP = 4 SNCR; State Alter. = 2 SNCR/2 Shutdown
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Figure 9: Visibility Impact Results (2013 Analysis)*

*EPA FIP = 4 SCR; NMED SIP = 4 SNCR; State Alternative = 2 SNCR/2 Shutdown
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Figure 10: Average and Maximum Days Compared to 0.5 dv (2013 Analysis)*

*EPA FIP = 4 SCR; NMED SIP = 4 SNCR; State Alter. = 2 SNCR/2 Shutdown
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Figure 11: Visibility Improvement of the EPA FIP, NMED SIP, and State Alternative Scenarios (2013 

Analysis)*

*EPA FIP = 4 SCR; NMED SIP = 4 SNCR; State Alter. = 2 SNCR/2 Shutdown
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Table 22: 2001-2003 Average Visibility Improvement for 4 SCR, 4 SNCR and 2 SNCR/2 Shutdown 

Scenarios

Class I Area 4 SCR 4 SNCR

2 SNCR/2 

Shutdown

Difference Difference 4 SCR 

to 2 SNCR/2 

Shutdown

4 SCR to 4 

SNCR

Arches 1.06 0.37 0.97 0.69 0.09

Bandelier 0.61 0.23 0.64 0.38 -0.03

Black Canyon 0.37 0.16 0.41 0.21 -0.04

Canyonlands 1.54 0.48 1.38 1.06 0.16

Capitol Reef 0.34 0.10 0.42 0.24 -0.08

Grand Canyon 0.18 0.08 0.25 0.10 -0.07

Great Sand Dunes 0.73 0.27 0.69 0.46 0.04

La Garita 0.78 0.29 0.73 0.49 0.05

Maroon Bells 0.20 0.07 0.22 0.13 -0.02

Mesa Verde 2.69 0.55 2.41 2.14 0.28

Pecos 0.70 0.25 0.66 0.45 0.04

Petrified Forest 0.16 0.07 0.25 0.09 -0.09

San Pedro 1.41 0.49 1.29 0.92 0.12

West Elk 0.45 0.17 0.43 0.28 0.02

Weminuche 1.29 0.41 1.23 0.88 0.06

Wheeler Peak 0.59 0.24 0.58 0.35 0.01

Department Assessment of BART for NOx and PM 

In accordance with Section 169A(g)(7) of the Clean Air Act, the Department considered the following 

five statutory factors in the BART analysis for the SJGS: (1) the costs of compliance; (2) energy and nonair quality environmental impacts of compliance; (3) any existing pollution control technology in use at 

the source; (4) the remaining useful life of the source; and (5) the degree of improvement in visibility 

which may reasonably by anticipated to result from the use of such technology.

PM BART Assessment

Based on the 2011 five factor analysis, the Department has determined that BART for Units 1, 2, 3, and 4 

for PM is existing PJFF technology and the existing emission rate of 0.015 lb/MMBtu. The Department’s 

determination of BART was based on the following results of the full five factor analysis:

1) Each of Units 1, 2, 3 and 4 are equipped with PJFF and are subject to a federally-enforceable 

emission limit of 0.015 lb PM/MMBtu.

2) The Department reviewed both the cost-effectiveness and incremental cost-effectiveness of 

additional control technology (WESP) and found these costs to be excessive. See Table 11.
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3) There are additional energy impacts associated with the WESP technology and the Department

considers these costs to be reasonable.

4) The Department reviewed the visibility improvement that resulted from the installation of the 

consent decree technology (PJFF and LNB/OFA) and that would result from the addition of 

WESP technology. The Department determined that on a facility-wide basis the visibility 

improved by 1.06 deciviews (dv) from the installation of the consent decree technology at Mesa 

Verde National Park (Mesa Verde). The installation of WESP would result in a facility-wide 

improvement of 0.62 dv at Mesa Verde. Improvements on a unit-by-unit basis at all Class I areas 

showed very minor improvements, usually less than 0.1 dv. 

2011 NOx BART Determination

Based on the five factor analysis, the Department [has] determined in 2011 that, for the Facility 

comprising Units 1, 2, 3, and 4, BART for NOx is SNCR technology at an emission rate of 0.23 

lb/MMBtu on a 30-day rolling average. The Department’s determination of BART was based on the 

following results of the five factor analysis:

1) SNCR technology was considered cost-effective at an average cost of $3,494 per ton of NOx 

removed. SNCR technology will reduce the facility annual NOx emissions by 4,900 tons. (In the 

updated 2013 analysis, the cost estimate increased to $5,589 per ton. While still cost effective, this 

higher cost makes the State Alternative more attractive.) 

 

2) The SNCR technology would result in additional energy impacts and non-air impacts from a new 

reagent system and a reagent storage system. The Department considered these additional costs in 

the review of the overall cost-effectiveness of SNCR and found these costs to be reasonable. 

3) The Department reviewed the visibility improvement that resulted from the installation of the 

SNCR technology on Units 1, 2, 3 and 4. The Department determined that on a facility-wide basis 

the visibility improved by 0.25 dv at San Pedro, 0.22 dv at Mesa Verde, and 0.21 dv at Bandelier. 

4) An emission limit of 0.23 lb NOx/MmBtu at each of Units 1, 2, 3 and 4 equals the EPA’s 

established presumptive limit for dry-bottom, wall-fired boilers burning sub-bituminous coal.

5) The Department reviewed additional economic information provided by PNM that analyzed the 

economic impact to ratepayers in New Mexico. The PNM estimates indicate the cost of control 

technology beyond SNCR would be financially burdensome and cause economic hardship to lowincome New Mexicans. According to the US Census Bureau, as of 2009, 18% of New Mexicans 

were living below the poverty line, as defined by the federal poverty standards. PNM estimates a 

rate increase of $11.50 per year per residential ratepayer from the installation of SNCR versus an 

estimated rate increase of $82.00 per year from the installation of SCR.

6) The Department has determined that in light of the unreasonable costs of SCR, particularly as 

reflected in the impact on ratepayers, requiring controls to achieve reductions beyond the most 

stringent presumptive standard prescribed by the EPA is not justified.
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2013 BART Determination

The Department considered the terms of the non-binding agreement between the EPA, NMED and PNM, 

signed February 15, 2013 (the “State Alternative”), and the resulting significant environmental 

improvements of this alternative and compared this scenario to the 4 SNCR and 4 SCR scenarios 

previously evaluated. [The main elements of the State Alternative affecting emissions reductions and non 

air quality environmental benefits are outlined below:] The Department’s determination of BART was 

based on consideration of the BART statutory factors in the context of the following elements of the State 

Alternative (2 SNCR/2 Shutdown).

1) PNM will retire Units 2 and 3 by December 31, 2017. These retirements do not give rise to control 

equipment costs requiring amortization. The remaining useful life of the source is defined as 30 

years for the three scenarios described (4 SCR, 4 SNCR, 2 SNCR/2 Shutdown). Therefore, the 

statutory factor of the remaining useful life of the source does not weigh in favor of any option

over another.

2) PNM will obtain the necessary construction permit modification to limit the SO2 emission rates at 

Units 1 and 4 to 0.10 lb/MMBtu on a daily rolling 30-day average basis. These SO2 emission 

reductions occur separately and apart from the SO2 backstop trading program that EPA has already 

approved as satisfying BART. In addition to increased visibility improvement, these SO2

reductions will lead to non-air quality environmental benefits, such as decreased acid deposition.

3) The retirement of Units 2 and 3 will reduce the facility annual NOx emissions by an additional 

10,550 tons. When added to the controlled emission rate of Units and 1 and 4, total annual NOx 

emission will be reduced by 12,989 tons. Additionally, PNM will conduct performance testing to 

determine if the SNCRs installed on Units 1 and 4 can achieve significantly less than 0.23 

lb/MMBtu.

4) [The retirement of Units 2 and 3 will reduce raw material usage at the facility, including limestone, 

activated carbon, coal and No. 2 diesel oil. See table below.]The 2 SNCR/2 Shutdown scenario 

would result in less material usage than the 4 SCR and 4 SNCR scenarios. See Table 23. This will 

result in less limestone required to be transported and mined, less diesel fuel that would need to be 

refined for this power plant, less coal mined and less carbon that would need to be activated. 

Closure of two units will result in up to 53 percent less water used, from 21,000 acre-feet to 

10,161 acre-feet; wastewater generated will be reduced by up to 50 percent, from 41 million 

gallons to 21 million gallons; and solid waste generated will be reduced by up to 50 percent, from 

1.71 million tons per year to 854,130 tons per year.

Table 23: Raw Material Usage Comparison

Raw Material [State Alternative 

Plan]

2 SNCR/2 

Shutdown (TPY)

[Baseline, SIP, 

and FIP]

Baseline, 4 

SNCR, and 4 

SCR

Limestone(1) 86,052 172,104

Activated Carbon(1) 130 261

Coal(2) 2,667,364 5,334,729

No. 2 Diesel Oil(2) 1,007,336 2,014,671
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(1) Based on 2012 material usage data

(2) Based on 2011 material usage data

The energy and non-air quality environmental benefit of these resource savings weighs heavily in 

favor of the 2 SNCR/2 Shutdown scenario over the 4 SCR and 4 SNCR scenarios.

5) The two-unit retirement scenario will result in a substantial decrease in particulate matter 

emissions from coal processing, handling and transportation, as well as a substantial reduction in 

greenhouse gas emissions, mercury and [non mercury] other hazardous air pollutant emissions, 

and acid gas emissions as detailed in Table [22] 24 below. The non-air quality environmental 

benefits of these reductions, such as less impact on climate and less deposition of mercury to 

waterways, weigh heavily in favor of the 2 SNCR/2 Shutdown scenario.

[6) Water usage is expected to drop by up to approximately 53% to 10,161 acre-feet/year.]

6) [The State Alternative] Table 22 shows the average visibility improvement between the three 

scenarios of 4 SCR, 4 SNCR and 2 SNCR/2 unit shutdown. The 2 SNCR/2 Shutdown scenario

achieves significant visibility improvements as compared to the baseline and installation of SNCR

on Units 1-4. The visibility improvements from the State Alternative of SNCR on two units and 

two units shutdown compare very closely with the SCR installation scenario as contained in the 

FIP (less than [0.5 dv] 0.3 dv impact at any Class I area). For the 4 SCR and 2 SNCR/2 Shutdown 

scenarios, the average difference over three years is 0.28 dv at Mesa Verde and 0.16 dv at 

Canyonlands.

Therefore, with respect to the statutory factor of the degree of visibility improvement anticipated, 

the 2 SNCR/2 unit shutdown scenario is superior to the 4 SCR scenario, and substantially 

equivalent to the 4 SCR scenario.

7) Table 10 includes the cost in dollars per ton for SCR and SNCR, as well as other scenarios. The 

total capital investment of the FIP 4 SCR scenario is estimated at nearly $861,871,000, as 

compared to $34,556,000 for the installation of SNCR at Units 1 and 4. This additional and 

significant capital expenditure that would be required to comply with the [FIP] 4 SCR scenario is 

not justified given the slight [and undetectable] improvement in visibility of the [FIP] 4 SCR 

scenario over the [State Alternative] 2 SCR/2 Shutdown scenario.

8) Finally, with respect to the statutory requirement to consider existing pollution controls at the 

source, such existing pollution control equipment was evaluated for all alternatives beginning in 

Step 1 of the analysis, and is outlined in Table 10. NMED determined that existing control 

equipment is not sufficient to meet BART requirements for NOx at San Juan Generating Station. 

This factor has no further relevance in selecting among the control options in this case .

Weighing all the above considerations as required by CAA § 169A, the Department has determined that 

the State Alternative (2 SNCR/2 Shutdown), which achieves substantial environmental benefits beyond 

the requirements of the FIP (4 SCR), the SIP (4 SNCR) and the requirements of the BART Guidelines at 

40 CFR Part 51 Appendix Y at a significantly lower cost than the FIP scenario of 4 SCRs, satisfies the 

statutory and regulatory requirements of BART. 
San Juan Generating Station

BART Assessment

Page 46

Table 24: Pollutant Emissions from 2 SNCR/2 Shutdown, 4 SNCR and 4 SCR

Scenario NOx SO2 PM CO CO2 VOC Mercury Non-Hg Acid Gases

Current 21,000 10,500 2,380 33,507 14,669,968 210 0.0842 5.4 1,488

[State 

Alternative]

2 SNCR/2 

Shutdown

8,011 3,483 1,184 18,615 7,314,801 104 0.042 2.7 744

[State 

Alternative]

2 SNCR/2 

Shutdown

% Reduction

62% 67% 50% 44% 50% 50% 50% 50% 50%

[NMED SIP]

4 SNCR 16,100 10,500 2,380 33,507 14,699,968 210 0.0842 5.4 1,488

[NMED SIP]

4 SNCR

% Reduction

23% 0% 0% 0% 0% 0% 0% 0% 0%

[EPA FIP]

4 SCR 3,502 10,500 2,380 33,507 14,699,968 210 0.0842 5.4 1,488

[EPA FIP]

4 SCR

% Reduction 

83% 0% 0% 0% 0% 0% 0% 0% 0%

References

1. 40 CFR 51 – Regional Haze Regulations and Guidelines for Best Available Retrofit Technology 

(BART) Determinations

2. Summary of WRAP RMC BART Modeling for New Mexico (April 21, 2006)

3. Public Service Company of New Mexico BART Technology Analysis for the San Juan 

Generating Station (June 6, 2007 and submittal updates)

4. EPA. (2003). Air Pollution Control Technology Fact Sheet (SNCR). Retrieved from 

http://www.epa.gov/ttn/catc/dir1/fsncr.pdf

5. EPA. (2003). Air Pollution Control Technology Fact Sheet (SCR). Retrieved from 

http://www.epa.gov/ttn/catc/dir1/fscr.pdf

6. EPA. (2003). Guidance for Estimating Natural Visibility Conditions under the Regional Haze 

Rule. http://www.epa.gov/ttncaaa1/t1/memoranda/rh_envcurhr_gd.pdf

7. Technical Support Document; Visibility Modeling for BART Determination: San Juan 

Generating Station, New Mexico. EPA-R06-OAR-0846-0003