BEST AVAILABLE RETROFIT 

TECHNOLOGY ANALYSIS

Addendum

REVISION 0

B&V PROJECT NO. 177051

B&V FILE NO. 32.0000

PREPARED FOR

PNM San Juan Generating Station

1 APRIL 2013

®

®

©Black & Veatch Holding Company 2013. All rights reserved.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Table of Contents i

Table of Contents

Acronym List .....................................................................................................................................................AL-1

1.0 Introduction and Objectives............................................................................................................ 1-1

1.1 Previous BART Submittals ............................................................................................................... 1-1

1.2 San Juan Generating Station Background.................................................................................. 1-2

2.0 Basis of Analysis .................................................................................................................................. 2-1

2.1 Design Basis ........................................................................................................................................... 2-1

2.2 Economic Data....................................................................................................................................... 2-2

2.2.1 Capital Cost Estimates..................................................................................................... 2-2

2.2.2 Annual Operating and Maintenance Cost Estimate ............................................ 2-6

2.3 Baseline and Target Emissions....................................................................................................... 2-7

2.4 Project Assumptions........................................................................................................................... 2-8

2.5 Modeling Baseline Conditions ........................................................................................................ 2-9

3.0 Identification of All Available Retrofit Emissions Control Technologies........................ 3-1

3.1 NOx Control Technologies................................................................................................................. 3-1

3.1.1 Low NOx Burners, Overfire Air with Neural Network........................................ 3-2

3.1.2 Selective Non-Catalytic Reduction............................................................................. 3-4

3.1.3 Selective Catalytic Reduction....................................................................................... 3-6

3.1.4 SNCR/SCR Hybrid............................................................................................................. 3-8

3.1.5 Gas Reburn........................................................................................................................... 3-9

3.1.6 Mobotec ROFA and ROTAMIX....................................................................................3-10

3.1.7 NOxStar ................................................................................................................................3-11

3.1.8 ECOTUBE............................................................................................................................3-11

3.1.9 PowerSpan.........................................................................................................................3-12

3.1.10 Phenix Clean Coal Combustion System..................................................................3-13

3.1.11 e-SCRUB..............................................................................................................................3-15

3.1.12 PerNOxide ..........................................................................................................................3-16

3.2 Draft System Impacts .......................................................................................................................3-16

3.2.1 Balanced Draft Conversion .........................................................................................3-17

4.0 Technical Feasibility of Additional Control Technology Alternatives ............................. 4-1

4.1 Technically Infeasible Additional NOx Control Technology Alternatives ..................... 4-1

4.1.1 Natural Gas Reburn.......................................................................................................... 4-1

4.1.2 Mobotec ROFA and ROTAMIX...................................................................................... 4-2

4.1.3 NOxStar .................................................................................................................................. 4-2

4.1.4 ECOTUBE.............................................................................................................................. 4-2

4.1.5 PowerSpan........................................................................................................................... 4-3
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Table of Contents ii

4.1.6 Phenix Clean Combustion.............................................................................................. 4-3

4.1.7 e-SCRUB................................................................................................................................ 4-3

4.1.8 PerNOxide ............................................................................................................................ 4-3

4.2 Technical Feasibility Summary...................................................................................................... 4-3

5.0 Evaluation of Technically Feasible Additional Control Technology 

Alternatives........................................................................................................................................... 5-1

5.1 Control Effectiveness.......................................................................................................................... 5-1

6.0 Impact Analysis and Cost-Effectiveness of Additional Control Technology 

Alternatives........................................................................................................................................... 6-1

6.1 Types of Impact Analyses ................................................................................................................. 6-1

6.1.1 Cost of Compliance........................................................................................................... 6-1

6.1.2 Energy Impacts .................................................................................................................. 6-2

6.1.3 Environmental Impacts.................................................................................................. 6-2

6.1.4 Remaining Useful Life ..................................................................................................... 6-5

6.2 Cost-Effectiveness................................................................................................................................ 6-5

6.2.1 Cost-Effectiveness Comparison................................................................................... 6-7

7.0 Visibility Impacts................................................................................................................................. 7-1

7.1 Introduction........................................................................................................................................... 7-1

7.2 Source Description.............................................................................................................................. 7-2

7.3 Location of Sources Versus Relevant Class I Areas................................................................ 7-2

7.4 CALPUFF Model Selection ................................................................................................................ 7-3

7.5 Technology Scenarios ........................................................................................................................ 7-4

7.6 Stack Parameters and Emissions data ........................................................................................ 7-5

7.7 Light Extinction and Deciview Impact......................................................................................7-10

7.8 Modeling Results................................................................................................................................7-11

7.8.1 Baseline Scenario............................................................................................................7-11

7.8.2 BART Control Technology Scenarios ......................................................................7-12

7.9 Summary ...............................................................................................................................................7-15

7.10 Visibility Cost Effectiveness...........................................................................................................7-27

8.0 Conclusions............................................................................................................................................ 8-1

Appendix A. Term Sheet..............................................................................................................................A-1

Appendix B. SJGS New Source Review Permit......................................................................................B-1

Appendix C. Sargent & Lundy Design, Process Description, and Cost Estimates.................... C-1

Appendix D. EPA Technical Support Document..................................................................................D-1

Appendix E. CALPUFF Modeling Speciation Information................................................................ E-1
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Table of Contents iii

LIST OF TABLES

Table 1-1 SJGS Characteristics for Baseline Operation............................................................................. 1-3

Table 2-1 Economic Evaluation Factors.......................................................................................................... 2-2

Table 2-2 Economic Evaluation Factors.......................................................................................................... 2-6

Table 2-3 Target Emissions.................................................................................................................................. 2-8

Table 4-1 Technically Feasible Additional NOx Control Technology Alternatives ........................ 4-4

Table 5-1 NOx Control Effectiveness for Additional Control Technology Alternatives 

(Annual Average Emissions Rates)............................................................................................... 5-2

Table 6-1 SJGS Pollutant Emissions, Facility Wide..................................................................................... 6-3

Table 6-2 Raw Material Usage, Facility Wide................................................................................................ 6-4

Table 6-3 Impact Analysis and Cost-Effectiveness Results of Additional NOx Control 

Technologies .......................................................................................................................................... 6-6

Table 7-1 Class I Areas ........................................................................................................................................... 7-2

Table 7-2 Baseline Modeling Stack Parameters........................................................................................... 7-6

Table 7-3 Baseline Emission Rates.................................................................................................................... 7-6

Table 7-4 EPA FIP Modeling Stack Parameters............................................................................................ 7-7

Table 7-5 EPA FIP Emission Rates .................................................................................................................... 7-7

Table 7-6 NMED SIP Modeling Stack Parameters....................................................................................... 7-8

Table 7-7 NMED SIP Emission Rates................................................................................................................ 7-8

Table 7-8 State Alternative Stack Parameters.............................................................................................. 7-9

Table 7-9 State Alternative Emission Rates .................................................................................................. 7-9

Table 7-10 Baseline Visibility Results, 98th Percentile (dv)...................................................................7-11

Table 7-11 EPA FIP Visibility Results, 98th Percentile (dv)....................................................................7-12

Table 7-12 NMED SIP Visibility Results, 98th Percentile (dv)...............................................................7-13

Table 7-13 State Alternative Visibility Results, 98th Percentile (dv)..................................................7-14

Table 7-14 Maximum Delta Decview FIP minus the SIP, 98th Percentile (dv) ...............................7-16

Table 7-15 Delta Decview EPA FIP minus the State Alternative, 98th Percentile (dv)................7-17

Table 7-16 Average Days Compared To 0.5 dv.............................................................................................7-19

Table 7-17 Maximum Days Compared To 0.5 dv.........................................................................................7-21

Table 7-18 Average Days Compared To 1.0 dv.............................................................................................7-23

Table 7-19 Maximum Days Compared To 1.0 dv.........................................................................................7-25

Table 7-20 Visibility Improvement Cost-Effectiveness Summary........................................................7-27

Table 8-1 Project Calendar ................................................................................................................................... 8-2

LIST OF FIGURES

Figure 3-1 Schematic of SNCR System with Multiple Injection Levels................................................. 3-4

Figure 3-2 Schematic Diagram of a Typical SCR Reactor........................................................................... 3-6

Figure 3-3 Schematic of Gas Reburn System .................................................................................................. 3-9

Figure 3-4 Mobotec ROFA and ROTAMIX Simplified Process Flow Diagram (Mobotec 

USA).........................................................................................................................................................3-11
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Table of Contents iv

Figure 3-5 ECOTUBE Installation in a Boiler ................................................................................................3-12

Figure 3-6 ECO Process Flow Diagram (Source: PowerSpan)...............................................................3-13

Figure 3-7 Phenix Clean Coal Process Flow Diagram. (Source: Phenix)............................................3-14

Figure 3-8 e-SCRUB Process Flow Diagram (Source: 

http://www.escrub.com/escrubprocess.htm)......................................................................3-15

Figure 7-1 Location of SJGS and Class I Areas ................................................................................................ 7-3

Figure 7-2 Visibility Impact Results .................................................................................................................7-18

Figure 7-3 Average Days Compared To 0.5 dv.............................................................................................7-20

Figure 7-4 Maximum Days Compared To 0.5 dv.........................................................................................7-22

Figure 7-5 Average Days Compared To 1.0 dv.............................................................................................7-24

Figure 7-6 Maximum Days Compared To 1.0 dv.........................................................................................7-26
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Acronym List AL-1

Acronym List

A/C Air-to-Cloth

AQC Air Quality Control

ASN Ammonium Sulfate Nitrate

B&W Babcock & Wilcox

BACT Best Available Control Technology

BART Best Available Retrofit Technology

CaS Calcium Sulfide

CCS Clean Combustion System

CO Carbon Monoxide

CO2 Carbon Dioxide

COHPAC Compact Hybrid Particulate Collector

CUECost Coal Utility Environmental Cost

DBA Dibasic Acid

DCS Distributed Control System

DV Deciview

EPA Environmental Protection Agency

EPRI Electric Power Research Institute

ESP Electrostatic Precipitator

FAA Federal Aviation Administration

FLAG Federal Land Managers Workgroup

FLGR Fuel Lean Gas Reburn

H2SO4 Sulfuric Acid Mist

Hg Mercury

HHV Higher Heating Value

IWAQM Interagency Workgroup on Air Quality Modeling

LCC Lambert Conformal Conic

LNB Low NOx Burners

MMBtu Million British Thermal Unit

MWh Mega Watt Hour

HNO3 Nitric Acid

NH3 Ammonia

NH4 Ammonium

NMED New Mexico Environment Department

NN Neural Network

NO3 Nitrates

NOx Nitrogen Oxides

NPS National Park Service

NSPS New Source Performance Standards
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Acronym List AL-2

NWS National Weather Service

OFA Overfire Air

PJFF Pulse Jet Fabric Filter

PM Particulate Matter

PPM Parts Per Million

PPMVD Parts Per Million, Volumetric Dry

PRB Powder River Basin

RMC Regional Modeling Center

SAM Sulfuric Acid Mist

SCR Selective Catalytic Reduction

SJGS San Juan Generating Station

SNCR Selective Non-Catalytic Reduction

SOA Secondary Organic Aerosol

SO2 Sulfur Dioxide

SO3 Sulfur Trioxide

SO4 Sulfate

TAC Total Annualized Cost

TSD Technical Support Document

TSP Total Suspended Particulate

TCI Total Capital Investment

WRAP Western Regional Air Partnership
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Introduction and Objectives 1-1

1.0 Introduction and Objectives

The purpose of this Best Available Retrofit Technology (BART) Analysis for Public Service of 

New Mexico’s (PNM) San Juan Generating Station (SJGS) is to provide an addendum and update to 

the 2007 BART application and subsequent submittals. Particulate matter (PM) and sulfur dioxide 

(SO2) pollutant emission controls are already installed on the SJGS units and have previously been 

discussed in regard to the BART process and are not being considered further. This update focuses 

on nitrogen oxide (NOx) pollutant emission controls only. Specifically, this analysis reviews and 

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

non-catalytic reduction (SNCR), and also considers unit retirements as an alternative operating 

scenario as described in a non-binding agreement between EPA, New Mexico Environmental 

Department (NMED), and PNM (Appendix A). Additionally, the 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 Permit1

This report documents the BART evaluation process and the results obtained, as well as the 

recommended best control alternative for NOx control at SJGS.

dated August 31, 2012 (Appendix 

B). It is understood that these new pollutant emission rates were the result of either voluntary or a 

required permit action not associated with or related to the BART process. Therefore, these new 

emission limits have been incorporated into the Baseline modeling scenario, including EPA’s

Federal Implementation Plan (FIP) scenario representing four SCRs, and the NMED’s State 

Implementation Plan (SIP) scenario representing four SNCRs. These modeling scenarios were 

updated to “adjust” these previously analyzed and published scenarios for these new applicable 

emission limitations. 

1.1 PREVIOUS BART SUBMITTALS

In June 2007, PNM submitted the BART application for the SJGS. The objective of the study 

was to perform the BART analysis for the SJGS Units 1, 2, 3, and 4. These units were identified as 

BART–eligible sources by NMED because they cause visibility impairment in 16 Federal Class I 

areas that are within a 300 km radius, as identified in accordance with the Regional Haze and BART 

Rule guidelines that were published by the EPA on July 6, 2005 (70 FR 39104). Since this submittal,

PNM has responded to information requests from NMED and EPA, submitted information to 

support the possible control technology options and cost of these technologies, provided comments 

on EPA’s Advanced Notice of Public Rulemaking proposal, and updated visibility analyses. The 

following highlights the significant submittals by PNM to support NMED’s determination of SJGS’s 

BART and the regional haze rulemaking. Additional information can be found on NMED website2

 March 13, 2007 – SJGS Modeling Protocol Document

.

 June 6, 2007 – SJGS BART Application and Analysis

 1 NSR Permit No. 0063-M8. 2 http://www.nmenv.state.nm.us/aqb/reghaz/regional-haze_index.html
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Introduction and Objectives 1-2

 July 11, 2007 – Selective Catalytic Reduction (SCR) and Selective Non-Catalytic 

Reduction (SNCR) Hybrid Cost Analyses

 August 23, 2007 – Updated Visibility Cost Effectiveness Data

 November 5, 2007 – Refined Visibility Modeling and Results

 March 29, 2008 – PNM Discussion of OAQPS manual is the EPA Air Pollution Control

Cost Manual, Sixth Edition, EPA/452/B-02-001, dated January 2002 (the Cost 

Manual)

 March 31, 2008 – Final BART Visibility Modeling Response to NMED

 May 30, 2008 – Final BART SNCR Analysis and Discussion of SJGS’s Coal and BART 

Classification

 August 28, 2008 – Final Nalco-MOBOTEC Nitrogen Oxides and Final Particulate 

Matter BART Analyses 

 November 11, 2008 – Response to NMED Regarding H2SO4 Emissions

 March 16, 2009 – Sulfate Removal Report

 October 27, 2009 – PNM Comments on the EPA Proposal Advanced Notice of 

Proposed Rulemaking3

 February 11, 2011 – Revised SNCR and Rate Impact Analyses

1.2 SAN JUAN GENERATING STATION BACKGROUND 

SJGS is a minemouth facility burning coal from the San Juan Mine. Although the coal is 

classified as subbituminous, it is not a PRB subbituminous coal. The fuel combusted at SJGS has a 

higher heating value (HHV), lower moisture content, higher sulfur content, and lower volatility than 

PRB coal. 

SJGS Units 1 and 2 have a unit capacity of 370 MW each. The units are equipped with Foster 

Wheeler subcritical, wall-fired boilers that operate in a forced draft mode. SJGS 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. All units have wet limestone FGD forced oxidation systems 

installed for SO2 control.

On March 10, 2005, PNM entered into a consent decree with the Grand Canyon Trust, the 

Sierra Club, and the NMED. To meet the requirements of the consent decree, PNM installed stateof-the-art low NOx burners (LNB) with over fired air (OFA) ports on each boiler to reduce NOx

emissions. For PM emissions control, a full sized pulse-jet fabric filter (PJFF) was installed upstream 

of the limestone flue gas desulfurization (FGD) on each unit. The existing hot-side ESPs were deenergized, but remain in place. The PJFF is also a component, along with activated carbon injection 

(ACI), for reducing mercury (Hg) emissions. A summary of the unit’s operational characteristics are

presented in Table 1-1.

 3 EPA-R09-OAR-2009-0598
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Introduction and Objectives 1-3

Table 1-1 SJGS Characteristics for Baseline Operation

ITEM SJGS 1 SJGS 2 SJGS 3 SJGS 4

Fuel Type Subbituminous Subbituminous Subbituminous Subbituminous

HHV of Fuel, Btu/lb 9,692 9,692 9,692 9,692

Unit Rating, MW (gross) 370 370 544 544

Boiler Heat Input, 

MMBtu/h

3,707 3,688 5,758 5,649

Type of Boiler/

Manufacturer

Wall-fired/ 

Foster Wheeler

Wall-fired/ 

Foster Wheeler

Opposed wallfired/B&WOpposed wallfired/B&W

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 Low-NOx

burners

Over Fired Air

Low-NOx

burners

Over Fired Air

Low-NOx

burners

Over Fired Air

Low-NOx

burners

Over Fired Air

Mercury Activated 

Carbon Injection

Activated 

Carbon Injection

Activated 

Carbon Injection

Activated 

Carbon Injection
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Basis of Analysis 2-1

2.0 Basis of Analysis

2.1 DESIGN BASIS 

Sargent & Lundy (S&L) was contracted by PNM to develop a conceptual design, project cost 

estimate, and technical portions of an Engineering, Procurement and Construction (ECP) 

specification for SCR control systems on SJGS Units 1, 2, 3 and 4. S&L also prepared conceptual 

designs and project cost estimates to install and operate SNCR control systems on the San Juan 

generating units. A detailed summary of the SCR and SNCR cost estimates prepared for SJGS is 

provided in Appendix C. Appendix C includes a description of the design criteria and assumptions 

used to develop the cost estimates and contains the actual cost estimates that show the total capital 

costs, annual operating and maintenance (O&M), and total annual costs associated with both 

control technologies. 

Site-specific factors that had a significant effect on the SCR design basis and costs include 

the site congestion at SJGS, NOx emission reduction requirements, fugitive emission controls and 

balanced draft conversion, and the inclusion of a sorbent injection system to meet sulfuric acid mist 

(SAM) emission limits. SCRs add a significant pressure drop to the existing systems, so the SJGS 

units will have to have a new fan installed to accommodate the SCRs. Converting the units to 

balanced draft operations will cause additional size and costs to the new fans, as well as boiler and 

ductwork stiffening. These costs were split between the two projects by assigning 80% of the costs 

to the SCR, and 20% to the balanced draft conversion. The sorbent injection system is included, 

because SJGS must meet a SAM limit of 2.6 x 10-4 lb/MMBtu. Adding an SCR system will increase 

SO2 to SO3 oxidation, resulting in increased sulfuric acid emissions, and based on vendor input, a 

sorbent injection system is required in order for SJGS to meet this limit with an operating SCR. 

Equipment costs included in the SNCR cost estimate are largely based on a budgetary quote 

provided by Fuel Tech, an Original Equipment Manufacturer (OEM) of SNCR equipment. The Fuel 

Tech quote was based on SJGS boiler-specific operating parameters. The SNCR system was based 

on a 50% urea solution being delivered to site. Carbone monoxide (CO) levels of 1,000 ppm (at the 

boiler bull nose) are typically needed to achieve optimal NOx reductions with SNCR, so the cost 

estimates assumed only a 25% NOx reduction rate due to potentially high CO levels. The SNCR 

conceptual design and cost estimates were based on achieving a controlled NOx emission limit of 

0.23 lb/MMBtu. For cost estimating purposes it was assumed that Units 1 and 2 are equivalent, as 

are Units 3 and 4, due to the similarities in their design and operation.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Basis of Analysis 2-2

2.2 ECONOMIC DATA

2.2.1 Capital Cost Estimates

Capital cost estimates were developed for retrofit control technologies identified as 

technically feasible for the SJGS units. The capital cost estimates were based on conceptual 

estimates prepared by S&L based on: (1) conceptual designs and general arrangements prepared 

for the control systems; (2) budgetary quotes from equipment vendors for the major pieces of 

equipment; (3) site walk-downs; and (4) S&L’s in-house database of equipment and material costs 

for similar projects. The capital cost estimates include direct and indirect costs and are stated in 

2013 dollars. 

Table 2-1 lists some of the economic parameters and assumed values used in developing the 

capital cost estimates. 

Table 2-1 Economic Evaluation Factors

EVALUATION FACTORS VARIABLE

Plant and Control Technology Economic Life 30 years

New Mexico Gross Receipt Tax Rate 6.3125%

Capital and O&M Escalation Factor Not Included

Capital Recovery Factor (to annualize capital cost) 8.44% (30 years)

Interest During Construction Not Included

Total capital investment for the NOx control technologies include the purchased equipment 

costs, all costs for labor and materials for installing that equipment (direct installation costs), costs 

for site preparation, demolition, buildings, and certain other costs (indirect installation costs).4

 Contracting Strategy. The capital cost for the plant modifications are based on 

hiring an Engineering, Procurement and Construction (EPC) contractor to provide a 

‘turn-key’ air quality control system. Design of the control system would be 

performed by the EPC contractor. All equipment would be purchased directly by 

and installed by the EPC contractor. 

 Key 

components of the capital cost estimates can be found in the cost summary tables included in 

Appendix C for each of the control technology options. Installation costs include all costs for labor 

and materials for installing the new control systems, and take into account retrofit difficulties given 

the existing site configuration. Finally, the costs of miscellaneous items such as site preparation, 

demolition of existing structures, foundations, structural steel, buildings, and other site structures 

needed to implement the control technology are included. Direct capital costs were calculated 

based on the following assumptions, as further explained in Appendix C:

 4 See, U.S.EPA Office of Air Quality Planning and Standards (OAQPS), Air Pollution Control Cost Manual, EPA/452/B02-001, 6th Edition, January 2002, Section 1, Chapter 2, pg. 2-5.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Basis of Analysis 2-3

 Equipment Costs. Equipment costs include only those costs for the manufactured 

equipment. For the SNCR control system these items include the SNCR system, 

compressors, water treatment, tanks, pumps, and motors. For the SCR control 

system these items include the SCR reactor vessel and catalyst modules, economizer 

bypass and low load temperature control system, ammonia system, dry sorbent 

injection control system, and related ancillary equipment. 

 Material Costs. Material costs include those costs for commodity-like materials, 

such as structural steel, concrete, piping, valves, cable, cable tray, and conduit. All 

material unit costs were estimated on the basis of S&L in-house data, vendor 

catalogs, and industry publications. Quantities of materials were developed based

on the conceptual designs and general arrangement drawings prepared for each 

control system. 

 Labor Costs. Union craft labor rates were developed for both projects for the 

Albuquerque, New Mexico area from the publication RS Means. Union rates were 

then incorporated into work crews appropriate for the activities by adding 

allowances for payroll taxes, worker’s compensation, fringe benefits, incidentals, 

small tools, construction equipment, and site overheads to arrive at crew rates 

detailed in the cost estimate.

 Labor Incentives (SNCR). Labor incentives for the SNCR work are estimated based 

on 5 days x 10 hours/day work week for the non-outage work. The boiler tube 

insert modifications and scaffolding required for this work will be performed during 

an outage, and are estimated based on 6 days x 10 hours/day work schedule. The 

cost estimate reflects this assumption for overtime calculations. For common areas, 

is it assumed all work would be performed during pre-outage, and therefore reflects 

5 days x 10 hours/day schedule. 

 Labor Incentives (SCR). Labor incentives for the SCR work are estimated based on 

5 days x 10 hours/day work week for the non-outage work. Outage labor incentives 

were estimated based on 7 days and two shifts of 12 hours/day. 

 Labor Productivity. A 1.15 labor productivity factor was used in the estimates based 

on the regional labor productivity factor in the New Mexico area as published in 

Compass International Global Construction Cost and Reference Yearbook.

 Subsistence Pay. All cost estimates assume no subsistence pay. 
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Basis of Analysis 2-4

Indirect costs are those costs that are not related to the equipment purchased but are 

associated with any engineering project, such as the retrofit of an air quality control (AQC) 

technology. Indirect costs addressed in this evaluation are explained in more detail in Appendix C 

and include the following:

 Contingency

 Freight 

 Consumables

 EPC Engineering, Procurement and Project Services 

 EPC Management Support 

 EPC Startup & Commissioning

 EPC Fee 

 Owners Engineering 

 Startup and Spare Parts

 Performance Tests

2.2.1.1 Contingency

Contingency accounts for unpredictable events and costs that could not be anticipated 

during the normal cost development of a project. Costs assumed to be included in the contingency 

cost category are items such as possible redesign and equipment modifications, errors in 

estimation, unforeseen weather-related delays, strikes and labor shortages, escalation increases in 

equipment costs, increases in labor costs, delays encountered in startup, etc. Contingency was 

included in both the SNCR and SCR cost estimates as follows:

 Contingency (SNCR):

● 10% of Equipment Costs

● 20% of Material Costs

● 20% of Labor Costs

● 20% of Construction Indirect Costs

 Contingency (SCR):

● 20% of Total Direct and Indirect Construction Costs

2.2.1.2 Owners Engineer and Construction Management Support

Construction management services include field management staff such as support 

personnel, field contract administration, field inspection and quality assurance, project control, 

technical direction, and management of startup. It also includes cleanup expense for the portion 

not included in the direct-cost construction contracts, safety and medical services, guards and other 

security services, insurance premiums, other required labor-related insurance, performance bond, 

and liability insurance for equipment and tools. 
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Basis of Analysis 2-5

2.2.1.3 Startup and Spare Parts

Startup services include the management of the startup planning and procedure and the 

training of personnel for the commissioning of the newly installed AQC technology. Also included 

are the general low-cost spare parts required for each AQC technology system. High-cost critical 

spare part components are kept only if recommended by the manufacturer; they are determined 

and accounted for on a case-by-case basis.

2.2.1.4 Performance Tests

Performance test services are typically required after every AQC technology addition to 

validate the performance of the emissions reduction system. The results of the performance tests 

are used to ensure compliance with performance guarantees and emissions limits.

2.2.1.5 Allowance for Funds Used During Construction (AFUDC) or Interest During 

Construction (IDC)

AFUDC accounts for the time value of money associated with the distribution of 

construction cash flows over the construction period, which for an SCR system could be spread over 

a construction period of 36+ months. Total Capital Investment (TCI), as defined in the Control Cost 

Manual, includes all costs required to purchase equipment needed for the control system 

(purchased equipment costs), the costs of labor and materials for installing that equipment (direct 

installation costs), costs for site preparation and building, working capital, and off-site facilities.5

2.2.1.6 New Mexico Gross Receipt Tax

 

Thus, the Control Cost Manual allows the time value of money, measured by the real discount rate, 

to be incorporated into the cost estimate. Although AFUDC represents a significant actual cost that 

PNM will incur with an SCR projects (estimated to be in the range of $38 to $45 million), AFUDC 

was excluded from the SCR and SNCR cost estimates. 

The New Mexico Gross Receipt Tax (NMGRT) of 6.3125% was applied to the total cost (i.e., 

purchased equipment and services performed) of both the SNCR and SCR projects. 

2.2.1.7 Escalation

Escalation is typically included in cost estimates for major retrofit control projects and is 

intended to account for increases in equipment, material, and labor costs that occur during the 

duration of the project; however, escalation was not included in the SCR/SNCR cost estimates. Cost 

estimates attached to this report are shown in 2013 dollars. 

 5 OAQPS Control Cost Manual, page 2-5.
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BLACK & VEATCH | Basis of Analysis 2-6

2.2.2 Annual Operating and Maintenance Cost Estimate 

Annual O&M costs typically consist of the following cost categories:

 Reagent costs.

 Electric power costs.

 Makeup water costs.

 Operating labor costs.

 Maintenance materials and labor costs.

The costs of reagent, electric power, makeup water, wastewater, and byproduct disposal are 

variable annual costs and are dependent on the specific control technology. O&M materials and 

labor are fixed annual costs. Table 2-2 lists the major economic factors used to obtain the annual 

O&M costs. 

Table 2-2 Economic Evaluation Factors

PARAMETER VALUE

Reagent Cost

Ammonia (anhydrous) $785/ton

Ammonia (50% urea solution) $420/ton

Selective Catalytic Reduction (SCR) Catalyst Cost $8,000/m3

Makeup Water Cost $6.00/1,000 gal

Steam $5.00/1,000 gal

Byproduct Disposal Cost N/A

Auxiliary and Replacement Electric Power Cost $37.00/MWh

Lost Fly Ash Sales N/A

2.2.2.1 Reagent Costs

Reagent costs include the costs for the material, delivery of the reagent to the facility, and 

reagent preparation. Reagent costs are a function of the quantity of the reagent used and the price 

of the reagent. The quantity of reagent used will vary with the quantity of pollutant removed. Cost 

estimates included in Appendix C are based on using anhydrous ammonia as the SCR reagent, urea 

as the SNCR reagent, and hydrated lime in the DSI control system.
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BLACK & VEATCH | Basis of Analysis 2-7

2.2.2.2 Electric Power Costs

Additional auxiliary power will be required to run some of the new control technology 

systems. The power requirements of each system vary, depending on the type of technology and 

the complexity of the system. Electric power costs include an increase in fan power caused by the 

flue gas pressure losses through the new equipment. 

2.2.2.3 Makeup and Service Water Costs

Service water is required for some of the processes in the new control technology systems. 

Examples of water consumption include water used to dilute the urea reagent for the SNCR prior to 

injecting the urea solution into the boiler. Additional capital costs will be incurred to construct the 

water treatment needed to obtain the required water quality. 

2.2.2.4 Operating Labor Costs

The SCR and SNCR systems are assumed to not have any additional operating labor cost at 

SJGS. The technologies themselves are not too difficult to operate, and will not require additional 

operators to be hired. SJGS has existing air quality control technologies that require much more 

operating labor, and the addition of an SCR or SNCR at each unit should place a significant demand 

on the personnel.

2.2.2.5 Maintenance Materials and Labor Costs

The annual maintenance materials and labor costs are typically estimated as a percentage of 

the total equipment costs of the system. Based on electrical utility industry experience, 

maintenance labor and materials typically represent between 1 and 5 percent of the total capital 

costs. Some initial recommended spare parts were included in the capital costs. Annual 

maintenance labor and materials for both the SCR and SNCR control systems were calculated using 

the EPA’s Control Cost Manual factor of 1.5% of the control system’s total capital investment. 

2.3 BASELINE AND TARGET EMISSIONS

The average baseline emission rates for the SJGS units are assumed to be 0.30 lb/MMBtu 

based on the emission limits of the currently installed technologies with a maximum assumed to be 

0.40 lb/MMBtu. 

The EPA FIP for New Mexico targets an emission limit of 0.05 lb/MMBtu with SCRs installed 

at SJGS. The NMED SIP targets a value of 0.23 lb/MMBtu with SNCRs installed at SJGS. The NMED 

SIP’s target emission rate is based on the final Regional Haze and BART Rule guidelines issued in 

July 2005, where the presumptive limits that apply to BART-eligible coal plants for NOx and SO2

were outlined. The BART NOx presumptive limits vary according to the type of coal burned and the 

boiler design. For all units at SJGS, the NOx presumptive limit for a dry-bottom wall-fired, 

subbituminous coal burning unit is 0.23 lb/MMBtu. The presumptive limit of 0.23 lb/MMBtu was 

determined to be achievable for the majority of dry-bottom, wall-fired boilers firing subbituminous 

coals and using current combustion control technologies. 
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BLACK & VEATCH | Basis of Analysis 2-8

In addition to this presumptive limit, the BART analysis procedure requires control 

technologies that are considered as BACT to be included as a control alternative. A summary of the 

BART presumptive limits and BACT determinations for the pollutants in this BART analysis is 

presented in Table 2-3. Additionally, EPA’s presumptive limit from their 2011 FIP determination 

has also been included.

Table 2-3 Target Emissions

LIMITS NOX EMISSION RATE

BART Presumptive Limits(1)

(for subbituminous fuel)

0.23 lb/MMBtu

BACT Determination(2) 0.07 lb/MMBtu

EPA SCR Presumptive Limit(3) 0.05 lb/MMBtu

(1)NOx BART presumptive limits are for dry bottom, wall-fired coal fired 

units.

(2)BACT limits are referenced from the EPA BACT/LAER Clearinghouse

and appropriate for a retrofit installation.

(3)EPA Presumptive Limit as described in EPA’s FIP rule (EPA-R06-OAR2010-0846;FRL-9451-1)

2.4 PROJECT ASSUMPTIONS

In performing the BART analysis, several general assumptions were made to facilitate the 

conceptual design activities of the technically feasible control technologies that are being evaluated. 

The following are key project assumptions:

 No significant change will occur in plant availability with units that will be retrofit 

with BART controls after the installation of new AQC equipment.

 The site will have sufficient area available to accommodate construction activities 

including, but not limited to, offices, lay-down areas, and staging.

 Byproducts produced from the emissions reduction processes will be used as 

reclamation material in the existing coal mine. 
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BLACK & VEATCH | Basis of Analysis 2-9

2.5 MODELING BASELINE CONDITIONS

Emissions rates of pollutants are required as input data for visibility modeling. Stack outlet 

conditions for all the technically feasible control technologies were calculated and are presented in 

Section 7.0. The following stack outlet data are included:

 Flue gas stack exit velocity.

 Flue gas temperature.

 NOx emissions rate.

 SO2 emissions rate.

 Filterable PM emissions rate.

 SO3 emissions rate.
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BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3-1

3.0 Identification of All Available Retrofit Emissions Control 

Technologies

In Step 1 of the BART analysis, all available retrofit control technologies that have a 

practical potential for application at SJGS were identified and verified. These technologies are 

considered available technologies. The technology considered could be a change in plant operation 

method, addition/modification of emissions control system, or a combination for control of a 

pollutant. As previously indicated, control technologies for only NOx were reviewed and a 

description of the technology are presented in this section. Information on the working principle, 

retrofit considerations, advantages, and disadvantages of the technology are provided in the 

descriptions contained in Sections 3.1 through 3.2. 

In addition to adding NOx control technology to the SJGS units, retiring the units is another 

viable option for meeting the emission reduction and visibility requirements. The scope of work 

required to retire a unit is not discussed here, as this study assumes that specific units would be 

retired in place and that there is no cost associated with this action (e.g. the retired units will not be 

demolished).

3.1 NOX CONTROL TECHNOLOGIES

There are two approaches to achieving a reduction in NOx emissions: combustion control 

and post-combustion control. Combustion control methods seek to suppress NOx formation during 

the combustion process by controlling the flame temperature and fuel/oxygen ratio. Combustion 

control methods include LNBs, OFA, and neural network (NN) combustion optimization systems. 

The post-combustion controls consist of SNCR and SCR systems. SNCR and SCR are flue gas 

treatment technologies that reduce NOx after its formation. The SNCR and SCR NOx reduction 

technologies use either urea or ammonia as a reagent. SCR technology also uses multiple layers of 

reduction catalyst. Other NOx reduction techniques were also identified, including emerging 

technologies. 

NOx control technologies that were identified as available for retrofit at SJGS are listed 

below. A short description of each technology is included in the following sub-sections:

 LNB, OFA with NN. 

 SNCR.

 SCR.

 SNCR/SCR Hybrid.

 LNB, OFA, NN and SNCR.

 LNB, OFA, NN and SCR.

 LNB, OFA, NN and Hybrid.

 Gas Reburn.

 Mobotec ROFA and ROTAMIX.

 NOxStar.

 ECOTUBE.
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 PowerSpan.

 Phenix Clean Combustion.

 e-SCRUB.

 PerNOxide.

3.1.1 Low NOx Burners, Overfire Air with Neural Network

3.1.1.1 Low NOx Burners

NOx, primarily in the form of NO and NO2, is formed during combustion by two primary 

mechanisms: thermal NOx and fuel NOx. Thermal NOx results from the dissociation and oxidation of 

nitrogen in the combustion air. The rate and degree of thermal NOx formation is dependent on 

oxygen availability during the combustion process and is exponentially dependent on combustion 

temperature. Fuel NOx, on the other hand, results from the oxidation of nitrogen organically bound 

in the fuel. This is the dominant NOx producing mechanism in the combustion of pulverized coal, 

and typically accounts for 75 to 80 percent of total NOx. 

All LNBs offered commercially for application to coal fired boilers control the formation and 

emissions of NOx through some form of staged combustion. The basic NOx reduction principles for 

LNBs are to control and balance the fuel and airflow to each burner and to control the amount and 

position of secondary air in the burner zone so that fuel devolatization and high temperature zones 

are not oxygen rich. In this process, the mixing of the fuel and the air by the burner is controlled in 

such a way that ignition and initial combustion of the coal take place under oxygen deficient 

conditions, while the mixing of a portion of the combustion air is delayed along the length of the 

flame. 

The objective of this process is to drive the fuel-bound nitrogen out of the coal as quickly as 

possible, under conditions where no oxygen is present, and force it to form molecular nitrogen 

rather than be oxidized to NOx. Any nitrogen escaping the initial fuel-rich region has a greater 

opportunity to be converted to NOx as the combustion process is completed. The net result of 

staged combustion is usually longer and/or wider flames due to this delayed mixing process. 

Staged combustion may increase the potential for higher levels of unburned carbon in ash and 

higher CO emissions. This is particularly true of wall-fired boiler systems where, compared to 

tangential firing, the combustion process must be confined to well-defined flame zones and is less 

able to make maximum use of the available burner zone volume.

For LNBs to reach their maximum benefit, the proper balance of fuel and airflow to the 

burners (and from burner to burner) is critical. NOx reduction is achieved from the ability to 

control the location of the flame, the length of the flame, and, to a certain extent, the time of 

combustion.

By balancing the fuel and airflow to the burners, an important step is achieved in controlling 

the flame characteristics and improving the overall combustion process. Balanced fuel flow 

ensures that each burner is operated with a similar air-to-fuel ratio. This allows the burners to 

operate as a NOx control system rather than as individual burners. 
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3.1.1.2 Overfire Air System

OFA works by reducing the excess air in the burner zone, thereby enhancing the 

combustion staging effect and further reducing NOx emissions. Any residual unburned material, 

such as CO and unburned carbon that inevitably escapes the main burner zone, is subsequently 

oxidized as the OFA is added. 

As with primary NOx control, the performance that can be expected from a given OFA 

system depends on a number of factors. As the amount of OFA is increased, the stoichiometry in the 

burner zone decreases, and a point is reached where CO emissions reach high levels and become 

uncontrollable. The point at which this occurs varies, particularly if the fuel has characteristics that 

make it difficult to burn. For example, low volatility, low oxygen, or high moisture content make 

fuels more difficult to burn. It will also depend on the balance of flows between individual burners 

and the fuel fineness. As the OFA amount approaches 10 to 15 percent, the probability for 

individual burners to be operating under fuel-rich conditions increases so that pockets of very high 

CO emissions and unburned carbon will be formed. Similarly, fuel-rich operation at burners close 

to the waterwalls can lead to local slag formation and increased tube wastage rates, particularly if 

slagging is an ongoing problem. A fairly high level of unburned material leaving the burner zone 

can be accommodated by proper overfire port design, where requirements call for rapid and 

complete mixing of the OFA with the boiler flue gases. 

Aggressively staging combustion to reduce NOx emissions creates a reducing environment 

in the boiler and can damage the boiler waterwall tubes. The reducing environment attacks the 

iron oxides in the tube metal and can lead to pinholes in the boiler tubes. This phenomenon is 

referred to as tube wastage. Poor staging in the boiler could lead to tube wastage, an increase in the 

amount of maintenance, and, in the worst-case scenario, may require a forced outage to repair the 

tubes. 

3.1.1.3 Neural Network Systems

Advances in computer hardware and software technology have enabled power generation 

companies to implement cost-effective optimization solutions that decrease emissions and 

maximize plant efficiency. This solution, commonly referred to as the boiler optimization or NN 

system, may provide improvements in the heat rate of the boiler and reduce combustion-related 

emissions. NN computing differs from traditional computing in that engineering, statistical, and 

first-law principles have been replaced by complex, time-varying, nonlinear relationships. NN 

systems use real-time operational data extracted from a plant distributed control system (DCS), 

“learn” solutions from plant operational experience, and achieve reductions in the emissions 

produced, while possibly improving the heat rate of the plant.

NN systems also supplement other NOx reduction strategies. Some of these include LNB, 

OFA, and post-combustion controls such as SCR and SNCR. These systems are also used to help 

boiler manufacturers tune boilers with poor combustion characteristics or after an LNB retrofit or 

other boiler enhancements, such as OFA addition.
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BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3-4

A system for monitoring the air and coal flows provides real-time data for tuning the 

burners and maximizing performance of combustion system.

Airflow systems measure primary airflow, bulk secondary air, total secondary airflow, and 

OFA flow distribution. One specific system uses a pitot derivative of the multi-point, self-averaging 

pitot principle to measure the total and static pressure components of airflow. Pulverized fuel flow 

is determined by measuring the mass flow distribution and transport velocity of the fuel in the 

pipelines from the mill to the individual burners. The precise technology used for the 

measurements varies depending on the specific vendor.

3.1.2 Selective Non-Catalytic Reduction 

SNCR systems reduce NOx emissions by injecting a reagent at multiple levels in the steam 

generator, as illustrated on Figure 3-1. SNCR systems rely solely on reagent injection (rather than a 

catalyst) and an appropriate reagent injection temperature, good reagent/gas mixing, and adequate 

reaction time to achieve NOx reductions. SNCR systems can use either ammonia or urea as the 

reagent. Ammonia or urea is injected into areas of the steam generator where the flue gas 

temperature ranges from 1,500 to 2,200° F. The furnace of a pulverized coal fired boiler operates at 

temperatures between 2,500 to 3,000° F.

Figure 3-1 Schematic of SNCR System with Multiple Injection Levels
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SNCR systems are capable of reducing NOx emissions by as much as 50 to 60 percent in 

optimum conditions (adequate reaction time, temperature, and reagent/flue gas mixing; high 

baseline NOx conditions; multiple levels of injectors). Ammonia slip is the ammonia that does not 

react with NOx and instead “slips” past the boiler as ammonia. High levels of ammonia slip cause 

several negative operational impacts. First, ammonia will react with SO3 in the flue gas to form 

ammonium bisulfate and condense on the air heater surface, degrading its performance and 

decreasing plant efficiency. Another concern with high ammonia slip arises when SNCR is installed 

upstream of a fabric filter. The ammonia will condense on the fly ash and land on the fabric filter 

bags. This will cause bag blinding and require early replacement of fabric filter bags. For this 

reason, it is recommended that the ammonia slip be maintained below 5 ppmvd. 

However, to achieve these high levels of removal efficiency, high levels of ammonia slip (10 

to 50 ppmvd) must be allowed. Typically, to maintain a 5 ppmvd ammonia slip limit, NOx emissions 

reduction levels of 20 to 40 percent can be achieved. Potential performance is very site-specific and 

varies with fuel type, steam generator size, allowable ammonia slip, furnace CO concentrations, and 

steam generator heat transfer characteristics.

SNCR systems reduce NOx emissions using the same reduction mechanism as SCR systems. 

Most of the undesirable chemical reactions occur when reagent is injected at temperatures above or 

below the optimum range. At best, these undesired reactions consume reagent with no reduction in 

NOx emissions; at worst, the oxidation of ammonia can actually generate NOx. Accordingly, NOx

reductions and overall reaction stoichiometry are very sensitive to the temperature of the flue gas 

at the reagent injection point. This complicates the application of SNCR for boilers larger than 100 

MW because of the large boiler size/volume associated with such boilers. 

Reagent injection lances are usually located between the boiler soot blowers in the pendent 

superheat section. Optimum injector location is mainly a function of temperature and residence 

time. To accommodate SNCR reaction temperature and boiler turndown requirements, several 

levels of injection lances are normally installed. Typically, four to five levels of multiple lance 

nozzles are installed if sufficient boiler height and residence time is available. A flue gas residence 

time of at least 0.3 second in the optimum temperature range is desired to ensure adequate SNCR 

performance. Residence times in excess of 1 second yield high NOx reduction levels even under less 

than ideal mixing conditions. Computational fluid dynamics and chemical kinetic modeling can be 

performed to establish the optimum ammonia injection locations and flow patterns. For an existing 

boiler, minor waterwall reconfigurations are necessary to accommodate installation of SNCR 

injector lances. A re-examination of the boiler steam piping would probably be required to achieve 

optimum performance. 
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3.1.3 Selective Catalytic Reduction

SCR systems are the most widely used post-combustion NOx control technology for 

achieving significant NOx emissions reduction. In SCR systems, vaporized ammonia (NH3) injected 

into the flue gas stream acts as a reducing agent when passed over an appropriate amount of 

catalyst. The NOx and ammonia reagent react to form nitrogen and water vapor. The reaction 

mechanisms are very efficient, with a reagent stoichiometry of approximately 1.05 (on a NOx

reduction basis) and a low ammonia slip (unreacted ammonia emissions). A simplified schematic 

diagram of a typical SCR reactor is illustrated on Figure 3-2. However, most modern SCR systems 

use sonic horns in place of steam or air soot blowers. Some SCR systems are built without a bypass. 

However, a unit that uses fuel oil for startup should have a bypass to avoid getting unburned fuel on 

the catalyst during startup.

Figure 3-2 Schematic Diagram of a Typical SCR Reactor

SCR in coal fired operation can be placed in one of three locations. The most common is a 

high dust SCR. With a high dust SCR, the catalyst is located downstream of the economizer and 

upstream of the particulate control device. The second option is a low-dust SCR where the catalyst 

is located downstream of a hot-side ESP. This reduces the cost of an SCR as compared to the high 

dust SCR since the catalyst volume can be smaller. It should be noted that an SCR located after a deenergized hot-side ESP should be designed and sized as a high dust SCR. The third option is a tail 

end SCR where the reactor is located downstream of an FGD system. This requires a smaller 

reactor than the other options but also requires a regenerative heat exchanger to heat the catalyst 

above the minimum ammonia injection temperature. In selecting a location for the SCR, specific 

plant issues need to be assessed to determine the most economical solution. 
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The SCR reactor is the housing for the catalyst. The reactor is basically a widened section of 

ductwork modified by the addition of gas flow distribution devices, catalyst, catalyst support 

structures, access doors, and sonic horns/soot blowers. An ammonia injection grid is located 

upstream of the SCR reactor. The SCR reactor is elevated above and upstream of the air heater. 

The SCR reaction occurs within the temperature range of 550 to 850 °F, where the extremes 

are highly dependent on the fuel quality. Along with the NOx reaction, the catalyst oxidizes a 

portion of the SO2 in the flue gas to SO3. The oxidation of SO2 to SO3 could also require moderate air 

heater modifications, since the acid dew point temperature of the flue gas is directly related to SO3

concentration. As the SO3 concentration increases, the acid dew point of the flue gas increases, 

potentially increasing corrosion in downstream equipment or possibly requiring an increase in the 

air heater gas outlet temperature. 

The ammonia reagent for SCR systems can be supplied by anhydrous ammonia, aqueous 

ammonia, or by conversion of urea to ammonia. Since the ammonia is vaporized prior to contact 

with the catalyst, the selection of ammonia type does not influence the catalyst performance. 

However, the selection of ammonia type does affect other subsystem components, including 

reagent storage, vaporization, injection control, and balance-of-plant requirements. The vast 

majority of installations worldwide use anhydrous ammonia. 

SCR systems have a variety of interfacing system requirements to support operations. 

These requirements include fan draft power, auxiliary power, soot blowing steam, gas temperature, 

controls, ductwork, reactor footprint, and air heater. The SCR system will affect the boiler draft 

system. Depending on arrangement and performance requirements, draft losses can range from 4 

to 10 in. wg, which would require additional fan power. If necessary, ductwork and/or boiler box 

reinforcement may also be required. In conjunction with the fan modification, an expansion of the 

auxiliary power system might be necessary. Auxiliary power modifications may also be necessary 

for ammonia supply system requirements. 

The major impact of the SCR system can be seen at the air heater, where there are two areas 

of concern. One concern is the formation and deposition of ammonium bisulfate on the air heater 

surface. This will cause an increase in the pressure drop of the air heater, degrading its 

performance and decreasing plant efficiency. The other potential concern for the air heater is the 

tendency for high SO3 concentrations in the flue gas to form sulfuric acid vapor. If the acid dew 

point temperature has been increased to more than the air heater exit temperature, a significant 

amount of acid gases will condense in the air heater and lead to pluggage and corrosion. Several 

measures can be taken to avoid or correct this situation. Most important is the right composition of 

the catalyst to minimize the SO2 to SO3 conversion rate. Ammonia slip must also be minimized. Air 

heater basket modifications are often necessary to minimize these harmful effects. 
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3.1.4 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. 

The SNCR component of the hybrid system is identical to the SNCR system described 

previously, except that the hybrid system may have more levels of multiple injection lances. This 

will increase the capital cost of the SNCR component of the hybrid system. During operation, the 

SNCR system would be allowed to inject higher amounts of reagent into the flue gas compared to 

conventional SNCR. This increased reagent flow has a two-fold effect: NOx reduction within the 

boiler is increased, while ammonia slip also increases. The ammonia that slips from the SNCR is 

then used as the reagent for the catalyst. 

There are two design philosophies for using this excess ammonia slip. The most 

conservative hybrid systems use the catalyst simply as an ammonia slip “scrubber” with some 

additional NOx reduction. As with in-duct systems, the flue gas velocity through the catalyst is an 

important factor in design. Operating in this mode allows maximum NOx reduction within the 

boiler by the SNCR, while minimizing the catalyst volume requirement. While some NOx reduction 

is realized at the catalyst, the relatively small catalyst requirement of this design allows a true induct arrangement, with no significant ductwork changes, arrangement interference, or structural 

modifications. The second philosophy uses adequate catalyst volume to obtain significant levels of 

additional NOx reduction. However, this philosophy is usually not economically advantageous 

when compared to SCR. As a result, hybrid systems are usually designed using the first philosophy. 

The additional reduction is a function of the quantity of ammonia slip, catalyst volume, and 

distribution of ammonia to NOx within the flue gas. Using ammonia slip produced by the SNCR 

system is not an efficient method to introduce reagent, because of the low reagent utilization 

discussed as a part of the SNCR. Therefore, even though the reaction at the catalyst requires 1 ppm 

of ammonia to remove 1 ppm of NOx, the SNCR must inject at least 3 ppm of ammonia to generate 1 

ppm of ammonia at the catalyst.

Catalyst volume is strongly influenced by the NOx reduction required and the ammonia 

distribution. If multiple levels of catalyst operating at low flue gas velocity are required, some 

modifications will be required to the existing ductwork. If widening the existing ductwork cannot 

provide adequate catalyst volume, then a separate reactor is required, thus eliminating much of the 

capital cost advantage of a hybrid system.

The major impact of the hybrid system can be seen at the air heater, where there are two 

areas of concern. One concern is the formation and deposition of ammonium bisulfate on the air 

heater surface. This will cause an increase in the pressure drop of the air heater, degrading its 

performance and decreasing plant efficiency. The other potential concern for the air heater is high 

concentrations of SO3 in the flue gas. If the acid dew point temperature has been increased to more 

than the exhaust temperature, a significant amount of acid gases will condense in the air heater and 
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lead to pluggage and corrosion. Several measures can be taken to avoid or correct this situation. 

Modifications to the air heater baskets can help to minimize these adverse effects. 

3.1.5 Gas Reburn

The natural gas reburning process employs three separate combustion zones to reduce NOx

emissions, as illustrated on Figure 3-3. The first zone consists of the normal combustion zone in the 

lower furnace, which is formed by the existing wall burners. In this zone, 75 to 80 percent of the 

total fuel heat input is introduced. The first zone burners are operated with about 10 percent 

excess air (a 1:10 stoichiometric ratio). A second combustion zone (the reburn zone) is created 

above the lower furnace by operating a row of conventional natural gas burners at a stoichiometric 

ratio of less than 1.0. This technology also has the potential for increased furnace corrosion 

(especially with higher sulfur fuels) because of the reducing atmosphere in the lower furnace.

The sub-stoichiometric reburn zone causes NOx produced in the lower furnace to be 

reduced to molecular nitrogen and oxygen. This happens because the oxygen stripped from the NOx

molecules is combined with the more active CO molecules to form CO2 as combustion is completed 

in the upper furnace. Fuel burnout is completed in the third zone (the burnout zone) by the 

introduction of OFA. Sufficient OFA is introduced to complete combustion of the unburned 

materials in the upper furnace, with an overall excess air rate for the boiler of 15 to 20 percent. 

Reburn technology has demonstrated NOx reductions of 40 to 65 percent.

Figure 3-3 Schematic of Gas Reburn System

Burnout Zone

•Normal Excess Air

Reburning Zone

•Slightly Fuel Rich

•NOx Reduced to N2

Primary Combustion

Zone

•Reduced Firing Rate

•Low Excess Air

•Lower NOx

Overfire Air

40 to 60% NOx Reduction

10 to 20 % Gas

Fuel Rich

80 to 90% Coal

10% Excess Air
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Sufficient residence time (adequate furnace height) in the reburn and OFA zones is a key 

factor in determining whether the reburning technology can be applied. Successful retrofit of this 

technology requires space within the boiler to allow adequate residence time for both the 

additional burning zone (0.4 to 0.6 second) and the associated OFA burnout zone (0.6 to 

0.9 second). When this space is available, reburning can be highly effective, but a low residence 

time will limit system performance. Also, the high cost of natural gas can make the annual 

operating costs of this technology prohibitive.

A variation to gas reburn is fuel lean gas reburn (FLGR), which can reduce NOx emissions 

from coal fired boilers by 30 to 45 percent. FLGR requires a lower natural gas input than in a 

conventional gas reburn system and does not require an OFA system to achieve CO burnout. The 

FLGR technology requires low natural gas flow rates to maintain an overall lean fuel condition (of 

approximately half the amount required for a conventional reburn system). Mixing between the 

injected gas and furnace gas is the key to effective NOx removal. CO burnout is achieved by the 

excess oxygen that is available in the overall fuel lean furnace gas. 

Another type of the FLGR system consists of incorporating a urea-based SNCR system into 

the gas reburn system. This technology involves injecting natural gas and urea; the system is called 

amine-enhanced fuel lean gas reburn (AE-FLGR). This technology is capable of a higher NOx

removal efficiency than the basic gas reburn and FLGR systems. An amine-enhanced system is 

capable of reducing NOx emissions by 50 to 70 percent.

3.1.6 Mobotec ROFA and ROTAMIX

Mobotec provides a NOx reduction system that combines LNBs, OFA, and SNCR technologies 

into an integrated system. The system uses a modified OFA system with mixing characteristics 

achieved by adding a rotation to the OFA. This system is called ROFA, or Rotating Opposed Firing 

Air. A booster fan is used to direct combustion air away from the primary combustion zone and to 

the upper portion of the furnace. Air nozzles are strategically placed so that the gas flow inside the 

furnace rotates, causing turbulent mixing. The ROFA system has the potential to provide improved 

combustion, which results in lower unburned carbon, lower CO and NOx production, and improved 

boiler efficiency.

In addition, ROTAMIX can be added to the system, which consists of injecting urea or 

ammonia into the ROFA air nozzles. The extra mixing produced by combining the OFA nozzles with 

the reagent injection can achieve additional NOx reduction because of a homogeneous temperature 

profile in the boiler. The ROTAMIX system adapts to changes in load and temperature in the 

furnace and preferentially introduces ammonia where the temperature is most favorable for NOx

reduction. This approach reduces chemical consumption considerably and lowers ammonia slip by 

increasing the reaction efficiency through mixing. Chemical consumption for a ROTAMIX system 

can be up to 50 percent less than other SNCR technologies. ROTAMIX installations have yielded up 

to 60 percent NOx reduction in addition to the ROFA NOx reduction. 
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BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3-11

Although the Mobotec system may offer significant advantages over conventional 

scrubbing, impacts such as the increased volumes of particulate that would need to be collected, 

expected additional costs for sorbent, and the limited large-scale installed experience with the 

system should be considered. A simplified process flow diagram of the ROFA and ROTAMIX system 

is illustrated on Figure 3-4.

Figure 3-4 Mobotec ROFA and ROTAMIX Simplified Process Flow Diagram 

(Mobotec USA)

3.1.7 NOxStar

NOxStar is the trademarked name for a NOx control technology provided by Doosan Power 

Systems (formerly Mitsui Babcock). It involves the injection of ammonia and a hydrocarbon 

(typically natural gas) into the flue gas path of a coal fired boiler at around 1,600 to 1,800° F for the 

reduction of NOx. The ammonia reduces NOx through an SNCR reaction, with the hydrocarbon 

minimizing the ammonia slip. This enables higher reagent injection rates for NOx reductions than 

are achievable with a typical SNCR technology. The technology supplier states that the technology 

has the ability to achieve NOx emissions of less than 0.20 lb/MMBtu without the use of a catalyst 

and large SCR reactor. Although initially targeting high NOx reductions, full-scale demonstrations to 

date have been limited to nominally 50 percent NOx reduction performance.

3.1.8 ECOTUBE

The ECOTUBE system, provided by ECOMB AB (located in Sweden), utilizes retractable 

lance tubes that penetrate the boiler above the primary burner zone and inject high-velocity air as 

well as reagents. The lance tubes work to 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. 
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BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3-12

ECOTUBE is capable of reducing NOx, CO, and volatile organic compounds, while improving 

thermal efficiency, by optimizing the combustion process in boilers. An illustration of the ECOTUBE 

installation in a typical boiler is shown on Figure 3-5. 

Figure 3-5 ECOTUBE Installation in a Boiler

The water-cooled ECOTUBEs are automatically retracted from the boiler on a regular basis 

and cleaned to remove layers of soot and other deposits. Additional benefits have been identified 

by the supplier, including furnace combustion improvements that increase efficiency, reduce fuel 

usage, and reduce corrosion and erosion in the boiler and back-end equipment. 

3.1.9 PowerSpan

There are several emerging multi-pollutant technologies that use high electron beams or 

other proprietary processes. The PowerSpan ECO system has only limited experience and is 

beginning small-scale commercial operation. The ECO system is located downstream of an existing 

particulate control device; the process consists of three stages. A process flow diagram of the ECO 

system is illustrated on Figure 3-6. In the first stage, the flue gas passes through a dielectric barrier 

discharge reactor, where it is exposed to a nonthermal plasma discharge, which generates high 

energy electrons. The electrons initiate a chemical reaction to form oxygen and hydroxyl radicals, 

which then oxidize NOx, SO2, and Hg. This process results in the formation of nitric acid (HNO3), 

sulfuric acid, and mercuric oxides. Stage 2 is the collection of these acids and oxides in a 

downstream ammonia scrubber. The final stage is the collection of acid aerosols, fine PM, and 

oxidized Hg in the downstream wet ESP. Scrubber effluents contain dissolved ammonium sulfate 

nitrate (ASN) salts along with solids and Hg. The ASN solution is sent to a recovery process where 

the Hg is removed via a sulfur-impregnated activated carbon structure. Once the activated carbon 

bed becomes saturated with Hg, it is disposed of as a hazardous waste. The cleaned stream of ASN 

is converted to a saleable fertilizer. 
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BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3-13

The ECO system has been tested on a 1 to 2 MW slipstream unit at FirstEnergy’s Burger 

Plant and has achieved 82, 99, and 85 percent reduction for NOx, SO2, and Hg, respectively.

Figure 3-6 ECO Process Flow Diagram (Source: PowerSpan)

3.1.10 Phenix Clean Coal Combustion System

In the 2007 BART study, Phenix Limited LLC’s Clean Combustion System (CCS) was 

identified as a potential control technology, but since the study, Phenix Limited LLC has ceased 

operating. The CCS system can no longer be considered commercially available, but to review, CCS 

is an advanced hybrid coal gasification/combustion process that prevents the formation of NOx and 

SO2 emissions when burning coal. The only reagent required for pollution control is limestone. 

The CCS consists of an entrained-flow coal gasifier, followed by stages of combustion air. 

The CCS burner is designed to provide the necessary time, temperature, and stoichiometry required 

for all the chemicals in coal to complete their combustion reactions (to reach equilibrium 

conditions).

The coal, with limestone added as a source of calcium for sulfur capture, is pulverized and 

introduced to the burner along with a limited amount of hot combustion air. The initial high 

temperature combustion gasifies and/or releases all the constituents of coal into the gas; i.e., 

carbon, sulfur, nitrogen, and ash compounds. At these high temperatures, and with limited 

available oxygen, the carbon aggressively commands oxygen to form CO from all sources, including 

such compounds as water. Nitrogen compounds that may form, such as NOx, hydrogen cyanide, and 

ammonium (NH4), are forced to the molecular form (N2) by the aggressive action of carbon for 

oxygen. In the presence of calcium, the sulfur reacts to form calcium sulfide (CaS, a solid nongaseous particle). 
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BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3-14

The high combustion temperatures melt the coal ash and calcium sulfide solids to form an 

inert slag that drains from the bottom of the boiler. The hot flue gas, with high concentrations of CO 

and H2 and low concentrations of NOx and sulfur, exits into the boiler furnace. As the gases cool and 

generate steam, additional OFA is added in stages to the furnace to complete the combustion of CO 

to CO2 and H2 to water. This prevents the formation of any new (thermal) NOx and completes the 

combustion with excess air. The clean hot gases then enter the boiler superheat section as they did 

before the retrofit. A schematic of the process is shown on Figure 3-7. 

Retrofits require an annual outage period with a 2 to 3 week extension, for a total of 8 

weeks. The CCS retrofit modification requires replacing the existing pulverized coal burners with 

new down-fired CCS burners and adding OFA to the boiler furnace and powdered limestone to the 

coal fuel. Most of the new, off-the-shelf equipment fits within the existing boiler space. 

Figure 3-7 Phenix Clean Coal Process Flow Diagram (Source: Phenix)

A CCS repowered boiler will show improved efficiency from more complete coal 

combustion (loss on ignition of < 1.0 percent), very low NOx (< 0.15 lb/MMBtu), and control of SO2

emissions (< 0.5 lb/MMBtu) with lower sulfur coals. 
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BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3-15

3.1.11 e-SCRUB

The 2007 BART analysis identified the e-SCRUB process as a potential control technology, 

but since then, e-SCRUB has ceased operating. The technology can no longer be considered to be 

commercially available. To review, 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 byproduct recovery systems. A process flow diagram 

is shown on Figure 3-8. The process consists of the following:

 e-Beam Chamber--This process uses a high-energy electron beam in a chamber, the 

e-Beam chamber, to oxidize SO2 to SO3 and NOx to a combination of N2, HNO3, and 

NO2. Ammonia is injected upstream of the chamber and reacts with the oxidized 

compounds to form ammonium sulfate and ammonium nitrate.

 Wet ESP--The ammonium sulfate and ammonium nitrate are precipitated and 

collected as brine. The brine is then sent to an upstream spray dryer absorber and 

dry ESP. 

 Spray Dryer Absorber--The brine from a downstream wet ESP is fed into a spray 

dryer absorber, which forms a dry ammonium sulfate ((NH4)2SO4)/ammonium 

nitrate (NH4NO3) product that can be used as a fertilizer. The temperature of the 

flue gas is reduced in the spray dryer to an ideal reaction temperature prior to 

entering the e-Beam chamber. 

 Dry ESP--The dry ESP functions as a secondary byproduct collector and is located 

directly downstream of the spray dryer absorber.

Figure 3-8 e-SCRUB Process Flow Diagram (Source: http://www.escrub.com/escrubprocess.htm)
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BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3-16

According to pilot data, the vendor estimates that SO2 and NOx removals of 98 and 

90 percent, respectively, are achievable. To make this system cost-effective, it is important to locate 

a company to supply the ammonia reagent and remove the fertilizer byproduct. The e-SCRUB 

technology has been applied commercially on a 200 MW facility in China. 

3.1.12 PerNOxide

PerNOxide is a technology provided by FMC Environmental Solutions in conjunction with 

URS. PerNOxide was developed through research grants with the EPA, and the final patent is 

owned by NASA. FMC is the sole licensor of the technology, but they have a joint commercialization 

agreement with URS.

PerNOxide injects hydrogen peroxide into the flue gas somewhere between the economizer 

and the air preheater. The location is not as important as the flue gas temperature, which needs to 

be 600-1,100 °F. The hydrogen peroxide quickly evaporates in the duct and oxidizes NO to form 

NO2, N2O5, HNO2, and HNO3. The new compounds are significantly more soluble than NO, 

particularly the higher-order oxides. Their solubility is enhanced when the solvent contains other 

chemicals that can react with the nitrogen oxides. The research behind PerNOxide identified sulfite 

and bisulfate ions as having a positive effect on the solubility of the nitrogen oxides, so passing flue 

gas rich in high-order oxides of nitrogen through a solution containing sulfite ions will remove a 

significant portion of the nitrogen oxide molecules. 

Therefore, PerNOxide can only be used in conjunction with a wet FGD. Sodium based wet 

FGD systems are better than calcium based ones, because the sulfite concentrations tend to be 

higher when sodium is the FGD reagent.

PerNOxide has gone through numerous bench scale tests, and a full-scale pilot test. 

However, there are no commercial installations at this time.

3.2 DRAFT SYSTEM IMPACTS

The addition of an SCR would result in additional pressure requirements beyond the 

capabilities of the current fans on the SJGS units. Two options to account for this additional 

pressure drop are new booster fans and new forced draft fans. However, SJGS may be required to 

reduce fugitive emissions from the plant, which are primarily an effect of the boiler’s pressurized 

design. The SCR cost estimates include a new fan with considerations for balance draft conversion.
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BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3-17

3.2.1 Balanced Draft Conversion

Conversion to balanced draft operation would move the balance point (zero relative 

pressure) inside the furnace. SJGS currently operates with the balance point just before the booster 

fans. The following modifications would be necessary for the balanced draft conversion:

 New induced draft fans and motors. 

 Potentially, new motors for the existing forced draft fans to improve fan efficiency.

 Boiler wall stiffening to operate under a negative pressure.

 Ductwork stiffening to operate under a negative pressure.

 Control system modifications.

 Increased power requirements. 

These modifications would require an approximate 12 week unit outage to perform.

A balanced draft unit would have significantly less ash and soot leakage around the boiler 

working area and would experience higher unit availability. As further discussed in Section 5 and 6, 

the full cost of the draft system impacts assign 80% of the cost to the SCR and the remaining 20% to 

the cost of the balanced draft conversion.
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BLACK & VEATCH | Technical Feasibility of Additional Control Technology Alternatives 4-1

4.0 Technical Feasibility of Additional Control Technology 

Alternatives

Technically feasible retrofit emissions control technologies are identified by eliminating 

technically infeasible options. This section describes how the technical feasibility of a control 

technology is defined by the EPA in the BART guidelines. The technologies identified in Step 1 

(Section 3.0) are considered available technologies at the time of issue of this report. 

In the process of eliminating technically infeasible alternatives, it is necessary to 

demonstrate that a technology is not applicable or not available for application at the source. This 

demonstration is made by showing that the technology is commercially unavailable and/or there 

are insurmountable technical difficulties with applying the technology to the applicable unit. Other 

factors that are considered when determining the technical feasibility of a technology include the 

following:

 Size of the unit.

 Location of the proposed technology.

 Operating problems after retrofit of technology.

 Space constraints.

 Reliability.

 Adverse effects on the rest of the facility.

 Adverse community impacts.

Additionally, a technology is technically infeasible if its level of emissions control does not 

achieve the required permit emissions limit applied to the source by the regulating agency. Finally, 

if there are multiple control technologies that achieve the required emission limit, the BART 

procedure allows for the consideration of the less costly control technology, therefore eliminating 

the need to evaluate higher cost technologies.

For all the technologies identified as available in Section 3.0, a determination was made 

regarding the technical feasibility of the technology at the SJGS site on the basis of the criteria 

highlighted above.

4.1 TECHNICALLY INFEASIBLE ADDITIONAL NOX CONTROL TECHNOLOGY 

ALTERNATIVES

4.1.1 Natural Gas Reburn

Natural gas reburn in the SJGS boilers is not technically feasible because of the lack of space 

in the boiler for sufficient residence time for the natural gas reburn zone. The OFA ports limit the 

physical space on the boiler wall for a natural gas reburn system, so as currently configured, there 

is only about 0.25 s of residence time for a fuel gas reburn system. One option would be to move 

the OFA ports up, and thereby providing more residence time for the gas reburn zone. However, 

this benefit to gas reburn would decrease the effectiveness of OFA by inhibiting the mixture of the 
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BLACK & VEATCH | Technical Feasibility of Additional Control Technology Alternatives 4-2

over-fired air. Additionally, gas reburn’s optimal temperature is in the range of 2,600 °F, so 

maintaining a sufficient boiler temperature for gas reburn to work may present an operational 

challenge. Lastly, a new natural gas supply line would be required, since the existing natural gas 

line was abandoned. The exposure to the volatility of natural gas prices is also a negative factor 

when considering natural gas reburn as a NOx control technology. 

In spite of these challenges to natural gas reburn, there is the potential that it could be used 

in combination with another technology to achieve the presumptive federal and state NOx limits. 

The NOx reductions achieved at any of the SJGS units with gas reburn alone may not achieve the 

presumptive NOx limits, but it could achieve enough NOx reductions that the ammonia injection 

required for an SNCR system may be significantly reduced. The same can be said if gas reburn was 

used with an SCR system. All of the combinations that gas reburn can be used with other NOx

control technologies are not further evaluated, because the fact remains that natural gas reburn by 

itself is not a feasible technology at SJGS for meeting NOx limits.

4.1.2 Mobotec ROFA and ROTAMIX

Mobotec’s ROTAMIX technology is not considered technically feasible, because there are no 

current installations at pulverized coal fired boilers of the equivalent size to that of SJGS. The ROFA 

technology is a variant of the OFA system that has already been added as a result of the 

aforementioned consent decree. Although the Mobotec system may offer advantages over 

conventional scrubbing, the increased volumes of particulate that would need to be collected, the 

expected additional costs for sorbent, and the limited large-scale experience with the system are 

significant factors that make it infeasible for this application.

4.1.3 NOxStar

The major consideration for the NOxStar technology is that it currently has only one major 

installation in the United States and may require the installation of a single layer of in-duct catalyst 

(NOxStar Plus) to achieve the advertised levels of NOx reduction. Availability of natural gas is a 

factor that must be considered when assessing the technical feasibility of this technology. There is 

no natural gas supply at SJGS. In addition, through recent discussions, the supplier has identified 

limited ability and willingness to market the commercial technology. 

4.1.4 ECOTUBE

This technology has been demonstrated in installations on industrial/small-sized boilers 

firing solid waste, wood, or biomass. It is not technically feasible to apply this technology to boilers 

of the size as those at SJGS. 
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BLACK & VEATCH | Technical Feasibility of Additional Control Technology Alternatives 4-3

4.1.5 PowerSpan

The PowerSpan process has only been proven on a small scale and has not been applied at 

large-size commercial systems such as SJGS. Therefore, this process is not applicable for retrofit at 

SJGS. In addition, the ECO system has not been pilot tested at a facility burning a low sulfur 

(<1.5 percent) subbituminous coal or in a large, commercial-scale system. Therefore, it is 

considered not technically feasible for retrofit at SJGS. It should be noted that the first full-scale 

commercial unit using this process will be installed in FirstEnergy’s Burger plant. After it is 

installed, a better evaluation of the technical feasibility can be made. 

4.1.6 Phenix Clean Combustion

This technology never moved beyond the demonstration and testing stages, and Phenix 

Limited, LLC is no longer operating. There are no commercial retrofits at facilities similar to SJGS. 

Therefore, this technology is not considered to be applicable for retrofit at SJGS. 

4.1.7 e-SCRUB

The e-SCRUB process no longer appears to be commercially available. Although it appeared 

to offer significant advantages, it was still an experimental system with little proven operational 

data and only one known medium utility-scale installation. Therefore, the e-SCRUB process is not 

considered applicable for retrofit at SJGS.

4.1.8 PerNOxide

PerNOxide has no commercial installations, and remains in the testing/developmental 

stages. Therefore, this technology is not considered to be applicable for retrofit at SJGS. 

4.2 TECHNICAL FEASIBILITY SUMMARY

After the completion of the screening process (Step 2 of the BART determination), the 

following technologies were identified as feasible upgrades at SJGS for NOx reduction:

 SCR

 SNCR

 SNCR with Unit Retirement

The 2007 BART analysis determined the SCR/SNCR hybrid to also be a technically feasible 

technology, it was evaluated further in previous submittal documents, but it is not further 

evaluated as part of this BART update. A summary result of the evaluation process is detailed in 

Table 4-1. Also included in the tables are the reasons for technical infeasibility of the eliminated 

control technologies.
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BLACK & VEATCH | Technical Feasibility of Additional Control Technology Alternatives 4-4

Table 4-1 Technically Feasible Additional NOx Control Technology Alternatives

CONTROL TECHNOLOGY

TECHNICALLY 

FEASIBLE AND 

APPLICABLE? REASONS FOR TECHNICAL INFEASIBILITY

SCR Yes --

SNCR Yes --

SNCR with unit retirement Yes --

SCR/SNCR Hybrid Yes Deemed technically feasible and evaluated previously, but this technology was not 

evaluated further in this BART update.

Gas Reburn No Boilers are not suitable for natural gas reburn process due to lack of residence 

time.

Mobotec ROFA and ROTAMIX No ROTAMIX technology not demonstrated at SJGS scale boiler systems. ROFA will be 

considered as an OFA variant.

ECOTUBE No Not applied to SJGS scale boiler systems.

PowerSpan No In early commercial application stage. Not applied to SJGS scale boiler systems.

Phenix Clean Combustion No No longer commercially available. Not applied to SJGS scale boiler systems.

e-SCRUB No No longer commercially available. Not applied to SJGS scale boiler systems.

PerNOxide No Still in demonstration and testing stage. Not applied to SJGS scale boiler systems.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Evaluation of Technically Feasible Additional Control Technology Alternatives 5-1

5.0 Evaluation of Technically Feasible Additional Control 

Technology Alternatives

This section discusses the control effectiveness evaluation of technically feasible additional 

control technology alternatives for controlling NOx emissions beyond that achieved by technologies 

that were installed for the consent decree. The options for emissions control that are evaluated 

further are the SCR, SNCR, and SNCR with unit retirement and reflect the FIP, SIP, and State 

Alternative BART control scenarios. 

5.1 CONTROL EFFECTIVENESS

Step 3 of a BART analysis determines the control effectiveness of the additional NOx control 

technologies. Control effectiveness is expressed in a common metric based on the amount of 

pollutant generated per unit of heat input (lb/MMBtu). The evaluation of the control effectiveness 

was translated into an hourly rate (lb/hr) for each pollutant, according to the design basis heat 

input data for each SJGS unit. 

Table 5-1 indicates the control effectiveness of each additional NOx control technology. This 

control effectiveness was calculated from the targeted emission values of 0.05 lb/MMBtu for a SCR 

and 0.23 lb/MMBtu for a SNCR. 
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BLACK & VEATCH | Evaluation of Technically Feasible Additional Control Technology Alternatives 5-2

Table 5-1 NOx Control Effectiveness for Additional Control Technology Alternatives (Annual Average Emissions Rates)

NOX CONTROL EFFECTIVENESS

Unit SJGS 1 SJGS 2 SJGS 3 SJGS 4 Plant 

Total NOx

Design Basis Emissions

Heat Input Data, 

MMBtu/h

3,707 3,688 5,758 5,649

NOx Emissions 

Cases

lb/MMBtu lb/hr tpy lb/MMBtu lb/hr tpy lb/MMBtu lb/hr tpy lb/MMBtu lb/hr tpy tpy

Baseline 0.30 1,112 4,410 0.30 1,103 4,119 0.30 1,727 6,431 0.30 1,695 6,309 21,000

SCR 0.05 185.4 690 0.05 184.4 687 0.05 287.9 1,072 0.05 282.5 1,052 3,502

SNCR 0.23 852.6 3,174 0.23 848.2 3,158 0.23 1,324.3 4,931 0.23 1,299.3 4,837 16,100

SNCR with Units 

Retired

0.23 852.6 3,174 -- -- -- -- -- -- 0.23 1,299.3 4,837 8,011

Notes:

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

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

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

4. Yearly emissions (tpy) calculations were based on an annual unit capacity of 85 percent. 
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Impact Analysis and Cost-Effectiveness of Additional Control Technology Alternatives 6-1

6.0 Impact Analysis and Cost-Effectiveness of Additional 

Control Technology Alternatives

This section discusses the impact analysis and cost-effectiveness for SCR and SNCR 

technologies, as well as retiring some units. The cost effectiveness is done on a per unit basis, but 

the final evaluations also take into consideration the entire station’s controls. 

6.1 TYPES OF IMPACT ANALYSES

For all the additional NOx control technologies that are being considered, an impact analysis 

was performed as part of the BART determination process. The purpose of this exercise was to 

quantify the cost of applying the technology at the source, so that a comparison of the costeffectiveness of each technology could be made. In summary, the four types of impact analyses 

performed consisted of the following:

 Costs of compliance.

 Energy impacts.

 Environmental impacts.

 Remaining useful life.

The first step in performing the impact analysis was to define the design parameters for 

each additional NOx control technology that was identified as technically feasible. The design 

parameters contain all pertinent information on the control technology system for specific 

application to the source. Examples of these design parameters include type of reagent used and 

consumption rate, type of byproduct produced and production rate, flue gas pressure drop across 

the control technology, etc. Design parameters for each control technology that were identified as 

technically feasible for application at the SJGS site are summarized in Appendix C along with 

individual cost estimates for the technology options.

6.1.1 Cost of Compliance

Sargent & Lundy developed the cost of compliance based on the requirements for 

implementing each technically feasible control technology. The TCI for each control technology 

when applied specifically to the SJGS site and the annual O&M costs were calculated. The basis for 

this cost calculation was as follows:

 EPA Air Pollution Control Cost Manual - Sixth Edition.

 Budgetary quotes from equipment vendors.

 References to quotes or cost estimation for previous design/build projects or inhouse engineering estimates. No costs are assumed for retiring a unit. 
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BLACK & VEATCH | Impact Analysis and Cost-Effectiveness of Additional Control Technology Alternatives 6-2

6.1.2 Energy Impacts

Energy impacts were estimated for each control technology that consumes auxiliary energy 

during its operation. Only direct energy impacts for each control technology, such as the auxiliary 

power consumption of the control technology and the additional draft system power consumption 

to overcome the additional system resistance, were accounted for. Indirect energy impacts, such as 

the energy to produce raw materials used for the control technology system, were not considered. 

The auxiliary power consumption of the control technology was estimated on the basis of the 

typical power consumption of similar equipment of an equivalent size. The additional draft system 

power consumption was calculated on the basis of the volumetric flow rate of the flue gas through 

the control technology system and the flue gas pressure drop defined in the design parameter of the 

control technology. 

6.1.3 Environmental Impacts

The major non-air quality impacts included in the cost estimates were the water 

consumption demanded by each control technology. All quantities of water consumption were

calculated on a yearly basis. For the SNCR, raw water was assumed to be used for urea dilution and 

makeup water was assumed for the closed cooling water system. A water treatment system was 

added for the raw water’s use in diluting the urea solution, but it is not used for cleaning outgoing 

water. 

The following non-air quality environmental impacts were not included in the cost 

estimates.

 Byproduct and waste disposal – there is no significant impact to the current 

operations due to the addition of either an SCR or SNCR.

 Wastewater discharge – there is no wastewater discharge from either technology.

The SCR and SNCR technologies exclusively reduce NOx emissions, but the State Alternative 

has significant environmentally beneficial impacts as compared to the FIP and the SIP scenarios, 

resulting in a reduction of overall air emissions, water consumption, raw materials use, and coal 

combustion residues (CCRs) generated during plant operations. 

Table 6-1 shows selected pollutants, including CO2, and hazardous air pollutants (HAPs) 

emissions reductions for the State Alternative as compared to the SIP and the FIP scenarios. As can 

be seen from the table, the State Alternative reduces the emissions of NOx by 62 percent overall. 

Additionally, the State Alternative also reduces other air pollutants while the other options have no 

impact as the technology focus is only on NOx where the State Alternative includes Units 2 and 3 

retirements. By retiring two units, sensibly, the reduction in SJGS emissions is about half for the 

listed pollutants.
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BLACK & VEATCH | Impact Analysis and Cost-Effectiveness of Additional Control Technology Alternatives 6-3

Table 6-1 SJGS Pollutant Emissions, Facility Wide

SCENARIO

POLLUTANTS (TPY)

NOX SO2 PM CO CO21 VOC HG2

Non-Hg 

Metals

Acid 

Gases

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

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

State Alternative % 

Reduction

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

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

NMED SIP % Reduction 23% 0% 0% 0% 0% 0% 0% 0% 0%

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

EPA FIP % Reduction 83% 0% 0% 0% 0% 0% 0% 0% 0%

Notes:

1. CO2 numbers from the 2011 EPA Clean Air Markets Division database based upon 2011 operating data.

2. Hg numbers based on 1.2 lb/MMBtu Mercury and Air Toxics Standard (MATS) Limit.

3. Non-Hg metals and acid gas air emissions from 2011 SJGS TRI.

4. Consistent with the cost analysis, a 30-year service life was assumed.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Impact Analysis and Cost-Effectiveness of Additional Control Technology Alternatives 6-4

In addition to the decrease in overall pollutant emissions, the State Alternative will 

significantly reduce fugitive total suspended particulate (TSP) emissions by approximately 50% 

from 407 tpy (2011 TRI) to 204 tpy. These reductions result from:

 Decrease in coal handling,

 Fewer TSP emissions from the pulverizer,

 Reduction in TSP from duct leaks,

 Lower emissions from the handling of CCRs (i.e., fly ash and bottom ash, spent 

activated carbon and scrubber gypsum), and 

 Decreased emissions from both paved and unpaved roads resulting from fewer CCR 

trucks traveling to the mine and fewer truck deliveries of raw materials 

Regional Benefits from Reduced Raw Material Usage

The reduced raw material deliveries that result from the State Alternative also has the 

residual benefits of reducing criteria pollutant and GHG emissions from trucks hauling these 

materials over the highways, and a reduction in emissions generated during the manufacture and 

processing of the raw materials. Table 6-2 shows the estimated annual raw material usage rate 

from the State Alternative as compared to the FIP and SIP scenarios, and the current operations 

(Baseline). In general, the State Alternative raw material usage rate is estimated to be 50 percent 

less than current conditions or those expected under the other scenarios.

Table 6-2 Raw Material Usage, Facility Wide

RAW MATERIAL

STATE ALTERNATIVE

(TPY)

BASELINE, FIP, AND 

SIP SCENARIOS

(TPY)

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

(1)Based on 2012 material usage data.

(2)Based on 2011 material usage data.

Water and Wastewater Usage Benefits

The SJGS is located in an area of the country in which water is a critical resource. Based on 

the 2011 SJGS water use data, under the Baseline, FIP, and SIP scenarios, SJGS will consume 

approximately 21,000 acre-feet of water per year. With the adoption of the State Alternative, water 

usage is estimated to drop by approximately 53% to 10,161 acre-feet/year. Concentrated 

wastewater, which includes total and suspended solids from the wastewater management process, 

periodic boiler cleaning wastes and other process wastes, are discharged to on-site evaporation 
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Impact Analysis and Cost-Effectiveness of Additional Control Technology Alternatives 6-5

ponds under a zero discharge NPDES permit6

Solid Waste Disposal Benefits

and a state regulated discharge permit. Under this 

scenario , the generation of wastewater will be decreased by approximately 50 percent from 

41 million gallons/year (2011 data) down to approximately 21 million gallons/year. For the FIP

Scenario, the wastewater generation will remain roughly the same rate as in 2011.

In 2011, the SJGS disposed of approximately 1.426 million tons of fly and bottom ash along 

with 282,000 tons of gypsum generated from sulfur scrubbing operations and 261 tons of spent 

brominated activated carbon used to control mercury emissions. The total waste, 1.71 million 

tons/year, is disposed of at the San Juan Mine. Similar waste generation rates would be expected 

under the FIP and SIP. However, the State Alternative solid waste generation would be reduced by 

approximately 50% resulting in a reduction of approximately 854,130 tpy. 

As an added benefit, SNCR technology, as called for in the State Alternative, will not require 

the use of a catalyst for NOx reduction, which would periodically result in the replacement of spent 

catalyst due to catalyst poisoning by a number of alkali metals and trace elements. These catalyst 

poisons cause the catalyst to be treated as a hazardous waste during disposal, and this requires 

special handling and disposal practices. The FIP scenario requires the use of catalyst.

6.1.4 Remaining Useful Life

Finally, the impact of the remaining useful life of the control technology on its costeffectiveness was considered. For this BART analysis, the remaining useful life of the controls was 

defined as 30 years. Therefore, there was no additional life impact cost for the additional control 

technologies. 

6.2 COST-EFFECTIVENESS

The cost-effectiveness of each control technology was calculated from the cost of 

compliance and the amount of pollutant reduced. The cost-effectiveness is defined as the cost of 

control per amount of pollutant removed. The cost of control takes into account the impact 

analyses performed. The reduced emissions were estimated on a yearly basis according to the 

reduction from the Baseline emissions level shown in Table 6-1. The cost-effectiveness results are 

presented in Table 6-3. In addition to the cost effectiveness values, another method of comparing 

costs is incremental cost-effectiveness, which is the change in cost that results from comparing one 

control option to another. The incremental cost effectiveness indicates the additional cost to 

increase the removal of pollutant when comparing technologies that have different emission 

removal capabilities. This metric is particularly useful when comparing several control 

technologies’ costs at the same unit. The incremental cost effectiveness in thousands of dollars per 

ton of emission reduced to go from an SNCR to an SCR is $6,762/ton for Unit 1, $7,766/ton for 

Unit 2, $6,326/ton for Unit 3, and $5,636/ton for Unit 4. The cost-effectiveness values were based 

on 2013 dollars. 

 6 NPDES Permit N. NM0028606, issued February 2011.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Impact Analysis and Cost-Effectiveness of Additional Control Technology Alternatives 6-6

Table 6-3 Impact Analysis and Cost-Effectiveness Results of Additional NOx Control Technologies

IMPACT ANALYSIS AND COST EFFECTIVENESS RESULTS OF NOX CONTROLS FOR SJGS

ALL FEASIBLE 

TECHNOLOGIES

NOx EMISSIONS 

PERFORMANCE 

LEVEL

(LB/MMBTU)

EXPECTED NOx

EMISSION RATE

(LB/HR)

EXPECTED NOx

EMISSION RATE

(TPY)

EXPECTED NOx 

EMISSION 

REDUCTION

(TPY)

TOTAL CAPITAL 

INVESTMENT 

(TCI)

(1,000$)

TOTAL 

ANNUALIZED 

COST (TAC)

(1,000$)

COST 

EFFECTIVENESS

($/TON)

ENERGY IMPACTS

(1,000$)

NON-AIR 

ENVIRONMENTAL 

IMPACTS 

(1,000$)

FEDERAL IMPLEMENTATION PLAN - SCR ALL UNITS

SJGS 1 - SCR 0.05 185.4 690 3,450 180,862 22,165 6,425 746 --

SJGS 2 - SCR 0.05 184.4 687 3,433 180,862 24,562 7,157 729 --

SJGS 3 - SCR 0.05 287.9 1,072 5,359 264,208 32,585 6,080 1,107 --

SJGS 4 - SCR 0.05 282.5 1,052 5,258 235,940 29,508 5,613 1,102 --

Total 940 3,500 17,500 861,871 108,820 6,218 3,683

STATE IMPLEMENTATION PLAN - SNCR ALL UNITS

SJGS 1 - SNCR 0.23 852.6 3,174 966 17,392 5,400 5,590 43 --

SJGS 2 - SNCR 0.23 848.2 3,158 961 17,392 5,400 5,618 43 --

SJGS 3 - SNCR 0.23 1,324.3 4,931 1,501 17,163 8,224 5,480 51 --

SJGS 4 - SNCR 0.23 1,299.3 4,837 1,472 17,163 8,224 5,587 51 --

Total 4,324 16,100 4,900 69,111 27,248 5,561 187

STATE ALTERNATIVE - SNCR UNITS 1 & 4

SJGS 1 - SNCR 0.23 852.6 3,174 966 17,392 5,400 5,590 43 --

SJGS 2 - Retire n/a n/a n/a 4,119 n/a n/a n/a n/a --

SJGS 3 - Retire n/a n/a n/a 6,431 n/a n/a n/a n/a --

SJGS 4 - SNCR 0.23 1,299.3 4,837 1,472 17,163 8,224 5,587 51 --

Total 2,152 8,011 12,989 34,556 13,624 1,049 94

Notes:

1. Costs for all technologies are shown in 2013 dollars.

2. Expected emission rates (tpy) calculations were based on 85 percent unit capacity factor.

3. Expected emission reduction (tpy) calculations were based on control effectiveness described in submittal and baseline emissions (refer to June 6, 2007 BART Application Document).

4. Cost-effectiveness ($/ton) is defined as ratio of TAC over Expected Emission Reduction (tpy).

5. Expected emission reduction is based on annual emission reduction from Baseline emission levels technologies.

6. Incremental cost effectiveness are based on increments in expected emission reduction (tpy), but do not apply in this table since technologies are the same.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Impact Analysis and Cost-Effectiveness of Additional Control Technology Alternatives 6-7

6.2.1 Cost-Effectiveness Comparison

For all the additional NOx control technologies evaluated, a summary table was developed 

for the impact analysis performed and the resultant cost-effectiveness. Table 6-3 presents the final 

evaluations for all four units. The expected after-control emissions levels are also included in the 

table. Cost-Effectiveness Comparison Table 6-3 clearly shows that on a facility wide basis the State 

Alternative is the most cost effective scenario at $1,050/ton verses the SIP at $5,561/ton and the 

FIP at $6,228/ton.

The SCR is the most expensive option, because of the TCI and TAC are significantly more 

expensive than the other options. Additionally, the energy impacts for the FIP scenario are much 

higher than the other options primarily because of the pressure drop across the SCR. The State 

Alternative is significantly less expensive, because emissions from two units are completely 

eliminated at no cost by retiring the units. Looking between the units, Unit 1 and 2 costs are 

approximately the same, and Unit 3 costs are higher than Unit 4. This difference is due to the 

additional cost required for the installation of these technologies on the inside units. Specifically, 

the four units were built side-by-side in a row with minimum spacing between units. Units 1 and 4 

are outside units, whereas, Units 2 and 3 are inside units. Thus, accessibility to Units 2 and 

especially 3 is limited by the plant layout and the presence of other balance-of-plant equipment, 

such as the coal conveyor. The reduced accessibility means that the SCR system will need to be 

built in smaller pieces, thus increasing construction costs as compared to their sister units.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-1

7.0 Visibility Impacts

Visibility impact is the fifth step to consider in the engineering analysis required under the 

EPA BART guidelines. This step addresses the degree of improvement in visibility that may 

reasonably be anticipated to result from the use of the ‘‘best control technology’’ for sources subject 

to BART. Visibility impact analysis is typically achieved through a two phase process. First, the 

model was run using the current conditions to establish a baseline. In this analysis, the baseline 

consisted of the technologies and unit operations associated with the baseline. Second, model runs 

were conducted for the control technologies identified for each unit on a facility basis. The model 

results were then tabulated for the baseline and BART control technology scenarios over the time 

period of the meteorology modeled. The difference in the maximum value between the first and 

second stage is the expected degree of improvement in visibility. As previously noted, this is an 

addendum to the previously submitted analysis which compares resulting visibility from various 

control technology options to the baseline conditions. The baseline conditions and resulting 

visibility are included and comparisons have been made for the BART control technologies and the 

resulting visibility compared to the EPA FIP technology scenario. The following sections discuss the 

modeling methodology in greater detail.

7.1 INTRODUCTION

The objective of this modeling analysis is to evaluate visibility impacts for the control 

technologies selected using the first four steps of the BART analysis (as discussed in the previous 

sections) for PNM’s SJGS pre-BART and post-BART scenarios. 

The air dispersion modeling analyses presented in this report were conducted in 

accordance with the EPA Technical Support Document (TSD).

Black & Veatch conducted BART air modeling analyses using the CALPUFF air dispersion 

modeling system for the PNM SJGS. To aid potential settlement discussions with EPA and for 

consistency with EPA’s previous modeling conducted as part of EPA’s proposed 2011 Federal 

Implementation Plant (FIP)7, Black & Veatch utilized the EPA CALPUFF modeling information 

provided as part of a Freedom of Information Act (FOIA) request and described in a technical 

support document8 (Appendix D). Specifically, Black & Veatch used the compiled CALMET data set, 

EPA specified model versions, and modified EPA’s modeling input files to include the source specific 

parameters for the modeling scenarios described below. This modeling also assumed constant 

background ammonia. Therefore, as EPA’s FIP methodology was utilized a modeling protocol was 

not developed for this analysis.

 7 Federal Register/ Vol. 76, No. 3/ Wednesday, January 5, 2011. EPA-R06-OAR-0846-0001. 8 Technical Support Document; Visibility Modeling for BART Determination: San Juan Generating Station, New 

Mexico. EPA-R06-OAR-0846-0003.
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BLACK & VEATCH | Visibility Impacts 7-2

Black & Veatch conducted initial verification modeling using EPA’s FIP modeling runs 

provided in the FOIA request to ensure consistency. The results of the EPA FIP run by Black & 

Veatch matched EPA’s modeling results, indicating that the modeling methodologies and inputs 

utilized in this analysis were the same as those employed by the EPA. These results were made 

available to EPA on September 19, 2012. Black & Veatch conducted four modeling runs 

representing the baseline and three BART technology scenarios using the EPA methodology; these 

scenarios are further detailed in Section 7.5.

7.2 SOURCE DESCRIPTION

The SJGS facility is located in Farmington, New Mexico, within San Juan County. It has four 

pulverized coal units that are BART-eligible: Units 1, 2, 3 and 4. Units 1 and 2 are single, wall-fired 

Foster Wheeler boilers each rated at 370 MW gross. Units 3 and 4 are B&W subcritical, opposed 

wall-fired boilers that operate in a forced draft mode and are both rated at 544 MW gross.

7.3 LOCATION OF SOURCES VERSUS RELEVANT CLASS I AREAS

The Western Regional Air Partnership Regional Modeling Center (WRAP RMC) published a 

draft report on November 8, 2006 (WRAP Protocol). The NMED used this protocol to identify the 

four BART-applicable sources at the SJGS facility in January of 2007. With this information, it was 

determined there were 16 Class I areas within 300 km of SJGS. These Class I areas must be 

addressed in Step 5 of the BART analysis. The aforementioned EPA FIP modeling conducted in 

2011 also analyzed these same 16 Class I areas. The 16 Class I areas analyzed are identified in 

Table 7-1 and the location of these 16 Class I areas in relation to SJGS are illustrated on Figure 7-1.

Table 7-1 Class I Areas

NATIONAL PARKS AND WILDERNESS AREAS WITHIN 300 KILOMETERS OF SJGS

1. Mesa Verde 9. West Elk 

2. Weminuche 10. Arches 

3. San Pedro Parks 11. Capitol Reef 

4. La Garita 12. Pecos 

5. Canyonlands 13. Wheeler Peak 

6. Black Canyon of the Gunnison 14. Great Sand Dunes 

7. Bandelier 15. Maroon Bells 

8. Petrified Forest 16. Grand Canyon 
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-3

Figure 7-1 Location of SJGS and Class I Areas

7.4 CALPUFF MODEL SELECTION

The CALPUFF modeling system is recommended as the preferred modeling approach for 

use in BART analyses. CALPUFF and its meteorological model, CALMET, are designed to handle the 

complexities posed by complex terrain, large source-receptor distances, chemical transformation 

and deposition, as well as other issues related to Class I visibility impacts. The CALPUFF modeling 

system has been adopted by the EPA as a guideline model for source-receptor distances greater 

than 50 kilometers and for use on a case-by-case basis in complex flow situations for shorter 

distances (68 FR 18440-18482). CALPUFF is recommended for Class I impact assessments by the 

Federal Land Managers Workgroup (FLAG 2000 and FLAG 20109

) and the Interagency Workgroup 

on Air Quality Modeling (IWAQM) (EPA 1998). The final BART guidance recommends CALPUFF as 

“the best modeling application available for predicting a single source’s contribution to visibility 

impairment” (70 FR 39122). 

 9 FLAG 2010 updated several CALPUFF parameters contained in FLAG 2000 and reaffirmed CALPUFF to be the Class 

I model of choice.

-1500 -1400 -1300 -1200 -1100 -1000 -900 -800 -700 -600

X LCC (km)

-700

-600

-500

-400

-300

-200

-100

0

Y LC

C (km)

Petrified 

Forest

Grand

Canyon

Capitol

Reef

Canyonlands

Arches

Black Canyon

of the

Gunnison

West

Elk

Maroon Bells

Snowmass

Mesa Verde

Weminuche

La Garita

Great

Sand Dunes

San Pedro 

Parks

Bandelier

Pecos

Wheeler

Peak

PNM SJGS
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-4

CALPUFF is a non-steady-state, Lagrangian, puff transport and dispersion model that 

advects Gaussian puffs of multiple pollutants from modeled sources. CALPUFF’s algorithms have 

been designed to be applicable on spatial scales from a few tens of meters to hundreds of 

kilometers from a source. It includes algorithms for near-field effects such as building downwash, 

stack tip downwash, and transitional plume rise, as well as processes important in the far-field, 

such as chemical transformation, wet deposition, and dry deposition. CALPUFF contains an option 

to allow puff splitting in the horizontal and vertical directions, which extends the distance range of 

the model. The primary outputs from CALPUFF are hourly concentrations and hourly deposition 

fluxes evaluated at user-specified receptor locations. 

The modeled CALPUFF domain, receptors, constant ammonia concentrations, ozone, and 

CALMET data used in the analysis all came directly from the EPA modeling. The versions of the 

CALPUFF modeling system used for this analysis were also consistent with the aforementioned EPA 

modeling described in the TSD.

7.5 TECHNOLOGY SCENARIOS

The modeling analysis includes various combinations of control technologies including SCR, 

SNCR, and also considers SNCR and a two-unit retirement as an alternative operating scenario. 

Additionally, the BART modeling incorporated the SJGS’s new SO2 and total particulate matter 

(TPM) emission rates of 0.15 lb/MMBtu and 0.034 lb/MMBtu, respectively, in the current NSR 

Permit10

 Scenario 1: Baseline. Units 1-4 operating only with existing air pollution control 

technology and new permitted SO2 and TPM emission rates of 0.15 lb/MMBtu and 

0.034 lb/MMBtu, respectively.

dated August 31, 2012 (refer to Appendix B). It is understood that these new pollutant 

emission rates were the result of either voluntary or a required permit action not associated with 

or related to the BART process. Therefore, these new emission limits have been incorporated into 

the Baseline scenario, as well as the three BART technology scenarios. Additionally, BART 

modeling for the State Alternative includes the TPM emission rates as discussed above and a 

reduced SO2 emission rate of 0.10 lb/MMBtu as agreed upon in the Term Sheet between EPA, NMED 

and PNM. Below are the four scenarios that were evaluated:

 Scenario 2: EPA Federal Implementation Plan (FIP). 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.

 10 NSR Permit No. 0063-M8.
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BLACK & VEATCH | Visibility Impacts 7-5

 Scenario 3: New Mexico Environmental Department (NMED) State 

Implementation Plan (SIP). 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.

 Scenario 4: State Alternative. 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, new permitted TPM emission rate 0.034 lb/MMBtu, and a reduced 

SO2 emission rate of 0.10 lb/MMBtu (as specified in the Term Sheet).

7.6 STACK PARAMETERS AND EMISSIONS DATA

As previously presented in Sections 5 through 6 of this report, three different emissions 

control strategies, and technologies beyond the baseline, have been evaluated for SJGS. The baseline 

emissions for PM, NOX, SO2, and sulfur acid mist (H2SO4)

11

As described in the June 2007 BART application, the H2SO4 (or SO4)

were based on emissions limits from the 

SJGS Air Permit. The baseline and BART control scenarios stack parameters are presented in 

Tables 7-2, 7-4, 7-6, and 7-8, respectively, and are consistent with the parameters utilized in 

previous BART addendum submittals. The stack parameters remained constant for the different 

technologies due to the fact that types of control technologies analyzed made no difference in exit 

velocity or stack temperature. The baseline and BART control scenario emissions are presented in 

Tables 7-3, 7-5, 7-7, and 7-9, respectively. 12 emissions included in 

the previous CALPUFF BART modeling were derived from the speciation of particulate matter 

utilizing the Federal Land Managers National Park Service (NPS) speciation profiles13

For this analysis, speciation of particulate matter generally followed the same 

procedures/methodologies described in the June 2007 BART application and used in previous 

modeling analyses to support the SJGS BART process. The difference in the modeling provided in 

this revised analysis is that now permit-specific TPM emissions data was provided (rather than 

solely having filterable emissions data previously), which allowed Black & Veatch to use a more 

reasonable estimation of condensable particulate matter rather than using the condensable 

estimation provided by the NPS spreadsheets. The actual speciation of the particulate matter 

continued to follow the NPS methodology to derive emissions for such particulate-based categories 

as elemental carbon, soil, secondary organic aerosols, and coarse particulate matter.

(speciation 

spreadsheets) available online to derive the relative fraction of fine and course particles. Tables 1

through 4 (included in Appendix E) illustrate the data used for the aforementioned scenarios on a 

unit by unit basis. In addition to the data shown in Tables 1 through 4, CALPUFF requires 

particulate matter to be further broken down into various size categories, with each category 

impacting light extinction to varying degrees-known as speciation. 

 11 H2SO4 emission limit contained within the SJGS air permit is applicable to SCR technology installation. 12 SO4 emission data was conservatively assumed to equal SO3. 13 http://www2.nature.nps.gov/air/permits/ect/index.cfm
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BLACK & VEATCH | Visibility Impacts 7-6

As with prior modeling analyses, condensable particulate matter was subdivided into 

organic and inorganic compounds with 20 percent of the condensable particulate matter being 

classified as organic matter and modeled as secondary organic aerosols (SOA) in CALPUFF. Unlike 

previous analyses, however, neither this analysis nor the EPA’s analysis assumed the remaining 80 

percent of the condensable particulate matter (i.e., inorganic matter) was SO4 (or SO3) as the NPS 

speciation profile would suggest in lieu of having any other SO4 emissions data. Rather, for this 

analysis emission data was directly input to the model using data from the EPA for the non-SCR 

scenarios (i.e., Baseline and SNCR) at an emission rate of approximately 0.000046 lb/MMBtu from 

EPA’s FIP modeling. The SO4 rate for the SCR scenario assumes the stack outlet emission rate of 

0.00026 lb/MMBtu from SJGS’s new permit and is consistent with the EPA’s FIP methodology

(SCR). 

Table 7-2 Baseline Modeling Stack Parameters

UNIT

STACK LOCATION(1)

STACK 

HEIGHT 

(M)

BASE 

ELEVATION 

(M)

STACK 

DIAMETER 

(M)

STACK EXIT 

VELOCITY 

(M/S)

STACK EXIT 

TEMP (K)

LCC EAST 

(KM)

LCC 

NORTH 

(KM)

SJGS 1 -1010.859 -290.127 121.92 1,615.44 6.10 21.34 322.83

SJGS 2 -1010.859 -290.127 121.92 1,615.44 6.10 21.34 322.83

SJGS 3 -1010.859 -290.127 121.92 1,615.44 8.53 17.07 322.83

SJGS 4 -1010.859 -290.127 121.92 1,615.44 8.53 16.76 322.83

(1)Stack coordinates in Lambert format included in the CALPUFF modeling.

Table 7-3 Baseline Emission Rates

UNIT

NOX

EMISSION 

RATE 

(LB/HR)

SO2

EMISSION 

RATE 

(LB/HR)

EC 

(LB/HR)

FINE PM 

(LB/HR)

COURSE 

PM 

(LB/HR)

H2SO4 

(LB/HR)

SOA 

(LB/HR)

SJGS 1 1,223.3 556.1 1.51 30.56 23.57 0.17 14.09

SJGS 2 1,217.0 553.2 1.51 30.40 23.49 0.17 14.01

SJGS 3 1,900.1 863.7 2.38 47.46 36.67 0.27 21.88

SJGS 4 1,864.2 847.4 2.30 46.59 35.95 0.26 21.47
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-7

Table 7-4 EPA FIP Modeling Stack Parameters

UNIT

STACK LOCATION(1)

STACK 

HEIGHT 

(M)

BASE 

ELEVATION 

(M)

STACK 

DIAMETER 

(M)

STACK EXIT 

VELOCITY 

(M/S)

STACK EXIT 

TEMP (K)

LCC EAST 

(KM)

LCC 

NORTH 

(KM)

SJGS 1 -1010.859 -290.127 121.92 1,615.44 6.10 21.34 322.83

SJGS 2 -1010.859 -290.127 121.92 1,615.44 6.10 21.34 322.83

SJGS 3 -1010.859 -290.127 121.92 1,615.44 8.53 17.07 322.83

SJGS 4 -1010.859 -290.127 121.92 1,615.44 8.53 16.76 322.83

(1)Stack coordinates in Lambert format included in the CALPUFF modeling.

Table 7-5 EPA FIP Emission Rates

UNIT

NOX

EMISSION 

RATE 

(LB/HR)

SO2

EMISSION 

RATE 

(LB/HR)

EC 

(LB/HR)

FINE PM 

(LB/HR)

COURSE 

PM 

(LB/HR)

H2SO4 

(LB/HR)

SOA 

(LB/HR)

SJGS 1 185.4 556.1 1.51 30.56 23.57 0.96 14.09

SJGS 2 184.4 553.2 1.51 30.40 23.49 0.96 14.01

SJGS 3 287.9 863.7 2.38 47.46 36.67 1.50 21.88

SJGS 4 282.5 847.4 2.30 46.59 35.95 1.47 21.47
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-8

Table 7-6 NMED SIP Modeling Stack Parameters

UNIT

STACK LOCATION(1)

STACK 

HEIGHT 

(M)

BASE 

ELEVATION 

(M)

STACK 

DIAMETER 

(M)

STACK EXIT 

VELOCITY 

(M/S)

STACK EXIT 

TEMP (K)

LCC EAST 

(KM)

LCC 

NORTH 

(KM)

SJGS 1 -1010.859 -290.127 121.92 1,615.44 6.10 21.34 322.83

SJGS 2 -1010.859 -290.127 121.92 1,615.44 6.10 21.34 322.83

SJGS 3 -1010.859 -290.127 121.92 1,615.44 8.53 17.07 322.83

SJGS 4 -1010.859 -290.127 121.92 1,615.44 8.53 16.76 322.83

(1)Stack coordinates in Lambert format included in the CALPUFF modeling.

Table 7-7 NMED SIP Emission Rates

UNIT

NOX

EMISSION 

RATE 

(LB/HR)

SO2

EMISSION 

RATE 

(LB/HR)

EC 

(LB/HR)

FINE PM 

(LB/HR)

COURSE 

PM 

(LB/HR)

H2SO4 

(LB/HR)

SOA 

(LB/HR)

SJGS 1 852.6 556.1 1.51 30.56 23.57 0.17 14.09

SJGS 2 848.2 553.2 1.51 30.40 23.49 0.17 14.01

SJGS 3 1,324.30 863.7 2.38 47.46 36.67 0.27 21.88

SJGS 4 1,299.30 847.4 2.30 46.59 35.95 0.26 21.47
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-9

Table 7-8 State Alternative Stack Parameters

UNIT

STACK LOCATION(1)

STACK 

HEIGHT 

(M)

BASE 

ELEVATION 

(M)

STACK 

DIAMETER 

(M)

STACK EXIT 

VELOCITY 

(M/S)

STACK EXIT 

TEMP (K)

LCC EAST 

(KM)

LCC 

NORTH 

(KM)

SJGS 1 -1010.859 -290.127 121.92 1,615.44 6.10 21.34 322.83

SJGS 2 N.A. N.A. N.A. N.A. N.A. N.A. N.A.

SJGS 3 N.A. N.A. N.A. N.A. N.A. N.A. N.A.

SJGS 4 -1010.859 -290.127 121.92 1,615.44 8.53 16.76 322.83

(1)Stack coordinates in Lambert format included in the CALPUFF modeling.

Table 7-9 State Alternative Emission Rates

UNIT

NOX

EMISSION 

RATE 

(LB/HR)

SO2 

EMISSION 

RATE 

(LB/HR)

EC 

(LB/HR)

FINE PM 

(LB/HR)

COURSE 

PM 

(LB/HR)

H2SO4 

(LB/HR)

SOA 

(LB/HR)

SJGS 1 852.6 370.7 1.51 30.56 23.57 0.17 14.09

SJGS 2 N.A. N.A. N.A. N.A. N.A. N.A. N.A.

SJGS 3 N.A. N.A. N.A. N.A. N.A. N.A. N.A.

SJGS 4 1,299.30 564.9 2.30 46.59 35.95 0.26 21.47
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-10

7.7 LIGHT EXTINCTION AND DECIVIEW IMPACT

Consistent with the EPA’s TSD, the “revised” IMPROVE equation was to calculate light 

extinction14

The BART guidelines recommend that impacts of sources be estimated in deciviews relative 

to natural background. Consistent with EPA’s TSD, Black & Veatch used average background 

concentrations and relative humidity adjustment factors from the Federal Land Managers‘ Air 

Quality Related Values Work Group (FLAG) Phase I Report for use with the revised IMPROVE 

equation (“Method 8”)

. The revised IMPROVE equation is used to convert measured or modeled 

concentrations into extinction for each pollutant chemical species, and then total them up, 

accounting for the effect of relative humidity. Additionally, in the second CALPOST step the light 

extinction is converted to deciviews, using the defining equation for deciviews. The delta deciview 

(Δdv) represents the impact on visibility in deciviews of the source being evaluated, which is 

provided by CALPUFF. It is the change, or “delta”, between deciviews with and without the source. 

From the BART guidelines, delta deciviews is the difference between deciviews including both the 

source and the natural background alone. Each modeled day and location in the Class I area will 

have an associated delta deciview. For each day the model finds the maximum visibility for all 

receptors in the Class I area. From this point, BART guidelines use the 98th percentile, 8th high, 

visibility impacts expressed in 24-hour averages of delta deciviews relative to natural background, 

as estimated using the CALPUFF air quality modeling system for comparing the scenario and effects 

of various controls. The 98th percentile is used instead of the maximum value to avoid unusual 

meteorological conditions and conservative assumptions in the model. 

15.

 14 Pitchford, M. L., W. C. Malm, B. A. Schichtel, N. Kumar, D. Lowenthal and J. L. Hand, Revised algorithm for 

estimating light extinction from IMPROVE particle speciation data, Journal of the Air & Waste Management 

Association, 57, 1326-1336, 2007. 15 U.S. Forest Service, National Park Service, and U.S Fish and Wildlife Service. 2010. Federal land managers’ air 

quality related values work group (FLAG): phase I report-revised (2010). Natural Resource Report NPS/NRPC/NRR2010/232. National Park Service, Denver, Colorado

(http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf)
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-11

7.8 MODELING RESULTS

7.8.1 Baseline Scenario

The results of baseline scenario modeling are presented in Table 7-10. The baseline 

scenario impacts were used to establish a comparison for the BART control technology impacts. 

Table 7-10 Baseline Visibility Results, 98th Percentile (dv)

CLASS I AREA 2001 2002 2003 AVERAGE MAXIMUM

Arches 3.51 0.96 1.52 1.99 3.51

Bandilier 1.40 1.30 1.03 1.24 1.40

Black Canyon 1.36 1.41 0.63 1.13 1.41

Canyonlands 4.66 2.12 2.29 3.02 4.66

Capitol Reef 2.39 0.46 0.66 1.17 2.39

Grand Canyon 0.93 0.26 0.38 0.52 0.93

Great Sand Dunes 0.85 1.54 1.08 1.16 1.54

La Garita 1.39 1.94 1.14 1.49 1.94

Maroon Bells 0.71 0.61 0.34 0.55 0.71

Mesa Verde 5.16 5.22 5.02 5.13 5.22

Pecos 0.94 1.27 1.03 1.08 1.27

Petrified Forest 0.52 0.46 0.38 0.45 0.52

San Pedro 2.21 1.98 2.08 2.09 2.21

West Elk 1.59 1.43 0.68 1.24 1.59

Weminuche 2.15 2.95 2.02 2.37 2.95

Wheeler Peak 1.12 1.10 0.91 1.04 1.12
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-12

7.8.2 BART Control Technology Scenarios

The results of the modeling for the BART emissions control technology scenarios are 

presented in Tables 7-11 through 7-13. Table 7-11 illustrates the EPA FIP scenario and resultant 

visibility impacts of the entire facility using SCR technology installation on each unit. Table 7-12 

illustrates the NMED SIP scenario and resultant visibility impacts of the entire facility using SNCR 

technology installation on each unit. Finally, Table 7-13 illustrates the State Alternative scenario 

and resultant visibility impacts of Units 2 & 3 retired and Units 1 & 4 with new SNCR installation. 

Table 7-11 EPA FIP Visibility Results, 98th Percentile (dv)

CLASS I AREA 2001 2002 2003 AVERAGE MAXIMUM

Arches 1.13 0.49 0.46 0.69 1.13

Bandilier 0.49 0.49 0.42 0.47 0.49

Black Canyon 0.42 0.42 0.26 0.36 0.42

Canyonlands 1.57 0.69 0.75 1.00 1.57

Capitol Reef 0.83 0.25 0.32 0.47 0.83

Grand Canyon 0.33 0.13 0.20 0.22 0.33

Great Sand Dunes 0.32 0.50 0.35 0.39 0.50

La Garita 0.50 0.58 0.36 0.48 0.58

Maroon Bells 0.28 0.19 0.14 0.20 0.28

Mesa Verde 2.17 2.15 2.33 2.22 2.33

Pecos 0.40 0.48 0.33 0.40 0.48

Petrified Forest 0.20 0.16 0.22 0.19 0.22

San Pedro 0.72 0.75 0.67 0.71 0.75

West Elk 0.46 0.40 0.23 0.37 0.46

Weminuche 0.83 0.92 0.73 0.82 0.92

Wheeler Peak 0.42 0.45 0.32 0.40 0.45
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-13

Table 7-12 NMED SIP Visibility Results, 98th Percentile (dv)

CLASS I AREA 2001 2002 2003 AVERAGE MAXIMUM

Arches 2.67 0.72 1.15 1.51 2.67

Bandilier 1.08 0.98 0.80 0.96 1.08

Black Canyon 1.01 1.07 0.47 0.85 1.07

Canyonlands 3.71 1.62 1.81 2.38 3.71

Capitol Reef 1.82 0.38 0.56 0.92 1.82

Grand Canyon 0.72 0.24 0.30 0.42 0.72

Great Sand Dunes 0.65 1.15 0.81 0.87 1.15

La Garita 1.05 1.47 0.85 1.12 1.47

Maroon Bells 0.53 0.46 0.27 0.42 0.53

Mesa Verde 4.67 4.43 4.47 4.52 4.67

Pecos 0.73 1.00 0.78 0.84 1.00

Petrified Forest 0.39 0.34 0.31 0.34 0.39

San Pedro 1.72 1.56 1.59 1.62 1.72

West Elk 1.21 1.07 0.51 0.93 1.21

Weminuche 1.74 2.36 1.61 1.90 2.36

Wheeler Peak 0.86 0.83 0.67 0.79 0.86
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-14

Table 7-13 State Alternative Visibility Results, 98th Percentile (dv)

CLASS I AREA 2001 2002 2003 AVERAGE MAXIMUM

Arches 1.37 0.35 0.55 0.76 1.37

Bandilier 0.52 0.48 0.39 0.46 0.52

Black Canyon 0.49 0.52 0.22 0.41 0.52

Canyonlands 1.99 0.82 0.91 1.24 1.99

Capitol Reef 0.89 0.16 0.24 0.43 0.89

Grand Canyon 0.33 0.09 0.13 0.18 0.33

Great Sand Dunes 0.31 0.57 0.39 0.42 0.57

La Garita 0.50 0.71 0.41 0.54 0.71

Maroon Bells 0.26 0.21 0.12 0.20 0.26

Mesa Verde 2.80 2.65 2.61 2.69 2.80

Pecos 0.35 0.47 0.37 0.39 0.47

Petrified Forest 0.19 0.16 0.13 0.16 0.19

San Pedro 0.87 0.74 0.79 0.80 0.87

West Elk 0.58 0.53 0.25 0.45 0.58

Weminuche 0.85 1.21 0.79 0.95 1.21

Wheeler Peak 0.40 0.39 0.33 0.37 0.40
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-15

7.9 SUMMARY

During the telephone conference calls conducted on September 20, 2012 between EPA 

Region 6, NMED, PNM, and Black & Veatch and on November 19, 2012 between EPA Region 6, PNM, 

and Black & Veatch, the BART modeling methodology and approach were discussed and confirmed. 

Based on the approved approach, visibility modeling was conducted for the four BART scenarios. 

The NMED SIP and State Alternative scenarios visibility results were compared to the EPA FIP 

visibility results. The results of maximum visibility difference (in deciviews) projected at any of the 

16 Class I areas for the BART control technologies at any time over the 2001 to 2003 period are 

presented in Tables 7-14 and 7-15, respectively. The visibility results for the Baseline Scenario 

have been included for informational purposes as new SO2 and PM limits apply, but were not 

analyzed further.

Between the NMED SIP and State Alternative BART technology scenarios, the State 

Alternative (Table 7-15) resulted in the best visibility improvement evaluated beyond the EPA FIP. 

Specifically, the results indicate that visibility impacts at four Class I areas are equal to or better 

than visibility impacts projected for the EPA FIP scenario. Additionally, the visibility impacts for 

the remaining 12 Class I areas are less than a 0.5 dv difference from EPA’s FIP scenario for these 

same areas—the maximum difference is 0.47 dv. It should be noted that a change of 1 dv is 

generally regarded as the limit of perceptible change in visibility16

As previously noted, the projected visibility impacts for State Alternative scenario are all 

within a value of 0.5 dv of the FIP. Additionally, Tables 7-17 through 7-20 include a summary of 

CALPUFF’s predicted average and maximum days over a 0.5 dv and 1.0 dv threshold. These 

summary tables also illustrate the frequency of the occurrence of the level of visibility impact as 

compared to that for EPA’s FIP. These results indicate that approximately half or more of the 

number of Class I areas are equal to or better than the EPA FIP. This indicates a general 

improvement in visibility as compared to the EPA FIP and NMED SIP scenarios. Additionally, 

Figures 7-3 through 7-6 illustrate the number of days over comparison at each Class I area for each 

BART technology scenario. As illustrated in Figure 7-3 through 7-6, the State Alternative closely 

matches the EPA FIP scenario’s days comparison curves.

to the human eye. Additionally, 

Figure 7-2 illustrates the visibility impacts at each Class I area for each BART technology scenario. 

As illustrated in Figure 7-2, the State Alternative closely matches the EPA FIP scenario’s visibility 

curve for several Class I areas.

 16 70 FR 39118; July 6, 2005.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-16

Table 7-14 Maximum Delta Deciview FIP minus the SIP, 98th Percentile (dv)

CLASS I AREA EPA FIP NMED SIP

EPA FIP MINUS 

NMED SIP

Arches 1.13 2.67 -1.54

Bandilier 0.49 1.08 -0.59

Black Canyon 0.42 1.07 -0.65

Canyonlands 1.57 3.71 -2.14

Capitol Reef 0.83 1.82 -0.99

Grand Canyon 0.33 0.72 -0.39

Great Sand Dunes 0.50 1.15 -0.65

La Garita 0.58 1.47 -0.89

Maroon Bells 0.28 0.53 -0.25

Mesa Verde 2.33 4.67 -2.34

Pecos 0.48 1.00 -0.52

Petrified Forest 0.22 0.39 -0.17

San Pedro 0.75 1.72 -0.97

West Elk 0.46 1.21 -0.75

Weminuche 0.92 2.36 -1.44

Wheeler Peak 0.45 0.86 -0.41
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-17

Table 7-15 Delta Deciview EPA FIP minus the State Alternative, 98th Percentile (dv)

CLASS I AREA EPA FIP

STATE 

ALTERNATIVE

EPA FIP MINUS STATE 

ALTERATIVE

Arches 1.13 1.37 -0.24

Bandilier 0.49 0.52 -0.03

Black Canyon 0.42 0.52 -0.1

Canyonlands 1.57 1.99 -0.42

Capitol Reef 0.83 0.89 -0.06

Grand Canyon 0.33 0.33 0

Great Sand Dunes 0.50 0.57 -0.07

La Garita 0.58 0.71 -0.13

Maroon Bells 0.28 0.26 0.02

Mesa Verde 2.33 2.80 -0.47

Pecos 0.48 0.47 0.01

Petrified Forest 0.22 0.19 0.03

San Pedro 0.75 0.87 -0.12

West Elk 0.46 0.58 -0.12

Weminuche 0.92 1.21 -0.29

Wheeler Peak 0.45 0.40 0.05
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-18

Figure 7-2 Visibility Impact Results

0

1

2

3

4

5

6

Deciviews, dv

Visibility Impact Results

Baseline

FIP

SIP

State Alternative
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-19

Table 7-16 Average Days Compared To 0.5 dv

CLASS I AREA BASELINE FIP SIP

STATE 

ALTERNATIVE FIP - SIP

FIP - STATE 

ALTERNATIVE

Arches 26 13 24 14 -11 -1

Bandelier 33 6 24 7 -18 -1

Black Canyon 26 4 17 6 -13 -2

Canyonlands 42 23 39 22 -16 1

Capitol Reef 13 6 12 6 -6 0

Grand Canyon 6 2 4 2 -2 0

Great Sand Dunes 38 3 24 4 -21 -1

La Garita 54 7 38 9 -31 -2

Maroon Bells 9 0 5 0 -5 0

Mesa Verde 177 109 160 100 -51 9

Pecos 30 4 21 4 -17 0

Petrified Forest 6 1 4 0 -3 1

San Pedro 65 19 52 19 -33 0

West Elk 26 3 16 6 -13 -3

Weminuche 126 35 101 41 -66 -6

Wheeler Peak 32 4 20 3 -16 1

Note: Maximum Number of Days with Average Impacts Equal to or Greater than 0.5 Deciviews.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-20

Figure 7-3 Average Days Compared To 0.5 dv17

 17 Maximum Number of Days with Average Impacts Equal to or Greater than 0.5 Deciviews

0

20

40

60

80

100

120

140

160

180

200

Days

Average Days Compared to 0.5 dv

Baseline

FIP

SIP

State Alternative
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-21

Table 7-17 Maximum Days Compared To 0.5 dv

CLASS I AREA BASELINE FIP SIP

STATE 

ALTERNATIVE FIP - SIP

FIP - STATE 

ALTERNATIVE

Arches 43 26 43 27 -17 -1

Bandelier 44 6 29 8 -23 -2

Black Canyon 35 5 22 8 -17 -3

Canyonlands 71 42 65 39 -23 3

Capitol Reef 22 14 22 15 -8 -1

Grand Canyon 10 4 8 5 -4 -1

Great Sand Dunes 55 7 37 9 -30 -2

La Garita 84 10 62 14 -52 -4

Maroon Bells 13 1 9 1 -8 0

Mesa Verde 193 128 180 122 -52 6

Pecos 34 5 27 6 -22 -1

Petrified Forest 8 2 6 1 -4 1

San Pedro 79 22 67 22 -45 0

West Elk 32 6 20 8 -14 -2

Weminuche 162 52 138 68 -86 -16

Wheeler Peak 32 6 21 5 -15 1

Note: Maximum Number of Days with Maximum Impacts Equal to or Greater than 0.5 Deciviews.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-22

Figure 7-4 Maximum Days Compared To 0.5 dv18

 18 Maximum Number of Days with Maximum Impacts Equal to or Greater than 0.5 Deciviews

0

20

40

60

80

100

120

140

160

180

200

Days

Maximum Days Compared to 0.5 dv

Baseline

FIP

SIP

State Alternative
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-23

Table 7-18 Average Days Compared To 1.0 dv

CLASS I AREA BASELINE FIP SIP

STATE 

ALTERNATIVE FIP - SIP

FIP - STATE 

ALTERNATIVE

Arches 18 5 15 8 -10 -3

Bandelier 12 1 8 1 -7 0

Black Canyon 9 1 6 1 -5 0

Canyonlands 28 8 23 10 -15 -2

Capitol Reef 8 2 6 2 -4 0

Grand Canyon 3 0 2 0 -2 0

Great Sand Dunes 11 1 5 1 -4 0

La Garita 19 0 9 2 -9 -2

Maroon Bells 2 0 1 0 -1 0

Mesa Verde 118 45 103 50 -58 -5

Pecos 9 0 4 0 -4 0

Petrified Forest 1 0 0 0 0 0

San Pedro 33 5 20 5 -15 0

West Elk 8 0 6 1 -6 -1

Weminuche 67 4 42 5 -38 -1

Wheeler Peak 8 0 4 0 -4 0

Note: Maximum Number of Days with Average Impacts Equal to or Greater than 1.0 Deciviews
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-24

Figure 7-5 Average Days Compared To 1.0 dv19

 19 Maximum Number of Days with Average Impacts Equal to or Greater than 1.0 Deciviews

0

20

40

60

80

100

120

Days

Average Days Compared to 1.0 dv

Baseline

FIP

SIP

State Alternative
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-25

Table 7-19 Maximum Days Compared To 1.0 dv

CLASS I AREA BASELINE FIP SIP

STATE 

ALTERNATIVE FIP - SIP

FIP - STATE 

ALTERNATIVE

Arches 34 12 28 15 -16 -3

Bandelier 15 2 10 2 -8 0

Black Canyon 13 1 8 1 -7 0

Canyonlands 48 16 40 20 -24 -4

Capitol Reef 17 5 17 6 -12 -1

Grand Canyon 7 1 5 1 -4 0

Great Sand Dunes 18 2 10 2 -8 0

La Garita 33 1 14 3 -13 -2

Maroon Bells 5 0 2 0 -2 0

Mesa Verde 142 58 124 64 -66 -6

Pecos 13 0 7 0 -7 0

Petrified Forest 2 0 1 0 -1 0

San Pedro 42 6 25 6 -19 0

West Elk 11 1 9 3 -8 -2

Weminuche 102 7 68 9 -61 -2

Wheeler Peak 10 0 6 1 -6 -1

Note: Maximum Number of Days with Maximum Impacts Equal to or Greater than 1.0 Deciviews.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-26

Figure 7-6 Maximum Days Compared To 1.0 dv20

 20 Maximum Number of Days with Maximum Impacts Equal to or Greater than 1.0 Deciviews

0

20

40

60

80

100

120

140

160

Days

Maximum Days Compared to 1.0 dv

Baseline

FIP

SIP

State Alternative
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7-27

7.10 VISIBILITY COST EFFECTIVENESS

The visibility improvement cost-effectiveness was determined according to the TAC for the 

additional control technology alternatives shown in Table 6-3.. The maximum modeled visibility 

improvement for each BART control technology scenario at each of the 16 Federal Class I areas 

were used for the determination of the visibility improvement cost-effectiveness in $/deciview 

($/dv). The Baseline is compared with the three BART control technology scenarios, and are shown 

in the visibility improvement cost effectiveness summary in Table 7-20:

 Baseline to the EPA FIP.

 Baseline to the NMED SIP.

 Baseline to the State Alternative.

As shown in Table 7-20, the cost to install the State Alternative BART control technology on 

a $/dv basis is a fraction of the cost per dv improvement as compared to either the FIP or SIP BART 

control technologies.

Table 7-20 Visibility Improvement Cost-Effectiveness Summary

VISIBILITY SCENARIO

TOTAL 

ANNUALIZED COST 

(TAC) ($1,000)

SCENARIO MAXIMUM 

DECIVIEW CHANGE 

(DV)

MAXIMUM 

IMPROVEMENT 

($1,000/DV)

Baseline to FIP 108,820 3.09 35,217,000

Baseline to SIP 27,248 0.95 28,682,000

Baseline to State Alternative 13,624 2.67 5,103,000
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Conclusions 8-1

8.0 Conclusions

The SJGS analysis was performed to support the NMED BART SIP process. After completing 

all five steps of the BART analysis, feasible technologies for all four units at SJGS were selected and 

evaluated for visibility improvement at the affected Federal Class I areas. The visibility 

improvement modeling is summarized in Section 7.0 of this report.

The recommended BART control for SJGS is the State Alternative scenario consisting of 

installation of SNCR technology on Units 1 and 4 achieving a NOx emission rate of 0.23 lb/MMBtu21

The recommended BART control scenario was based on an evaluation of the most costeffective technology. This evaluation was performed as detailed in Sections 3.0 through 6.0 of this 

report. 

and a lower SO2 emission rate of 0.10 lb/MMBtu coupled with the retirement of Units 2 and 3. After 

completion of the SNCR performance testing, PNM will begin SNCR optimization testing on both 

units to determine if a NOx emission rate below 0.20 lb/MMBtu is achievable on the same 30-day 

rolling average basis. Units 1 and 4 will continue to operate their existing air pollution control 

equipment established to reduce other criteria pollutant emissions. Units 2 and 3 will be retired inplace on December 31, 2017.

The FIP (SCR) scenario would require significant capital expenditure and modifications that 

will impact many areas of the plant including boiler draft systems, air heater performance, SO3

emissions, and ash handling. The capital costs for SCR ranged from $181 million on Units 1 and 2 to 

$264 million on Unit 3. 

The SIP (SNCR) and State Alternative scenarios would require less capital expenditure than 

the aforementioned FIP scenario. For SIP scenario, the capital costs are approximately $17 million 

for each SJGS unit. For the State Alternative scenario the costs of the technology for Units 1 and 4 

are the same as for the SIP scenario. However, there is the additional benefit of Units 2 and 3 

retiring in 2017 and the associated environmental benefits as described in Section 6.1.3.

The visibility changes resulting from the three BART control technology options show (as 

described in Section 7.0) improvements at each of the 16 Class I areas as compared to the Baseline 

scenario. The most significant aspect of the visibility analysis is that the State Alternative BART

technology scenario resulted in the best visibility improvement evaluated beyond the EPA FIP at a 

fraction of the cost of the FIP control technology option. Specifically, the costs of the State 

Alternative BART control technology option--the recommended BART control technology option for 

SJGS--has a total capital investment of $827,223,000 less than the FIP BART control technology 

option. Additionally, as depicted in Section 7.9 the State Alternative closely matches the EPA FIP 

scenario’s visibility curve and days comparison curves for several Class I areas.

Additionally, based on the non-binding agreement between EPA, NMED, and PNM a 

schedule has been developed for the installation of SNCR technology on Units 1 and 4, and the 

retirement of Units 2 and 3. Table 8-1 highlights the timeline summarized in the Term Sheet for the 

regulatory approval and implementation project.

 21 Emission rate is based on a 30-day rolling average basis.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Conclusions 8-2

Table 8-1 Project Calendar

YEAR MONTH ACTION

2013

April • PNM Submits a BART Addendum

• NMED Begins SIP Modifications

May-June • NMED Requests the New Mexico Environmental Improvement Board 

(EIB) Hearing

September • NMED Presents the Revised SIP to EIB 

October • NMED Presents the Revised SIP to EPA

December • EPA Determination of Completeness of the SIP

2014

April • EPA proposes Action on the SIP

October • Final EPA Action on the SIP

November • EPA and NMED Discussion Regarding FIP compliance Dates

2016

January • Units 1 and 4 SNCR Installation (January 31, 2016)(1)

April • SNCR Performance Testing and Optimization Begins

May • Begin Collection of NOx Emissions Data

2017

February • End of Long-Term SNCR Performance Test

December • Units 2 and 3 Retirement by December 31, 2017

(1)SNCR in-service date of January 14, 2016 or 15 months from EPA approval-- whichever is later.
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Appendix A A-1

Appendix A. Term Sheet







PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Appendix B B-1

Appendix B. SJGS New Source Review Permit
f 

SUSANA MARTINEZ 

GOVERNOR 

JOHN A. SANCHEZ 

LIEUTENANT GOVERNOR 

New Mexico 

ENVIRONMENT DEPARTMENT 

Air Quality Bureau 

1301 Siler Road, Building B 

Santa Fe, NM 87507-3113 

Phone (505) 476-4300 

Fax (505) 476-4375 

www.nmenv.state.nm.us 

NEW SOURCE REVIEW PERMIT 

Issued under 20.2.72 NMAC 

Certified Mail No: 7005 18200001 5771 0255 

Return Receipt Requested 

NSR Permit No: 0063-M8 

Facility Name: San Juan Generating Station 

DAVE MARTIN 

CABINET SECRETARY 

BUTCH TONGATE 

DEPUTY SECRETARY 

Facility Owners: Unit 1: Public Service Company of New Mexico~ Tucson Electric Power 

Unit 2: Public Service Company of New Mexico; Tucson Electric Power 

Unit 3: Public Service Company of New Mexico; Southern California Public 

Power Authority; Tri-State Generation and Transmission Association, Inc. 

Unit 4: Public Service Company of New Mexico; Utah Associated Municipal 

Power Systems; City of Farmington, New Mexico; M-S-R Public Power 

Authority; City of Anaheim, California; Los Alamos County, New Mexico 

OperatorlPermittee Name: Public Service Company of New Mexico (PNM) 

Mailing Address: Alvarado Square, Albuquerque, NM 87158 

TEMPOIIDEA ID No: 

AIRS No: 

Permitting Action: 

Source Classification: 

Facility Location: 

County: 

Air Quality Bureau Contact: 

Main AQB Phone No. 

1421-P~20120001 

35-045-00902 

NSR Significant Permit Revision 

Major-TV and Major-PSD 

36°48'2" Nand -108°26' 19" W 

San Juan 

Joseph Kimbrell 

(505) 476-4300 

AUG 3 1 2012 

Date 

[ > nrllt H,rSlt r 8 
NSR Permit No. 0063M8 Page 2 of 54

TABLE OF CONTENTS

Part A FACILITY SPECIFIC REQUIREMENTS .................................................................... 3

A100 Introduction................................................................................................................. 3

A101 Permit Duration (expiration)....................................................................................... 3

A102 Facility: Description.................................................................................................... 3

A103 Facility: Applicable Regulations................................................................................. 5

A104 Facility: Regulated Sources ........................................................................................ 9

A105 Facility: Control Equipment ..................................................................................... 12

A106 Facility: Allowable Emissions.................................................................................. 12

A107 Facility: Allowable Startup, Shutdown, & Maintenance (SSM) .............................. 20

A108 Facility: Allowable Operations................................................................................. 20

A109 Facility: Reporting Schedules................................................................................... 21

A110 Facility: Fuel Sulfur Requirements – not required ................................................... 21

A111 Facility: 20.2.61 NMAC Opacity – not required ...................................................... 21

A112 Construction Options................................................................................................ 21

A113 Compliance Plan ....................................................................................................... 22

A114 Reducing Facility Emissions..................................................................................... 22

EQUIPMENT SPECIFIC REQUIREMENTS ............................................................................. 23

Oil and Gas Industry ..................................................................................................................... 23

A200 Oil and Gas Industry – not required.......................................................................... 23

Construction Industry.................................................................................................................... 23

A300 Construction Industry - not required......................................................................... 23

Power Generation Industry ........................................................................................................... 23

A400 Power Generation Industry ....................................................................................... 23

A401 Turbines - Not Required ........................................................................................... 24

A402 Boilers....................................................................................................................... 24

A403 Engines...................................................................................................................... 31

A404 Heaters - Not Required ............................................................................................. 31

A405 Cooling Towers......................................................................................................... 32

A406 Haul Roads/Storage piles (Coal-Fired Plants).......................................................... 32

A407 Storage Silos (activated carbon, fly ash)................................................................... 34

Part B GENERAL CONDITIONS .......................................................................................... 36

B100 Introduction............................................................................................................... 36

B101 Legal ......................................................................................................................... 36

B102 Authority................................................................................................................... 37

B103 Annual Fee ................................................................................................................ 37

B104 Appeal Procedures.................................................................................................... 38

B105 Submittal of Reports and Certifications.................................................................... 38

B106 NSPS and/or MACT Startup, Shutdown, and Malfunction Operations ................... 38

B107 Startup, Shutdown, and Maintenance Operations..................................................... 39

B108 General Monitoring Requirements ........................................................................... 39

B109 General Recordkeeping Requirements ..................................................................... 41

B110 General Reporting Requirements.............................................................................. 42
NSR Permit No. 0063M8 Page 3 of 54

B111 General Testing Requirements.................................................................................. 43

B112 Compliance ............................................................................................................... 46

B113 Permit Cancellation and Revocation......................................................................... 46

B114 Notification to Subsequent Owners.......................................................................... 47

B115 Asbestos Demolition................................................................................................. 47

B116 Short Term Engine Replacement.............................................................................. 47

Part C MISCELLANEOUS ..................................................................................................... 51

C100 Supporting On-Line Documents............................................................................... 51

C101 Definitions................................................................................................................. 51

C102 Acronyms.................................................................................................................. 53

A100

PART A FACILITY SPECIFIC REQUIREMENTS

A. This permit NSR 0063-M8 supersedes all portions of Air Quality Permit 0063-M7,

issued 12/14/2011, except the portion requiring compliance tests. Compliance test 

conditions from previous permits, if not completed, are still in effect, in addition to 

compliance test requirements contained in this permit.

Introduction

A101

A. The term of this permit is permanent unless withdrawn or cancelled by the 

Department.

Permit Duration (expiration)

A102

A. This facility consists of four coal-fired electric generating units and associated 

support facilities. Each coal-fired unit burns pulverized coal and No. 2 Diesel oil in a 

boiler and produces high-pressure steam which powers a steam turbine coupled with 

an electrical generator. Electrical power produced by the units is 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. For the purposes of this permit, the 

four generating units at San Juan Generating Station are designated Unit 1, Unit 2, 

Unit 3, and Unit 4.

Facility: Description

B. This facility is located approximately 3 miles north-northeast of Waterflow, New

Mexico in San Juan County. 

C. This modification has two distinct permitting scenarios that are mutually exclusive, 

i.e., if one scenario becomes final the other scenario becomes moot. Scenario A is the 

permitting scenario required to implement the SJGS Federal Implementation Plan 
NSR Permit No. 0063M8 Page 4 of 54

(FIP) published in 40 CFR 52.1628 (dated August 22, 2011, effective on September 

21, 2011). The provisions of this FIP are under judicial review, but the FIP 

implementation date makes it necessary to proceed with obtaining the authority-toconstruct air permit immediately to insure construction of the required equipment 

(SCR) can begin in time to meet the FIP operational deadline. Scenario B of this 

permit application is intended to implement the requirements of the State of New 

Mexico Regional Haze State Implementation Plan, (SIP) adopted pursuant to 40 CFR 

51.309, which specifies controls for SJGS that are different than the FIP. If the 

judicial review of the FIP results in vacatur of the FIP requirements, PNM would 

implement the SIP requirements which require installation and operation of an SNCR 

control system, rather than SCR. SNCR is represented in this permit application as 

Scenario B. While permitting scenarios A and B are distinct, some permit 

modifications are common to both scenarios. Add Units E520, E521, and E522 for 

Scenario A. Combine AUX1 and AUX2 into Unit E410 and delete Unit E411. Add 

Compliance Schedule for 5-year construction period approved by FIP. Preconstruction emission limits shall remain in effect until the new control equipment 

for each unit becomes operational. This description is for informational purposes 

only and is not enforceable.

Conditions related to this modification

Condition 

Number

Pollutant Limit Condition implementation date begins or 

requirement end date

Table 106.A NOx Current-0.30 lb/MMBtu Scenario A/B - Ends no later than 9/20/16

Table 106.A NOx Scenario A – 0.05 lb/MMBtu Begins no later than 9/20/16

Table 106.A NOx Scenario B – 0.23 lb/MMBtu Begins no later than 9/20/16

Table 106.A H2SO4 Scenario A – 0.00026 lb/MMBtu Begins no later than 9/20/16

Table 106.A Ammonia Slip

Ammonia Slip wet – Each

Scenario A – 2 ppm

Scenario B – 10 ppm

Scenario A/B - Begins no later than 9/20/16

Table 106.A Ammonia Slip

Ammonia Slip (pph) - Each 

Scenario A – units 1-2 (4.78

pph), units 3-4 (7.31 pph)

Scenario B – units 1-2 (23.91

pph); units 3-4 (36.03 pph)

Scenario A/B - Begins no later than 9/20/16

Table 106.A Ammonia Slip

Ammonia Slip - Combined 

Scenario A – 105.9 tpy

Scenario B – 525.0 tpy

Scenario A/B - Begins no later than 9/20/16

Table 106.C See Table 106.C See Table 106.C Scenario A/B - Ends no later than 9/20/16

Table 106.J See Table 106.J See Table 106.J Scenario A/B - Begins no later than 9/20/16
NSR Permit No. 0063M8 Page 5 of 54

D. Table 102.A and Table 102.B show the total potential emissions from this facility for 

information only, not an enforceable condition, excluding exempt sources or 

activities. 

Table 102.A: Total Potential Criteria Pollutant Emissions from Entire Facility 

Pollutant Emissions (tons per year)

Nitrogen Oxides (NOx) (Pre-construction) 24,703.0

Nitrogen Oxides (NOx) (Scenario A, SCR) 4118.0

Nitrogen Oxides (NOx) (Scenario B, SNCR) 18,941.0

Carbon Monoxide (CO) 39,420.0

Volatile Organic Compounds (VOC) 248.0

Sulfur Dioxide (SO2) 12,352.0

Total Suspended Particulates (TSP) Total 3381.0

Particulate Matter less than 10 microns (PM10) Filterable 1,550.0

Particulate Matter less than 2.5 microns (PM2.5) Total 2836.0

Table 102.B: Total Potential HAPS that exceed 1.0 ton per year 

Pollutant Emissions (tons per year)

Ammonia (Scenario A, SCR) (NM-TAP) 105.9

Ammonia (Scenario B, SNCR) (NM-TAP) 525.0

Hydrochloric acid (HCl) 21.3

Hydrofluoric Acid; (Hydrogen fluoride) 44.7

Sulfuric Acid (H2SO4) (Scenario A, SCR Only) (HAP&TAP) 21.6

Total HAPs (Scenario A, SCR Only) 88.2

Total HAPs(Scenario B, SNCR) 66.8

Total HAPs**(Pre-construction) 74.6

* HAP emissions are already included in the VOC emission total.

** The total HAP emissions may not agree with the sum of individual HAPs because only individual HAPs greater 

than 1.0 tons per year are listed here.

A103

A. The permittee shall comply with all applicable sections of the requirements listed in 

Table 103.A. 

Facility: Applicable Regulations

Table 103.A: Applicable Requirements

Applicable Requirements Federally

Enforceable

Unit

No.

20.2.1 NMAC General Provisions X Entire Facility
NSR Permit No. 0063M8 Page 6 of 54

Applicable Requirements Federally

Enforceable

Unit

No.

20.2.3 NMAC Ambient Air Quality Standards X Entire Facility

20.2.7 NMAC Excess Emissions X Entire Facility

20.2.14 NMAC Coal Burning Equipment –

Particulate Emissions X E301, E302, E303, E304

20.2.31 NMAC Coal Burning Equipment – Sulfur 

Dioxide X E301, E302, E303, E304

20.2.32 NMAC Coal Burning Equipment – Nitrogen 

Dioxide X E301, E302, E303, E304

20.2.61 NMAC Smoke and Visible Emissions X E602, E603, E604, E605, 

E606

20.2.70 NMAC Operating Permits X Entire Facility

20.2.71 NMAC Operating Permit Emission Fees X Entire Facility

20.2.72 NMAC Construction Permit X Entire Facility

20.2.73 NMAC Notice of Intent and Emissions 

Inventory Requirements X Entire Facility

20.2.74 NMAC Permits – Prevention of Significant 

Deterioration (PSD) X Entire Facility

20.2.77 NMAC New Source Performance X E301, E302, E303, E304, 

E803, E804, E805

20.2.300 NMAC, Reporting of Greenhouse Gas 

Emissions – Effective Jan 1, 2011 X E301, E302, E303, E304

40 CFR 50 National Ambient Air Quality Standards X Entire Facility

40 CFR 60, Subpart A, General Provisions X E301, E303, E304, E803, 

E804, E805

40 CFR 60 Subpart D – Standards of Performance 

for Fossil-Fuel-Fired Steam Generators X E301, E303, E304

40 CFR 60 Subpart OOO – Standards of 

Performance for Nonmetallic Mineral Processing 

Plants

X E803, E804, S805

40 CFR 64 Compliance Assurance Monitoring X E301, E302, E303, E304

40 CFR 68 Chemical Accident Prevention X Entire Facility

40 CFR 72 Subparts B, D, and I – Acid Rain Permit 

Regulations X E301, E302, E303, E304

40 CFR 73 Subparts B, C, and D – Sulfur Dioxide 

Allowance System X E301, E302, E303, E304

40 CFR 75 Subparts A-G - Continuous Emission 

Monitoring X E301, E302, E303, E304

40 CFR 76 Acid Rain Nitrogen Oxides Emission 

Reduction Program X E301, E302, E303, E304

40 CFR 77 Excess Emissions X E301, E302, E303, E304

40 CFR 82 Subpart B – Protection of Stratospheric 

Ozone, Servicing of Motor Vehicles X Entire Facility
NSR Permit No. 0063M8 Page 7 of 54

Applicable Requirements Federally

Enforceable

Unit

No.

March 10, 2005 Consent Decree filed in the United 

States District Court, District of New Mexico X E301, E302, E303, E304

Demister Settlement Agreement X E301, E302, E303, E304

SJGS Federal Implementation Plan (FIP) 

published in 40 CFR 52.1628 (August 22, 2011) X E301, E302, E303, E304

Regional Haze State Implementation Plan (SIP) 

under 40 CFR 51.309 (June 15, 2012) X E301, E302, E303, E304

B. Table 103.B lists requirements that are not

Table 103.B: Non-Applicable Requirements 

applicable to this facility. This table only 

includes those requirements cited in the application as applicable and determined by 

the Department to be not applicable, or the Department determined that the 

requirement does not impose any conditions on a regulated piece of equipment.

Non-Applicable Requirements (1) (2) Justification For 

Non-Applicability

40 CFR 60 Subpart K – Standards of 

Performance for Storage Vessels for Petroleum 

Liquids

X

See note (2) below

40 CFR 60 Subpart Ka –Standards of 

Performance for Storage Vessels for Petroleum 

Liquids

X

See note (2) below

(1) Not Applicable For This Facility: No existing or planned operation/activity at this facility triggers the 

applicability of these requirements.

(2) No Requirements: Although these regulations may apply, they do not impose any specific requirements on the 

operation of the facility as described in this permit.

C. Applicable requirements that give rise to emissions limits in this permit.

Table 103.C: Applicable Requirements Giving Rise to Permit Emission Limits

(for information only, not an enforceable condition)

Emission Unit Nos. Applicable 

Requirement Description of Requirement

E301, E303, E304 40 CFR 60.42(a)(1) PM Emission Limit

E301, E303, E304 40 CFR 60.42(a)(2) Opacity Emission Limit

E301, E303, E304 40 CFR 60.43(a)(2) SO2 Emission Limit

E301, E303, E304 40 CFR 60.44(a)(3) NOx Emission Limit

E301, E303, E304 20.2.14.201.A NMAC PM Emission Limit
NSR Permit No. 0063M8 Page 8 of 54

Emission Unit Nos. Applicable 

Requirement Description of Requirement

E301, E303, E304 20.2.14.201.B NMAC PM-2 Emission Limit

E301, E303, E304 20.2.31.109.B NMAC SO2 Emission Limit

E301, E303, E304 20.2.32.109 NMAC NOx Emission Limit

E302 20.2.14.202.A NMAC PM Emission Limit

E302 20.2.14.202.B NMAC PM-2 Emission Limit

E302 20.2.31.110.A NMAC SO2 Control Efficiency Limit

E302 20.2.32.110.C NMAC NOx Emission Limit

E301, E302, E303, E304 20.2.31.109.C NMAC SO2 Emission Limits 

(Plant-Wide)

E301, E302, E303, E304 NSR No. 63-M6 Emission Limits for NOx, SO2, 

PM-10, TSP, CO, and VOC 

E803 40 CFR 60.672(a) PM and Opacity Emission Limits

E804, E805 40 CFR 60.672(b) Opacity Emission Limit

E602, E603, E604, E605, E606 20.2.61.109 NMAC Opacity Emission Limit

E101, E102, E103, E104, E201, 

E406, E407, E408, E409, E410, 

E411, E505, E506, E507, E508, 

E509, E510, E701, E702, E703, 

E704, E705, E706, E707, E801, 

E802 

NSR No. 63-M6 Emission Limits for NOx, SO2, 

PM-10, TSP, CO, or VOC

E301, E302, E303, E304 PNM self imposed SO2 Emission Limits

E301, E302, E303, E304 FIP (Scenario A) NOx, Ammonia, H2SO4 and HAP 

Limits

E301, E302, E303, E304 SIP (Scenario B) NOx and Ammonia Limits

D. Units E301, E303, and E304 are subject to federal new source performance standards 

(NSPS) found in CFR Title 40, Part 60, Subpart A - General Provisions, and Subpart 
NSR Permit No. 0063M8 Page 9 of 54

D and shall comply with both the notification requirements in Subpart A and with the 

specific requirements of Subpart D.

E. New Source Performance Standards (NSPS) found in 40 CFR 60, Subpart A -

General Provisions, and Subpart OOO applies to certain pieces of equipment in the 

limestone handling system. Affected units shall comply with both the notification 

requirements in Subpart A and with the specific requirements of Subpart OOO.

F. Units E301, E302, E303, and E304 are subject to the applicable requirements of 

20.2.14, 20.2.31, 20.2.32 NMAC. Table 103.F identifies whether the boiler unit is a 

new or existing unit including its vintage designation.

Table 103.F: Boiler Designation (NMAC) Information

Unit 

Number

Vintage 20.2.14, 20.2.31, and 20.2.32 NMAC

20.2.31.7(H) 20.2.32.7(O)

E301 1 -- New Coal Burning Equipment

E302 -- D Existing Coal Burning Equipment

E303 2 -- New Coal Burning Equipment

E304 3 -- New Coal Burning Equipment

A104

A. Table 104 lists the emission units authorized for this facility. Emission units 

identified as exempt activities and/or equipment (as defined in 20.2.72.202 NMAC)

not regulated pursuant to the Act are not included.

Facility: Regulated Sources

Table 104: Regulated Sources List

Unit No. 1 Description Manufacture Manufacture 

Date

Model 

No.

Serial 

No. Capacity Control Equipment

S301/E301

Unit 1 Coal 

Boiler

Begin 

Commercial 

Operation 

12/1976

Foster 

Wheeler -- 08-1266 --

3707

MM Btu/hr 4

Fabric Filter

SO2 Scrubber

Scenario A: SCR

Scenario B: SNCR

S302/E302

Unit 2 Coal 

Boiler

Begin 

Commercial 

Operation 

11/1973

Foster 

Wheeler -- 08-1266 --

3688

MM Btu/hr 4

Fabric Filter

SO2 Scrubber

Scenario A: SCR

Scenario B: SNCR
NSR Permit No. 0063M8 Page 10 of 54

Unit No. 1 Description Manufacture Manufacture 

Date

Model 

No.

Serial 

No. Capacity Control Equipment

S303/E303

Unit 3 Coal 

Boiler

Begin 

Commercial 

Operation 

12/1979

Babcock & 

Wilcox -- RB-544 --

5758

MM Btu/hr 4

Fabric Filter

SO2 Scrubber

Scenario A: SCR

Scenario B: SNCR

S304/E304

Unit 4 Coal 

Boiler

Begin 

Commercial 

Operation 

4/1982

Babcock & 

Wilcox -- RB-545 --

5649

MM Btu/hr 4

Fabric Filter

SO2 Scrubber

Scenario A: SCR

Scenario B: SNCR

S508/E501 Unit 1 Duct 

Leaks -- -- -- -- -- Good air pollution control practices

S509/E502 Unit 2 Duct 

Leaks

S510/E503 Unit 3 Duct 

Leaks -- -- -- -- --

S511/E504 Unit 4 Duct 

Leaks -- -- -- -- --

S111/E101 Coal Pile A 

Maintenance -- -- -- -- -- TBD

S112/E102 Coal Pile A 

Maintenance -- -- -- -- -- TBD

S113/E103 Coal Pile A 

Maintenance -- -- -- -- -- TBD

S114/E104 Coal Pile A 

Maintenance -- -- -- -- -- TBD

S201/E202

Coal Silo 

Transfer 

Point

-- -- -- -- -- Enclosure

S203/E203

Coal Belt to 

Pulverizers 

transfer 

Point

-- -- -- -- -- Enclosure

S204/E201 Coal 

Pulverizers Multiple Multiple Multiple Multiple 8,200,000 tpy 3 Building Enclosure

S425/E406

Unit 1 

Cooling 

Tower

Marley Note 2 D52 6615-5-

11

170,000 

gpm

Drift 

Eliminators/Design

S426E407

Unit 2 

Cooling 

Tower

Marley Note 2 D52 6615-5-

11

165, 000 

gpm

S427/E408

Unit 3 

Cooling 

Tower

Marley Note 2 Model 2 644-12-

333-75

220, 000 

gpm

S428/E409

Unit 4 

Cooling 

Tower

Marley Note 2 Model 2

6616-

12-113-

80

227,500 

gpm
NSR Permit No. 0063M8 Page 11 of 54

Unit No. 1 Description Manufacture Manufacture 

Date

Model 

No.

Serial 

No. Capacity Control Equipment

S429/E410

Aux #1/#2

Cooling 

Tower

Marley 1978 600 

series NA 35,000 gpm

S518/E518

Unit 1 Fly 

Ash Silo 

Vent

W.W. Sly Oct 2008 JM3586 NA 291846 tpy Fabric Filter 

Baghouse

S519/E519

Unit 2 Fly 

Ash Silo 

Vent

W.W. Sly Mar 2009 JM3586 NA 290430 tpy Fabric Filter 

Baghouse

S512/E505

Unit 3 Fly 

Ash Silo 

Vent

W.W. Sly Dec 1979 JM3586 NA 25,400 scfm Fabric Filter 

Baghouse

S513/E506

Unit 4 Fly 

Ash Silo 

Vent

W.W. Sly Apr 1982 JM3586 NA 25,400 scfm Fabric Filter 

Baghouse

S514/E507

Unit 1 Fly 

Ash Silo 

Unloading

-- -- -- -- 291846 tpy Moisture Control 

(Bulk Unloading)

S515/E508

Unit 2 Fly 

Ash Silo 

Unloading

-- -- -- -- 290430 tpy

S516/E509

Unit 3 Fly 

Ash Silo 

Unloading

-- -- -- -- 453424 tpy

S517/E510

Unit 4 Fly 

Ash Silo 

Unloading

-- -- -- -- 453424 tpy

S738/E704

Front End 

Loader 

(Around 

Coal Piles)

-- -- -- -- -- Watering

S753/E707

Front End 

Loader 

(Around 

Gypsum 

Piles)

-- -- -- -- -- Watering

E702, 

E703, 

E704-B, 

and E706

Un-Paved 

Haul Roads -- -- -- -- -- Watering

E701, 

E705, and 

E708

Paved Road 

Emissions -- -- -- -- -- Water Truck Street 

Sweeper

S804/E802

Lime Stone 

Pile 

Maintenance

-- -- -- -- -- TBD

E801

Limestone 

Truck 

Unloading

__ __ __ __ __ None
NSR Permit No. 0063M8 Page 12 of 54

Unit No. 1 Description Manufacture Manufacture 

Date

Model 

No.

Serial 

No. Capacity Control Equipment

S806/E803 Limestone 

Silo loading __ __ __ __ __ Baghouse

E804

Limestone 

Hopper to 

Transfer 

Conveyor

__ __ __ __ __ None

E805

Limestone 

Silo to 

Weigh

__ __ __ __ __ None

S901/E901 Activated 

Carbon Silo -- Nov 2008 -- -- 578 scfm Dedicated Baghouse (E901)

S902/E902 Activated 

Carbon Silo -- Mar 2009 -- -- 578 scfm Dedicated Baghouse (E902)

S903/E903 Activated 

Carbon Silo -- Mar 2008 -- -- 578 scfm Dedicated Baghouse (E903)

S904/E904 Activated 

Carbon Silo -- Nov 2007 -- -- 578 scfm Dedicated Baghouse (E904)

E520

Unit 1/2 

Sorbent Silo 

(Scenario A)

TBD TBD

TBD Silo Vent Filer

E521

Unit 3 

Sorbent Silo 

(Scenario A)

TBD TBD

TBD Silo Vent Filer

E522

Unit 4 

Sorbent Silo 

(Scenario A)

TBD TBD

TBD Silo Vent Filer

1 Unit number designations starting with an “S” indicate Source and “E” Designations indicate emissions points

2 The manufacture date for the boilers (Units E301 – E304), the boiler specific cooling towers (Units 406 – 409), 

and the coal pulverizer (Unit E201) is assumed to be the “begin commercial operations” date for the respective 

boilers.

3 The coal pulverizers have a capacity of 1,600,000 tons per year of coal for each emissions unit E301 and E302. 

The coal pulverizers have a capacity of 2,500,000 tons per year of coal for each emissions unit E303 and E304. 

These capacity values are rounded to the nearest 100,000 tons per year. These values are based on historical 

coal use, scaled up to 100 percent unit utilization (i.e 100 percent load at 8760 hours per year).”

4 The Btu/hr value listed in Table 104 Includes a 6% safety factor added to nominal rated capacity of the boilers 

existing at the time of permit issuance.

A105

A. Table 104 lists all the pollution control equipment required for this facility. Each 

emission point is identified by the same number that was assigned to it in the permit 

application. 

Facility: Control Equipment

A106

A. The following table(s) list the emission units and their allowable emission limits. (40 

CFR 50, 40 CFR 60, Subparts A and D, and OOO; 40CFR72 Subparts B, D, and I;

Facility: Allowable Emissions
NSR Permit No. 0063M8 Page 13 of 54

40CFR73 Subparts B, C, and D; 40CFR75 Subparts A-G; 40CFR76; 20.2.72.210.A 

and B.1 NMAC).

Table 106.A: Maximum Allowable Emission Rates for Units E301 (1), E302 (2), E303 (3), 

and E304 (4)

Unit 

No.(s) Pollutant Maximum Allowable Emission Rate Averaging Period Applicable Requirement

Compliance 

Method

E301 

E302 

E303 

E304

CO

E301 – 3000 lb/hr

E302 – 2000 lb/hr

E303 – 2000 lb/hr

E304 – 2000 lb/hr

Per Compliance Method

20.2.3 NMAC, 40 

CFR 50,

NSR No. 63-M2

Quarterly Testing

E301 

E302 

E303 

E304

NOx

E301 – 1,573.7 lb/hr

E302 – 2,435.3 lb/hr

E303 – 2,444.4 lb/hr

E304 – 2,398.1 lb/hr

24-Hour Average NSR No. 63-M2

20.2.32 NMAC, CEMS

E301 

E302 

E303 

E304

NOx

E301 – 4871 tons/yr

E302 – 4844 tons/yr

E303 – 7564 tons/yr

E304 – 7424 tons/yr

Daily rolling 365-day Total NSR No. 63-M2

20.2.32 NMAC, CEMS

E301 

E303 

E304

NOx 0.70 lb/MMBtu 3-Hour Average, Rolled 

Hourly 40 CFR 60.44(a)(3) CEMS

E302 NOx 0.70 lb/MMBtu 3-Hour Average, Rolled 

Hourly 20.2.32.110.C NMAC CEMS

E301 

E303 

E304

NOx 0.45 lb/MMBtu 3-Hour Average, Rolled 

Hourly 20.2.32.109 NMAC CEMS

E301 

E302 

E303 

E304

NOx 1, 5

Current-0.30 lb/MMBtu

Scenario A – 0.05 lb/MMBtu

Scenario B – 0.23 lb/MMBtu

30 day rolling average5

30-boiler operating day 

rolling average10

30 day rolling average10

0063-M4

FIP & 0063-M8

CEMS & Process 

Records

E301 

E302 

E303 

E304

Opacity8 20% 6-Minute Average

40 CFR 60.42(a)(2); 

for E302-NSR 63M4 

and Consent Decree

COMS

E301 

E302 

E303 

E304

TSP4

(Filterable)

E301 – 174.8 lb/hr

E302 – 173.9 lb/hr

E303 – 271.6 lb/hr

E304 – 266.5 lb/hr

Per Compliance Method NSR No. 63-M2 Quarterly Testing

E301 

E302 

E303 

E304

TSP4

(Filterable)

E301 – 765.8 tons/yr

E302 – 761.9 tons/yr

E303 – 1,189.6 tons/yr

E304 – 1,167.1 tons/yr

Per Compliance Method NSR No. 63-M2 Quarterly Testing

E301 

E302 

E303 

E304

PM4,7

(Filterable)

0.015 lb/MMBtu Per Compliance Method 0063-M4 and Consent 

Decree Quarterly Testing

E301 

E303 

E304

PM4

(Filterable)

0.1 lb/MMBtu Per Compliance Method 40 CFR 60.42(a)(1) Quarterly Testing
NSR Permit No. 0063M8 Page 14 of 54

Unit 

No.(s) Pollutant Maximum Allowable Emission Rate Averaging Period Applicable Requirement

Compliance 

Method

E301 

E303 

E304

PM4

(Filterable)

0.05 lb/MMBtu Per Compliance Method 20.2.14.201.A NMAC Quarterly Testing

E302 PM4

(Filterable)

0.05 lb/MMBtu Per Compliance Method 20.2.14.202.A NMAC Quarterly Testing

E301 

E302 

E303 

E304

PM-104

(Filterable)

E301 – 174.8 lb/hr

E302 – 173.9 lb/hr

E303 – 271.6 lb/hr

E304 – 266.5 lb/hr

Per Compliance Method NSR No. 63-M2 Quarterly Testing

E301 

E302 

E303 

E304

PM-104

(Filterable)

E301 – 765.8 tons/yr

E302 – 761.9 tons/yr

E303 – 1,189.6 tons/yr

E304 – 1,167.1 tons/yr

Per Compliance Method NSR No. 63-M2 Quarterly Testing

E301 

E302 

E303 

E304

PM-2.54

(Filterable)

E301 – 55.6 lb/hr

E302 – 55.3 lb/hr

E303 – 86.4 lb/hr

E304 – 84.7 lb/hr

Per Compliance Method 0063-M6 Quarterly Testing

E301 

E302 

E303 

E304

PM-2.54

(Filterable)

E301 – 243.5 tons/yr

E302 – 242.2tons/yr

E303 – 378.4 tons/yr

E304 – 371.0 tons/yr

Per Compliance Method 0063-M6 Quarterly Testing

E301 

E302 

E303 

E304

PM-2.54

(Total)

0.034 lb/MMBtu Per Compliance Method NSR No. 63-M7 Annual Testing

E301 

E302 

E303 

E304

PM-2.54

(Total)

E301 – 126.0 lb/hr

E302 – 125.4 lb/hr

E303 – 195.8 lb/hr

E304 – 192.1 lb/hr

Per Compliance Method NSR No. 63-M7 Annual Testing

E301 

E302 

E303 

E304

PM-2.54

(Total)

E301 – 552.0 tons/yr

E302 – 549.0 tons/yr

E303 – 858.0 tons/yr

E304 – 841.0 tons/yr

Per Compliance Method NSR No. 63-M7 Annual Testing

E301 

E303 

E304

PM-24

(Filterable)

0.02 lb/MMBtu Per Compliance Method 20.2.14.201.B NMAC Note 2

E302 PM-24

(Filterable)

0.04 lb/MMBtu Per Compliance Method 20.2.14.202.B NMAC Note 2

E301 

E302 

E303 

E304

SO2 90% removal Annual Average 0063-M4 CEMS

E301 

E302 

E303 

E304

SO2

6 0.250 lb/MMBtu 7-day block average 0063-M4

CEMS & 

Process 

Records
NSR Permit No. 0063M8 Page 15 of 54

Unit 

No.(s) Pollutant Maximum Allowable Emission Rate Averaging Period Applicable Requirement

Compliance 

Method

E301 

E302 

E303 

E304

SO2

E301 – 2435.0 tpy

E302 – 2423.0 tpy

E303 – 3783.0 tpy

E304 – 3711.0 tpy

Per Compliance Method 20.2.3 NMAC,

40 CFR 50 CEMS

E301 

E302 

E303 

E304

SO2 0.15 lb/MMBtu9 30-Day Average,

Rolled Daily

PNM self imposed 

limit, NSR 63M6R2

and FIP

CEMS & Process 

Records

E301 

E303 

E304

SO2 1.2 lb/MMBtu 3-Hour Average,

Rolled Hourly 40 CFR 60.43(a)(2) CEMS

E301 

E303 

E304

SO2 1.2 lb/MMBtu 3-Hour Average, Rolled 

Hourly 20.2.31.109.B NMAC CEMS

E302 SO2

Minimum

72% Control

30-Day Average, Rolled 

Daily 20.2.31.110.A NMAC CEMS

E301 

E302 

E303 

E304

VOC

E301 – 11.1 lb/hr

E302 – 11.1 lb/hr

E303 – 17.3 lb/hr

E304 – 17.0 lb/hr

Per Compliance Method NSR No. 63-M2 Note 3

E301 

E302 

E303 

E304

H2SO4 0.00026 lb/mmBtu hourly basis FIP - 40 C.F.R. § 

52.1628

Annual

Method 8A

E301 

E302 

E303 

E304

Ammonia 

Slip 2 ppm design basis FIP - 40 C.F.R. § 

52.1628 SCR design

E301 

E302 

E303 

E304

Ammonia 

Slip 10 ppm design basis SIP - 40 C.F.R. § 

51.309(g) SNCR design

1 Nitrogen dioxide emissions include all oxides of nitrogen expressed as NO2

2 PNM shall show compliance with either the PM or PM2 limits as required in 20.2.14 NMAC.

3 Test results that demonstrate compliance with CO emission limits shall also be considered to demonstrate 

compliance with VOC emission limits for the subject emission unit.

4 The TSP emission limits in this permit only include filterable particulate emissions since the test method only 

measures filterable TSP. PM10 and PM2.5 filterable limits will remain. PM2.5 Total limits include both 

filterable and condensibles. 

5 For purposes of calculating the thirty (30) day rolling average, NOx emissions for the first three (3) hours of a 

cold startup after coal is fed to the boiler shall be capped at 0.30 lb/MMBtu. Cold startup is defined as a startup 

when the boiler is at ambient indoor temperature measured at the time fuel is first fed to the boiler.

6 The seven (7) day average emission rate of SO2 at San Juan Units E301, E302, E303, and E304 shall not exceed 

0.250 lb-SO2/MMBtu for each unit, calculated as a block average as measured by SO2 CEMS located 

downstream of the scrubber outlet and any scrubber by-pass return. For purposes of calculating the block 

average, SO2 emissions for the first three (3) hours of a cold startup after coal is fed to the boiler shall be capped 

at 0.250 lb./MMBtu. Cold startup is defined as a startup when the boiler is at ambient indoor temperature 

measured at the time fuel is first fed to the boiler.

7 The PM average emission rate for each of Units E301, E302, E303, and E304 shall not exceed 0.015 lbPM/MMBtu, as measured by EPA Reference Method 5 or 5i stack tests, conducted at least once each calendar 
NSR Permit No. 0063M8 Page 16 of 54

quarter at times and conditions specified by the Department, and according to test protocols approved by the 

Department, but in all cases under conditions and in a manner no less stringent than described in EPA’s 2009

Clean Air Act National Stack Testing Guidance.

8 The opacity limit for San Juan Units E301, E303, and E304 as required by 40 CFR 60.D and E301, E302, E303, 

and E304 as required by this permit shall be twenty (20) percent, averaged over any six (6) minute period 

except for one six (6) minute average per hour of up to twenty-seven (27) percent opacity. This limit shall apply 

at all times when air pollutants are being discharged into the atmosphere, unless PNM demonstrates that any 

excess opacity reading: (a) was caused by a startup, shutdown, malfunction, or emergency, or (b) occurred when 

both the boiler and all fans that move flue gas in the unit were off. Load changes, poor coal quality, air heater 

cleaning, sootblowing, and high ash hoppers shall not be used as a defense for any excess opacity reading. 

Opacity shall be measured in the duct or, if approved by EPA, after the outlet of the baghouse and corrected to 

stack exit. (CD 9a)

9 Prior to September 20, 2016: Compliance with the 0.15 lb/MMBtu heat input daily rolling, 30-day average SO2

emission limitation is determined by calculating at the end of each rolling 30 successive boiler operating days 

the arithmetic average of all hourly emission rates for SO2, except for data obtained during emergency 

conditions. Hourly emission rates will only be determined based on valid SO2 CEMs data for any hour where 

fuel is combusted in the unit. No missing hour substitute data will be used in determining compliance with the 

proposed 0.15 lb/MMBtu heat input 30-day rolling average SO2 emission limit. “Boiler operating day” means a 

24-hour period between 12 midnight and the following midnight (MST) during which any fuel is combusted at 

any time in the steam-generating unit. Effective on September 20, 2016 if SCR is installed: The SO2 emission 

rate limit for each unit in the plant shall be 0.15 pounds per million British thermal units (lbs/MMBtu), as 

averaged over a rolling 30 boiler operating- day period. For each unit on each boiler-operating-day, the hourly 

SO2 emissions measured in lbs/MMBtu, shall be averaged over the hours the unit was in operation to obtain a 

daily boiler-operating-day average. Each day, the 30-day-rolling average SO2 emission rate for each unit (in 

lbs/MMBtu) shall be determined by averaging the daily boiler-operating-day average emission rate from that 

day and those from the preceding 29 days. This method of calculating SO2 emissions becomes effective on 

September 20, 2016 if SCR is installed.

10 Per FIP at 40CFR52.1628 d(2), The NOx limit for each unit in the plant, expressed as nitrogen dioxide (NO2), 

shall be 0.05 pounds per million British thermal units (lb/MMBtu) as averaged over a rolling 30 calendar day 

period. For each unit, NOx emissions for each calendar day shall be determined by summing the hourly 

emissions measured in pounds of NOx. For each unit, heat input for each calendar day shall be determined by 

adding together all hourly heat inputs, in millions of BTU. Each day the thirty-day rolling average for a unit 

shall be determined by adding together the pounds of NOx from that day and the preceding 29 days and 

dividing the total pounds of NOx by the sum of the heat input during the same 30-day period. The result shall be 

the 30 day–rolling average in terms of lb/MMBtu emissions of NOx. If a valid NOx pounds per hour or heat 

input is not available for any hour for a unit, that heat input and NOx pounds per hour shall not be used in the 

calculation of the 30-day rolling average for NOx. This method of calculating NOx emissions becomes effective 

on September 20, 2016 if SCR is installed. Unless SCRs are installed and before the September 20, 2016 

effective date, footnotes 5 and 9 remain in effect.

B. Table 106.B contains the maximum allowable emission rates for Units E301, E302, 

E303, and E304 combined. 

Table 106.B, Maximum Allowable Emission Rates for Units E301-E304 Combined 

Pollutant

Maximum 

Allowable 

Emission Rate

Averaging 

Period

Applicable 

Requirement

Compliance 

Method

NOx 1 9,000 lb/hr 24-Hour Average, 

Rolled Hourly

NSR No. 63-M2,

40 CFR Part 50

CEMS
NSR Permit No. 0063M8 Page 17 of 54

Pollutant

Maximum 

Allowable 

Emission Rate

Averaging 

Period

Applicable 

Requirement

Compliance 

Method

SO2 13,000 lb/hr 3-Hour Average, 

Rolled Hourly 20.2.31.109.C NMAC

CEMS

SO2 0.55 lb/MMBtu 30-Day Average,

Rolled Daily 20.2.31.109.C NMAC

CEMS & Process 

Records

SO2 0.46 lb/MMBtu Annual Average NSR No. 63-M2

CEMS & Process 

Records

1 Nitrogen dioxide emissions include all oxides of nitrogen expressed as NO2

C. Table 106.C list the allowable emissions from duct leaks. Compliance shall be 

determined by implementation of a duct leak management program.

Table 106.C, Maximum Allowable Emission Rates for Duct Leaks 

Emission

Unit No.

Maximum Allowable Emission Rates

TSP PM-10 PM-2.5 NOx CO SO2

pph tpy pph tpy pph tpy pph tpy pph tpy pph tpy

E501 11.3 45.0 4.5 18.1 2.1 9.2 0.3 0.8 0.5 2.0 1.1 4.5

E502 12.4 50.0 4.9 20.0 2.1 9.2 0.4 0.8 0.4 1.5 1.2 4.9

E503 12.6 50.4 5.0 20.1 2.0 8.9 -- 0.8 0.2 1.0 1.3 5.0

E504 14.5 58.3 5.8 23.3 2.0 8.9 0.3 1.0 0.3 1.1 1.5 5.8

1 Emission rates for Duct Leaks under Scenarios A or B ends not later September 20, 2016.

D. Table 106.D lists the allowable emission limits for non-boiler emission units. The 

emissions from any individual piece of equipment shall not exceed the limits listed in 

the table. (NSR 63M6R1, Condition 2.e)

Table 106.D, Maximum Allowable Emission Rates for Non-Boiler Emission Units

Emission

Unit No.

Maximum Allowable Emission Rates

in Pounds per Hour (pph) and Tons per Year (tpy)

TSP PM-10

pph tpy pph tpy

E101 1.6 7.0 -- 1.6

E102 1.6 7.0 -- 1.6

E103 1.6 7.0 -- 1.6

E104 1.6 7.0 -- 1.6

E201 7.3 32.0 2.8 12.0

E202 -- 3.1 -- 1.5

E203 -- 3.1 -- 1.5
NSR Permit No. 0063M8 Page 18 of 54

Emission

Unit No.

Maximum Allowable Emission Rates

in Pounds per Hour (pph) and Tons per Year (tpy)

TSP PM-10

pph tpy pph tpy

E406 10.2 44.7 2.4 10.5

E407 9.9 43.4 2.3 10.2

E408 6.4 28.2 2.5 10.9

E409 13.7 59.8 3.2 14.1

E410 1.4 6.0 -- 2.3

E505 2.2 9.5 2.2 9.5

E506 2.2 9.5 2.2 9.5

E507 0.6 2.4 -- 1.1

E508 0.6 2.4 -- 1.1

E509 0.9 3.7 -- 1.8

E510 0.8 3.7 -- 1.7

E518 1.6 7.0 1.6 7.0

E519 1.6 7.0 1.6 7.0

Paved Roads 

(E701, E705, E708) 16.4 68.8 3.3 13.8

Unpaved Roads 

(E702, E703, 

E704B, ,E706) 21.7 77.9 6.6 23.8

E801 0.7 3.1 -- 1.5

E802 2.4 10.4 -- 1.6

E803 -- 1.1 -- --

E804 -- -- -- --

E805 -- -- -- --

S901 -- -- -- --

S902 -- -- -- --

S903 -- -- -- --

S904 -- -- -- --

E520 -- -- -- --

E521 -- -- -- --

E522 -- -- -- --

“--“ indicates that the emissions are less than 1.0 pph or 1.0 tpy and emission limits are not required for this permit.

E. Unless otherwise required by this permit or another applicable regulation, 

compliance with the NOx emission limits shall be determined on a unit-specific basis 

using data from NOx CEMS that have been installed, calibrated, and operated in 

accordance with 40 CFR. 75 and any other applicable requirement. 
NSR Permit No. 0063M8 Page 19 of 54

F. Unless otherwise required by this permit or another applicable regulation, 

compliance with the SO2 emission limits shall be determined on a unit-specific basis 

using data from SO2 CEMS that have been installed, calibrated, and operated in 

accordance with 40 CFR 75 and any other applicable requirement.

G. Each affected facility as defined in 40 CFR 60 Subpart OOO of the limestone 

handling system, including the limestone silo, shall meet the standards for particulate

matter specified in 40 CFR 60.672.

H. In accordance with 20.2.61.109 NMAC, the owner or operator of stationary 

combustion equipment shall not permit, cause, suffer or allow visible emissions from 

the stationary combustion equipment to equal or exceed an opacity of 20 percent; 

provided, however, stationary combustion equipment which is regulated by Parts 

20.2.10 NMAC through 20.2.18 NMAC, 20.2.37 NMAC, and 20.2.42 NMAC, and

any other Part of Chapter 2 which specifically limits particulate emissions is 

exempted from this Part. The emergency generators are subject to 20.2.61.109 

NMAC.

I. The activated carbon silo baghouses shall be designed and operated so there are no 

visible emissions.

(1) For mercury control, the operating procedures needed to maximize mercury 

removal per the consent decree requirements are not yet available to explicitly 

incorporate in this permit renewal. Once PNM, NMED and the Plaintiffs agree on 

the maximal mercury removal rate and procedure, then this permit will be reopened or modified to incorporate limits and/or conditions to meet consent decree 

requirements. (CD 9d)

J. Emission limits totals are used solely for assessing annual fees in accordance with 

20.2.71 NMAC. SJGS has many limits for each pollutant. This table shows the most 

stringent of these limits for each pollutant for which the annual fees will be based. 

Only pollutants for which we can assess fees are shown. (B103A) Emission totals 

from NSR Permit 0063M7 will be used for fees until all units under NSR 0063M8 

have been modified and new pollution controls are operational.

Table 106.J: Emissions (tons per year) total for annual fees use

Unit 1NOx 2CO 3VOC 4SO2

5

PM

E301

Scenario A

Scenario B

4,871

812

3,734

13,140 48.7 2,435 552

244

244

E302

Scenario A

Scenario B

4,844

808

3,715

8,760 48.5 2,423 549

242

242
NSR Permit No. 0063M8 Page 20 of 54

Unit 1NOx 2CO 3VOC 4SO2

5

PM

E303

Scenario A

Scenario B

7,564

1,261

5,801

8,760 75.8 3,783 858

378

378

E304

Scenario A

Scenario B

7,424

1,237

5,691

8,760 74.5 3,711 841

371

371

Misc

Scenario A

Scenario B

6

455

455

455

Totals*

Scenario A

Scenario B

24,703

4,118

18,941

39,420

No Change

No Change

247.5

No Change

No Change

12,352

No Change

No Change

3,255

3,255

3,255

Used for fees

(based on 63M7)

6,000 6,000 247.5 6,000 3,255

* Amounts are capped at 6,000 tpy per pollutant by regulation (20.2.71.111.C(4) NMAC).

1 Units 1,2,3,4: Tons per year NOx limits obtained by scaling up 0.3 lbs/MMBtu 30-day average (CD 9cii; Table 

106.A). 2 Units 1,2,3,4: Tons per year CO limits obtained by scaling up lbs/hr limits (Table 106.A).

3 Units 1,2,3,4: VOC totals based on average coal Btu content and revised heat input values (Application dated 

January 2009). 4 Units 1,2,3,4: Tons per year SO2 limits by scaling up 0.15 lb/MMBtu SO2 PNM self imposed limit. 5 Units 1,2,3,4: Tons per year PM limits obtained by scaling up 0.015 lbs/MMBtu (CD 9cii; Table 106.A) plus the 

PM-2.5 condensibles of 0.019 lbs/MMBtu (NSR 63M7). 6 Represents sum of the non-boiler PM (TSP) is 455 tpy (calculated from Tables 2E, by eliminating the boiler PM).

A107

A. SJGS Units have multiple NOx limits for different averaging times. Some limits are 

expressed in lbs/mmBtu rather than lbs/hr. Units 1, 3 and 4 have a 3-hr average limit 

of 0.45 lbs/mmBtu. During SSM this limit may be exceeded for each of these units. 

The maximum NOx emission rate during SSM for these units is 0.7 lbs/mmBtu. The 

Unit 2 3-hr NOx limit is 0.7 lbs/mmBtu and Unit 2 NOx emissions are not expected 

to exceed this rate during SSM. The permittee shall maintain records in accordance 

with Condition B109.E. SJGS shall comply with all other emission limits established 

for steady state operations even during SSM events.

Facility: Allowable Startup, Shutdown, & Maintenance (SSM) 

A108

A. This facility is authorized for continuous operation. No monitoring, recordkeeping, 

and reporting are required to demonstrate compliance with continuous hours of 

operation.

Facility: Allowable Operations
NSR Permit No. 0063M8 Page 21 of 54

A109

A. For the Title V Permit: A Semi-Annual Report of monitoring activities is due within 

45 days following the end of every 6-month reporting period. The six month 

reporting periods start on January 1st and July 1st of each year.

Facility: Reporting Schedules

B. For the Title V Permit: The Annual Compliance Certification Report is due within 30 

days of the end of every 12-month reporting period. The 12-month reporting period 

starts on January 1st of each year.

C. The quarterly reportable items required by this permit shall be submitted quarterly.

A110

A111

Facility: Fuel Sulfur Requirements – not required

A112

Facility: 20.2.61 NMAC Opacity – not required

A. This permit application has two distinct permitting scenarios that are mutually 

exclusive, i.e., if one scenario becomes final the other scenario becomes moot. 

Scenario A is the permitting scenario required to implement the SJGS Federal 

Implementation Plan (FIP) published in 40 CFR 52.1628 (dated August 22, 2011, 

effective September 21, 2011). The provisions of this FIP are under judicial review, 

but the FIP implementation date makes it necessary to proceed with obtaining the 

authority-to-construct air permit immediately to insure construction of the required 

equipment (SCR) can begin in time to meet the FIP operational deadline. Scenario B 

of this permit application is intended to implement the requirements of the State of 

New Mexico Regional Haze State Implementation Plan, (SIP) adopted pursuant to 40 

CFR 51.309, which specifies controls for SJGS that are different than the FIP. If the 

judicial review of the FIP results in vacatur of the FIP requirements, PNM would 

implement the SIP requirements which require installation and operation of an SNCR 

control system, rather than SCR. SNCR is represented in this permit application as 

Scenario B. While permitting scenarios A and B are distinct, this application 

includes permit modifications that are common to both scenarios. The permitting 

description given below, therefore, list the permitting elements as “Common”, 

“Scenario A” only and “Scenario B” only.

Construction Options

B. Permitting changes/updates to Scenario A (FIP) only:

(1) An SCR system on each boiler unit

(2) An anhydrous ammonia injection system used for supplying ammonia to the SCR 

system consisting of ammonia delivery, storage and injection equipment.
NSR Permit No. 0063M8 Page 22 of 54

(3) A dry sorbent injection system (DSI) consisting of DSI delivery, storage and 

injection equipment.

(4) Modification of the fly ash handling system through addition of ash hoppers at the 

economizer outlets on each boiler unit and bypass of the existing ESP structure.

(5) Modification of the fan system to achieve “balanced” draft configuration allowing 

for the elimination of emission points E510, E502, E503 and E504.

(6) EPA extended the time for compliance with the emission limits from 3 years to 5 

years, the maximum period allowed by the Clean Air Act. Therefore, SCR shall 

be installed on each of the four units as expeditiously as practicable, but in no 

event later than 5 years from the effective date of our final rule. The Federal 

register date was August 22, 2011, effective on September 20, 2011. Installation 

of all control equipment and compliance with new emission limits shall be not 

later than September 20, 2016.

C. Permitting changes/updates to Scenario B (SIP) only:

(1) A system for delivery, storage and injection of 50 percent urea solution into the 

flue gas of each boiler for NOx control by SNCR.

(2) Modification of the fan system to achieve “balanced” draft configuration allowing 

for the elimination of emission points E510, E502, E503 and E504.

(3) In accordance with 40 CFR 51.308(e)(1)(iv), the Department determined that 

SNCR shall be installed on each of the four units as expeditiously as practicable, 

but in no event later than 5 years after approval by the EPA of the SIP. As of July 

6, 2012, EPA has not approved the SIP. NMED establishes the deadline date to be 

the same as the FIP of September 20, 2016.

A113

A114

Compliance Plan

A. Certain terms and conditions of this permit reduce the potential emission rate of 

regulated equipment to values below those allowed prior to the date of issuance of 

this permit. The compliance date for construction or operation of the emission units 

and pollution control equipment required to achieve this reduction in potential 

emission rate is in accordance with the implementation scheduled in the FIP 

(September 20, 2016) or SIP (September 20, 2016).

Reducing Facility Emissions
NSR Permit No. 0063M8 Page 23 of 54

EQUIPMENT SPECIFIC REQUIREMENTS

A200

OIL AND GAS INDUSTRY

Oil and Gas Industry – not required

A300

CONSTRUCTION INDUSTRY

Construction Industry - not required

A400

POWER GENERATION INDUSTRY

This section has common equipment related to most Electric Service Operations (SIC4911).

Power Generation Industry

A. This facility and Units E301, E302, E303, and E304 (boilers) are subject to and shall 

have complied with the requirements of 40 CFR Part 72 by applying for and 

obtaining an Acid Rain Permit, P062AR2.

B. Acid Rain Program Monitoring

Requirement: Emission Units E301, E302, E303, and E304 (boilers) are subject to and shall 

comply with the requirements of 40 CFR Part 75 for installation, calibration, maintenance and 

operation of NOx and SO2 continuous emissions monitoring systems (NOx and SO2 CEMS) 

and for continuous opacity monitoring systems (COMS). 

Monitoring: The permittee shall comply with the requirements at 40 CFR 75.12(a) and 

75.12(b) for continuous monitoring of NOx emissions; with the requirements at 40 CFR 

75.11(a) and 75.11(b)(2) for continuous monitoring of SO2 emissions; with the requirements at 

40 CFR 75.14(a) for continuous monitoring of opacity; and with the requirements at 40 CFR 

75.13(b) and 75.13(c) for continuous monitoring of CO2 emissions. 

Recordkeeping: The permittee shall comply with the applicable recordkeeping requirements 

of 40 CFR Part 75, Continuous Emission Monitoring, subpart F, Sections 75.50 through 75.59; 

and in accordance with Section B109 of this permit..

Reporting: In accordance with 40 CFR 75.

C. Mercury CEMS

Requirement: The permittee shall install, maintain, and operate mercury CEMS in accordance 

with the manufacturer’s recommendations.

Monitoring: The permittee shall continually monitor the mercury emissions using CEMS that 

are installed and maintained in accordance with the CEMS manufacturer’s recommendations.
NSR Permit No. 0063M8 Page 24 of 54

(NSR 63M6R1, Condition 3.m)

Recordkeeping: In accordance with Section B109, the permittee shall keep records of the 

mercury CEMS outputs, calculations, and any CEMS maintenance activity necessary to show 

accurate and continual mercury emission rates were recorded.. 

Reporting: An annual evaluation of the mercury CEMS shall be performed and submitted to 

the NMED within 30 days after January 1 of each year.

D. PNM shall maintain, calibrate, and operate CEMS at San Juan Units E301, E303, and 

E304 to measure accurately and continuously opacity and the emissions of SO2, 

NOx, and the exhaust flow rate from each unit in full compliance with the 

requirements of 40 CFR Parts 60 and 75, including requirements for heat input rate 

measurements. Although Unit 302 is not an affected unit for purposes of NSPS 40 

CFR 60, Subpart D, PNM shall maintain, calibrate, and operate CEMS at San Juan 

Unit E302 to measure continuously opacity and the emissions of SO2, NOx, and the 

exhaust flow rate from the unit in accordance with the requirements of 40 CFR Parts 

60 and 75, including requirements for heat input rate measurements.

A401

A402

Turbines - Not Required

A. Units E301, E302, E303, and E304

Boilers

Requirement: Each boiler shall be equipped and operated with a baghouse, to meet the 

emission limits, except as otherwise allowed under the applicable provisions of 20.2.7 NMAC 

and 40 CFR 60 Subpart A (E301, E303, and E304 only). In addition, Control Devices 

associated with Emission Units E301, E303, and E304 are subject to the requirements of 40 

CFR 60.11(d). Each baghouse associated with the boilers shall be maintained and operated in 

accordance with good air pollution control practices for minimizing emissions. Individual 

boilers shall only be operated when its associated baghouse is achieving a control efficiency 

sufficient to ensure compliance with all applicable particulate emission limits listed in this 

permit.

Monitoring: For baghouses associated with Units E301, E302, E303, and E304, PNM shall 

record the pressure drop across each baghouse with a continuous monitoring device. The 

continuous monitoring device shall be designed with an alarm that records and signals to the 

operator any excursion outside the normal operating range of the baghouse. The normal 

operating range of the baghouse shall be determined by the manufacture or another 

Department approved method.

Recordkeeping: In accordance with Section B109, the pressure drop for each baghouse will 

be recorded hourly and these records will be kept on site for review.

Reporting: No reporting required in accordance with Section B110 of this permit.
NSR Permit No. 0063M8 Page 25 of 54

B. CAM Monitoring, Units E301, E302, E303, and E304

Requirement: CAM Rule Corrective Action Requirements: 

(1) The units are pollutant specific emission units for SO2, NOx and PM and are subject to and 

shall comply with the requirements of 40 CFR Part 64, Compliance Assurance Monitoring, 

including the requirements of 40 CFR 64.7(d) for corrective actions. Each unit has CEMS for 

SO2 and NOx which are required under acid rain regulations and, therefore, exempt SO2 and 

NOx from CAM requirements. 

(2) As a requirement of this permit the permittee is subject to and shall comply with the 

corrective provisions of the PM CAM Plan dated July 2010 submitted in the application for 

this permit and attached to this permit, except that the trigger points for corrective actions and 

excursions shall be those specified in Table 402.B.

(3) In accordance with 40 CFR 64.6(b), the permittee shall submit COM data 12-months after 

the issuance of this permit to show that the indicator range of 6% for Opacity has been set 

sufficiently to satisfy the requirements of 40 CFR 64 and to confirm the appropriateness of the 

indicator.

(40 CFR 64 and 20.2.70.302.A(7) NMAC)

Monitoring: 

(1) The permittee shall continuously monitor opacity of the units in accordance with the 

specifications of 40 CFR Part 60, Appendix B for continuous opacity monitors (COMs). (40 

CFR 64.6(c)(1)(ii) and 20.2.70.302.A(7)).

(2) The COMs shall collect at least one duct opacity reading every 10 seconds, except as 

allowed by (4) below (40 CFR 64.6(c)(1)(iii), 40 CFR 64.3(b)(4), 40 CFR 64.3(d)(3), and 

20.2.70.302.A(7)).

(3) The COMs shall be maintained at all times, including but not limited to maintaining the 

spare parts necessary for routine repairs (40 CFR 64.6(c)(3) and 40 CFR 64.7(b)).

(4) Except for applicable monitoring malfunctions, associated repairs, and required quality 

assurance or control activities, the permittee shall conduct the opacity monitoring at all times 

that each unit is operating. Data recorded during monitoring malfunctions, associated repairs, 

and required quality assurance or control activities shall not be used to meet the requirements 

of this permit that implement the requirements of 40 CFR Part 64. All data collected during all 

other periods shall be used in assessing the operation of the control devices for those emission 

units (40 CFR 64.6(c)(3), 40 CFR 64.7(c)).

(5) For the purposes of terms and conditions of this permit that implement the requirements of 

40 CFR Part 64, a monitoring malfunction is any sudden, infrequent, not reasonably 

preventable failure of the monitoring to provide valid data. Monitoring failures that are caused 

in part by poor maintenance or careless operation are not malfunctions (40 CFR 64.6(c) and 40 

CFR 64.7(c)).

CAM Indicators:

(6) Visible emissions (opacity) as measured by COM systems meeting the 40 CFR60 

Performance Specification One and located in the fabric filter outlet duct from each unit (per 

an Alternative Monitoring Plan submitted to EPA).

(7) Differential pressure drop across the fabric filter on each unit.

(8) By-pass damper position (open/closed) indicator.
NSR Permit No. 0063M8 Page 26 of 54

Recordkeeping: The Permittee shall comply with the requirements of 40 CFR Part 64, 

Compliance Assurance Monitoring, including the recordkeeping requirements of 40 CFR 

64.9(b). (40 CFR 64 and 20.2.70.302.A(7) NMAC).

Reporting: The Permittee shall comply with the requirements of 40 CFR Part 64, Compliance 

Assurance Monitoring, including the reporting requirements of 40 CFR 64.9(a). (40 CFR 64 

and 20.2.70.302.A(7)).

Table 402.B, CAM Indicator Trigger Points for Corrective Actions and Excursions

Indicator Trigger Point1

1 An excursion is defined as a condition when the average opacity exceeds six (6) 

percent for any consecutive 3-hr period.

2 An excursion is defined as a condition when the fabric filter average differential 

pressure exceeds 10 inches water column (w.c) for any consecutive 3-hr period.

3 An excursion is defined as a condition when the by-pass damper is in the open 

position any time when the boiler is in operation. 1

The permittee shall use the permit modification procedures of 20.2.70.404.B NMAC to change the CAM Plan. 

C. Duct Leak Management Program on Units E501, E502, E503, and E504

Requirement: The Duct leak management program shall be conducted in accordance with 

good air pollution control practices for minimizing emission. All remaining combustion gasses 

shall be exhausted through the primary stack of each unit. Compliance with this requirement 

shall be determined using data generated by the monitoring and by Department inspections of 

the units. 

The Expansion Joint Maintenance Program (EJMP) shall include:

a. A written procedure that identifies expansion joint inspection procedures, inspection 

points, inspection locations, inspection frequency and recordkeeping procedures.

b. Identification of measures and time taken to mitigate (minimize) and repair leaks 

including immediate and long-term corrective actions.

c. Quarterly assessment and evaluation of the EJMP covering the ability of the EJMP to 

detect and identify leaks, potential preventive maintenance measures identified to prevent 

or minimize leaks, and assessment of effectiveness of measures taken to minimize leaks.

When each boiler is taken out of service for the purpose of installing the new SCR/SNCR 

control technologies (balanced draft conversion), this requirement is no longer valid. If the 

SCR/SNCR technologies are not installed then this requirement remains valid.

Monitoring: Monitor performance of the EJMP to ensure that the program meets the 

requirements of this permit. At a minimum, this quarterly monitoring shall include an 

assessment of the program’s performance in meeting the requirements above, including an 

estimate of the actual area of duct leaks present on the subject emission units.

Recordkeeping: Records of the EJMP practices, quarterly inspections, and quarterly 

assessment of the program’s performance shall be maintained on site. 

Reporting: No reporting required in accordance with Section B110 of this permit.
NSR Permit No. 0063M8 Page 27 of 54

D. Limestone Forced Oxidation (LSFO) Scrubber Operations

Requirement: The boilers (E301, E302, E303, and E304) shall be equipped and operated with 

limestone scrubbers. PNM shall not exceed the emission limits. To the extent necessary to 

meet the SO2 emission limits and the SO2 control efficiency requirements of this permit (Table 

106.C), PNM shall add dibasic acid to the limestone slurry feed of each scrubber. The 

limestone scrubbers (E301, E302, E303, and E304) shall be maintained and operated in 

accordance with good air pollution control practices for minimizing emissions, except as 

otherwise allowed under the applicable provisions of 20.2.7 NMAC and 40 CFR 60 Subpart A 

(E301, E302, and E304 only). Compliance with these requirements shall be determined using 

data generated and by Department inspections of the units.

Monitoring: Control Devices C09, C11, C13, and C15, associated with Emissions Units 

E301, E302, E303, and E304, respectively, are subject to monitoring for good air pollution 

control practices and proper operation and maintenance. This monitoring shall consist of 

keeping monthly records of the performance of maintenance and repair activities on these 

control devices.

Recordkeeping: In accordance with Section B109, records of performance on maintenance 

and repair activities shall be kept on site for review.

Reporting: No reporting required in accordance with Section B110 of this permit.

E. Heat Input

Requirement: Heat input to these boilers shall not increase as a result of installation of the 

low-NOx burners. Compliance with this condition shall be provided upon request of the 

Department. An increase in heat input solely due to an increase in demand is authorized.

Monitoring: 

(1) For each boiler, the 24-hour heat input value shall be calculated by multiplying the 24-hour 

coal flow rate with the 7-day rolling average Btu content of the coal. The 7-day rolling 

average Btu content of the coal shall be derived from as delivered coal sample analysis. In the 

event no coal is delivered for 7 or more days, the last 7-day rolling average will be used.

(2) PNM shall keep records of the “as-delivered” heat content of the coal. The heat content of 

the coal shall be analyzed using an appropriate ASTM method, in accordance with the 

requirements of the coal contract.

(3) For each boiler, the 365-day rolling total heat input shall be calculated as a summation of 

the 24-hour heat input value calculated. 

Recordkeeping: In accordance with Section B109, records of the “as delivered” heat content 

of the coal and the 365 day rolling total heat input calculations shall be maintained.

Reporting: No reporting required in accordance with Section B110 of this permit. Upon 

written request by the Department, PNM shall summarize and report the 365-day rolling total 

heat input values calculated in (1) above.
NSR Permit No. 0063M8 Page 28 of 54

F. Continuous Opacity Monitors

Requirement:

(1) Units E301, E303, and E304 are subject to 40 CFR 60 Subpart D and PNM shall operate 

the COMs for units E301, E303, and E304 as required in 40 CFR 60 Subpart D. 

(2) Although Unit 302 is not an affected unit for purposes of NSPS 40 CFR 60, Subpart D, 

PNM shall install, calibrate, maintain, and operate COMs on Unit E302 per the procedures 

specified in 40 CFR 60 Subpart D. The COMs for Unit E302 shall be installed in a 

location comparable to the COM location of Units E301, E303, and E304, unless 

otherwise approved by the Department.

(3) For units E301, E302, E303, and E304 the permittee shall determine compliance with the 

opacity limits of the permit on a continuous basis, using data from the current COMS or 

an EPA approved COMs and an alternative location. All COMs shall be certified or 

recertified per the procedures in 40 CFR Part 60. 

Monitoring: For units E301, E302, E303, and E304 the permittee shall determine compliance 

with the opacity limits of the permit on a continuous basis, using data from the current COMS 

or an EPA approved COMs and an alternative location.

Recordkeeping: Records of opacity readings and QA/QC events will be maintained and 

records of compliance with applicable recordkeeping requirements of 40 CFR 60, Subparts A 

and D.

Reporting: In accordance with applicable reporting requirements of 40 CFR Part 60, 

Subparts A and D.

G. 20.2.31 NMAC (Units E301, E302, E303, and E304)

Requirement: The units are subject to and shall comply with the requirements of 20.2.31.112 

NMAC for SO2 continuous emissions monitoring (CEMS).

Monitoring: SO2 continuous emissions monitoring (CEMS).

Recordkeeping: In accordance with Section B109 of this permit and compliance with 

applicable recordkeeping requirements of 20.2.31.113 NMAC.

Reporting: No reporting is required in accordance with Section B110 of this permit.

H. Periodic Stack Test For Units E301, E302, E303, E304, and E803

Requirement: Units E301, E302, E303, and E304 (boilers) are subject to periodic compliance 

testing for PM, TSP, PM10, PM2.5, and CO using stack tests and Emission Unit E803 is subject 

to periodic compliance testing for PM using stack tests. The tests for PM, TSP, PM10, and 

PM2.5 on Emission Units E301, E302, E303, and E304 (boilers) shall be performed quarterly. 

The tests for CO on Emission Units E301, E302, E303, and E304 (boilers) shall be performed 

quarterly. The tests on Emission Unit E803 shall be performed at the discretion of the 

Department. 

Monitoring: The permittee shall perform quarterly tests and keep records of the periodic 

emissions tests in accordance with Table 402.H and Section B111 of this permit.

Recordkeeping: In accordance with Sections B109 and B111 of this permit.

Reporting: In accordance with Sections B110 and B111 of this permit.
NSR Permit No. 0063M8 Page 29 of 54

Table 402.H: Quarterly testing Requirements

Pollutant Reference Method

CO 1 Methods 1-4 and 10

PM (TSP, PM10, PM2.5)

2,3,4 Method 1-5, 5i 1 Test results that demonstrate compliance with CO emission limits shall also be considered to demonstrate 

compliance with VOC emission limits for the subject emission unit. 2 PNM may use Method 5 or 5i testing to demonstrate compliance with the PM10 and PM2.5 standards. 3 PM10 and PM2.5 particulate emissions include condensable particulate matter. 4 PNM shall conduct compliance testing to determine the condensable portion of actual PM10 and PM2.5 emissions 

using EPA Method 202, annually. PNM will also conduct a Method 5i test at approximately the same time it 

conducts each Method 202 test. 

I. Demister Operations

Requirement: Not Later than November 2011, PNM shall install pressure monitoring systems 

across the demister elements associated with all of the scrubber modules. Recordkeeping 

requirements will become effective on January 1, 2012. The monitoring systems shall have the 

accuracy, reliability and quality to determine whether the demisters are operating in as 

represented in the Demister Report that is associated with the 14 fps maximum velocity of the 

demister and based on actual pressure drop readings. (Demister Settlement Agreement, 

Paragraph 21.j)

(1) Each demister will be cleaned with “clean wash water sprays” on a wash sequence which 

is in automatic mode and in continuous operation. The wash sequence will automatically 

switch from cell to cell. 

(2) During plant outages, manual cleaning to remove stubborn deposits as noted during

inspections

Monitoring: 

(1) PNM shall monitor hourly the pressure drop across each demister from a continuous 

monitoring device. The continuous monitoring device shall be designed with an alarm that 

records and signals to the operator any excursion equal to or above 0.5 inches W.C. across 

either level or 1.0 across both. 

(2) During outages of 96 hours or more, PNM shall inspect the demisters based on 

manufacturers’ recommendations for deposit which are not cleaned by the clean wash water 

spraying.

Recordkeeping: 

(1) PNM shall record hourly the pressure drop across each demister.

(2) Record the time and dates of all 3 hour averages equal to or above 0.5 inches W.C. for

either of the two (2) levels or 1.0 combined.

(3) Record the corrective action taken to return the demister back to normal operation.

(4) Record the findings from the demister inspections.

(5) Record when manual cleaning is performed.

Reporting: Quarterly reporting is required in accordance with the Consent Decree, Section X, 

Reporting, Paragraphs 22-26. Once the Consent Decree is terminated then the quarterly reports 

shall be prepared and maintained onsite in accordance with Condition B110. The Quarterly 
NSR Permit No. 0063M8 Page 30 of 54

reports will continue to be summarized in the semi-annual reporting.

J. 40 CFR 60, Subpart D (Units E301, E303, and E304)

Requirement: The units are subject to 40 CFR 60, Subpart D and the permittee shall comply 

with the applicable requirements of 40 CFR 60, Subpart A and Subpart D.

Monitoring: The permittee shall comply with all applicable monitoring and testing 

requirements of 40 CFR 60, Subpart D.

Recordkeeping: Records of compliance with applicable recordkeeping requirements of 40 

CFR Part 60, Subparts A and D.

Reporting: In accordance with applicable reporting requirements of 40 CFR Part 60, 

Subparts A and D.

K. Coal Pulverizer Unit E201

Requirement: The coal pulverizers (E201) shall be entirely enclosed in a structure that is 

maintained and operated in accordance with good air pollution control practices in order to 

minimize particulate emissions. 

Monitoring: Annual operational inspection, no less than once per calendar year, PNM shall 

inspect the coal pulverizers to insure operation is in accordance with good air pollution control 

practices in order to minimize particulate emissions. 

Recordkeeping: In accordance with Section B109, PNM shall record the results of the 

inspections for the coal pulverizes.

Reporting: No reporting required in accordance with Section B110 of this permit.

L. H2SO4, Sulfuric Acid Mist Units E301, E302, E303, and E304

Requirement: Only for scenario A as required by the FIP and to demonstrate compliance with 

the emission limits identified in Table 106.A, the following monitoring is required on a per 

unit basis.

Monitoring:

The current Method 8A test, as specified in the FIP, does not have the sensitivity to measure 

accurately to 0.00026 lb/mmBtu levels. As a result, each unit shall be considered in 

compliance with the sulfuric acid emission limit if the results of the Method 8A test are at or 

below the level representing three times the representative detection limit (RDL) of Method 

8A, which is 0.0018 lb/mmBtu (equal to three times the RDL of 0.0006 lb/mmBtu). This 

method of demonstrating compliance is consistent with EPA’s approach in addressing 

measurement imprecision and variability for electric generating units, like those at SJGS, and 

for other industries as well. 77 Fed. Reg. 9304, 9390 (Feb. 16, 2012) (describing a 3xRDL 

approach). Once every three years from the issuance of this permit, PNM shall conduct a 

survey of test methods approved by EPA to determine if new test methods are available that 

can accurately measure 0.00026 lb/mmBtu with a measurement imprecision of less than 20%.

Once a new, more accurate test method becomes available, PNM shall perform the test once 

every calendar year on each unit to demonstrate compliance with the emission limit of 0.00026 

lb/mmBtu. 

Note, CTM-013 (i.e., Method 8A) indicates that “the minimum detectable limit (MDL) of the 
NSR Permit No. 0063M8 Page 31 of 54

method is 0.50 milligrams/cubic meter,” which translates to 0.0006 lb/mmBtu for SJGS.

Recordkeeping: In accordance with Section B109, PNM shall record the methodology used 

to calculate the lb/MMBtu emissions and the data used to support the calculations. PNM shall 

record summaries of the product searches for available test methods. PNM shall record any 

tests performed.

Reporting: In accordance with Section B110 of this permit, the permittee shall report semiannually a summary of the Sulfuric Acid Mist emissions in lb/MMBtu and any changes in 

available testing options.

M. Ammonia Slip Units E301, E302, E303, and E304

Requirement: To demonstrate compliance with the emission limits identified in Table 106.A, 

PNM must confirm as part of its initial compliance demonstration following the construction 

of the additional control equipment authorized by this permit that the controls are designed to 

meet the applicable ammonia slip limits (2 ppm for SCR under Scenario A, and 10 ppm for 

SNCR under Scenario B). Since no further emission limits apply, no additional monitoring is 

required.

Monitoring: None

Recordkeeping: In accordance with Section B109, PNM shall record the initial compliance 

demonstration.

Reporting: In accordance with Section B110 of this permit, the permittee shall report the 

initial compliance demonstration.

A403

A. Units E602, E603, E604, E605, E606, and E607 (emergency generators)

Engines 

Requirement: Units shall burn only No. 2 Diesel Fuel Oil. Except for maintenance and testing 

activities, units shall only be operated during the unavoidable loss of commercial utility power. 

Each emergency generator shall not operate more than 500 hours per year. Compliance with 

this requirement shall be determined using hours of operation data. 

Monitoring: Monitor emission by maintaining records to demonstrate that only No. 2 Diesel 

Fuel Oil was used and that each unit did not operate more than 500 hours per calendar year 

during an unavoidable loss of commercial utility power. PNM shall monitor the operating 

hours of the emergency generators.

Recordkeeping: In accordance with Section B109, PNM shall record the monthly and 12 

month total operating hours of each emergency generator.

Reporting: No reporting is required in accordance with Section B110 of this permit.

A404 Heaters - Not Required
NSR Permit No. 0063M8 Page 32 of 54

A405

A. Operational Requirements for Units E406, E407, E408, E409, and E410

Cooling Towers

Requirement: Cooling towers shall be maintained and operated according to manufacturer’s 

recommendations and good engineering practices, and the circulating water rate, total 

dissolved solids (TDS) content of that water, and the drift rate for the units shall not exceed the 

values specified in Table 405.A below. Compliance with these limits shall be determined using 

data generated by the monitoring and by Department inspections of the units.

Monitoring: PNM shall measure the TDS concentration of each cooling tower no less than 

once each calendar quarter.

Recordkeeping: In accordance with Section B109, no less than once each calendar quarter, 

the permittee shall record the TDS concentration of each cooling tower. The permittee shall 

then calculate and record the individual cooling tower PM emissions quarterly, based on the 

maximum capacity of the circulating water pump(s) for each unit, the actual TDS content, and 

the units specific drift rate. 

Reporting: No reporting required in accordance with Section B110 of this permit.

Table 405.A, Circulating Rate, TDS, and Drift Rate Operational Limits for Cooling Towers

Emission 

Unit No. Circulating Water Rate (gpm) TDS Content(milligrams/liter) Drift Rate (percent)

E406 170,000 6,000 0.002

E407 165,000 6,000 0.002

E408 220,000 3,900 0.0015

E409 227,500 6,000 0.002

E410 35,000 3,900 0.002

A406

A. Road Area Operational Requirements Units E701, E702, E703, E704, E705, E706, 

and E707

Haul Roads/Storage piles (Coal-Fired Plants)

Requirement: Road areas shall comply with the operational requirements specified in Table 

406.A. Compliance is demonstrated by monitoring and by Department inspections of the units. 

Monitoring: The permittee shall monitor emissions by maintaining a log/records of the times 

and location of water application, the times and location of sweeping, amount of water applied 

to the haul road, occurrences of visual inspections and by performing weekly visual 

inspections of the road area to determine that emissions are minimized. 

Recordkeeping: In accordance with Section B109, the records will be maintained on site for 
NSR Permit No. 0063M8 Page 33 of 54

review.

Reporting: No reporting required in accordance with Section B110 of this permit.

Table 406.A, Operational Requirements for Road Areas

Emission Unit No. Operational Requirements

E701, E705, and E708 Unit shall be paved, and swept and watered as necessary, to 

minimize emissions of TSP and PM10

E702, E703, E704, E706, and 

E707

Unit shall be watered as necessary to minimize emissions of 

TSP and PM10

B. Facility-Wide Raw Material Limits

Requirement: The calendar year material processing limits in Table 406.B were calculated 

from the AP-42 emission factors and pounds per hour emission rates for tons processed or 

gallons consumed. To demonstrate compliance with annual emission limits, the facility shall 

not process more than the quantities of raw materials specified in Table 406.B. Compliance 

with this limit shall be determined using data generated here.

Monitoring: The permittee shall monitor and record facility-wide raw material usage on a 

calendar quarter basis (which coincides with the reporting periods established at Condition 

A109). PNM shall monitor the quantities of coal, diesel fuel, and limestone processed. (NSR 

63M6R1, Condition 3.j) For each 24-hour period, the permittee shall monitor the coal flows in 

each boiler.

Recordkeeping: In accordance with Section B109, PNM shall maintain quarterly and annualto-date records of the quantities of coal, diesel fuel, and limestone processed.

Reporting: No reporting required in accordance with Section B110 of this permit.

Table 406.B, Facility-Wide Operational Limits on Raw Materials

Material Annual Limit

Coal 8,200,000 tons

No. 2 Diesel Fuel Oil 4,112,500 gallons(4 million gpy for the coal fired boilers and 112, 

500 gpy for the emergency generators)

Limestone 227,000 tons

C. Good Air Pollution Control Practices

Requirement: Coal pile maintenance (E101, E102, E103, and E104), fly ash silo unloading to 

trucks (E507, E508, E509, E510), limestone delivery system, and limestone pile maintenance 

(E802) shall be operated in accordance with good air pollution control practices to minimize 

emissions.

Monitoring: No less than once each calendar year, PNM shall inspect the coal pile 

maintenance, fly ash silo unloading to trucks, limestone delivery, and limestone pile 
NSR Permit No. 0063M8 Page 34 of 54

maintenance. 

Recordkeeping: In accordance with Section B109, PNM shall record the results of the 

inspection for the coal pile maintenance, fly ash silo unloading to trucks, limestone delivery, 

and limestone pile maintenance. Records and/or logs of control practices to demonstrate 

compliance with the controls in the permit application shall be maintained and summarized in 

the Semi-annual reports.

Reporting: No reporting required in accordance with Section B110 of this permit.

D. NSPS Subpart OOO (Units E803, E804, and E805 (limestone process equipment))

Requirement: Allowable emission limits

Monitoring: The units are subject to and shall comply with the requirements of 40 CFR 60, 

Subpart A and of 40 CFR 60, Subpart OOO, 60.675(c) for monitoring emissions.

Recordkeeping: In accordance with the applicable requirements of 40 CFR 60, Subpart 

OOO, 60.676(f). Records of any periodic opacity determinations will be maintained.

Reporting: In accordance with the applicable requirements of 40 CFR 60, Subpart OOO. 

Opacity test results will be submitted to the NMED.

A407

A. Activated Carbon Silo Baghouses (Units E901, E902, E903, and E904)

Storage Silos (activated carbon, fly ash)

Requirement: Activated Carbon for Mercury emissions control

(1) Each of the activated carbon silos shall be equipped with a baghouse operated according 

to manufacturer’s guidelines and specification. The baghouse shall have a design PM 

emission rate of 0.0092 grains/scf or less and a design baghouse exhaust flow rate of 578 

scfm.

(2) The activated carbon shall be introduced into the exhaust stream prior to the baghouse 

used to control particulate matter from the respective boilers.

(3) Each activated carbon baghouse shall be equipped and operated with a device to 

continuously monitor the pressure differential across the baghouse to insure continued 

compliance.

Monitoring: PNM shall monitor the pressure drop across each activated carbon silo baghouse 

whenever the silos are loaded. The data capture rate shall be no less than once every six 

minutes. At a minimum the record shall include the silo designation, date, time, pressure 

differential, and in the event that the pressure differential is not continually monitored, the silo 

loading status (fan on or off).

Recordkeeping: PNM shall follow the General Recordkeeping requirement in Section B109.

(1) PNM shall keep manufacturer’s documentation onsite indicting that each activated carbon 

silo baghouse was designed to control PM emissions 0.0092 grains/scf or less and design 

baghouse exhaust flow rate is 578 scfm.

(2) PNM shall keep records of the pressure drop across each activated carbon silo baghouse.

(3) PNM shall keep the manufacturer’s documentation onsite that indicates the proper range 

that the pressure drop should be during normal operations of each activated carbon silo 
NSR Permit No. 0063M8 Page 35 of 54

baghouse.

Reporting: No reporting required in accordance with Section B110 of this permit.

B. Fly Ash/Limestone Silo Baghouses

Requirement: The fly ash silo loading (E505, E506, E518, and E519) and limestone silo 

loading (E803) shall be equipped and operated with baghouses. The baghouses shall be 

equipped and operated with devices to monitor the differential pressure drop across the 

baghouse. The control devices shall be operated and maintained in accordance with 

manufacturer’s specifications, including specifications for pressure drop, in order to achieve a 

minimum 99.5% control of TSP, PM10, and PM emissions. Compliance with these 

requirements shall be determined using data generated and by Department inspections of the 

units.

Monitoring: The permittee shall monitor emissions by measuring the pressure drop across 

each filter, daily. PNM shall monitor and record the pressure drop across each fly ash silo 

baghouse (Units 505 and 506). For baghouse associated with the Units E505, E506, E518, 

E519 and E803, PNM shall monitor the differential pressure drop across the baghouses daily.

(Units 505 and 506).

Recordkeeping: In accordance with Section B109, PNM shall record the daily pressure drop 

measurements for each baghouse. 

Reporting: No reporting required in accordance with Section B110 of this permit.
NSR Permit No. 0063M8 Page 36 of 54

PART B

B100

GENERAL CONDITIONS

A. The Department has reviewed the permit application for the proposed 

construction/modification/revision and has determined that the provisions of the Act 

and ambient air quality standards will be met. Conditions have been imposed in this 

permit to assure continued compliance. 20.2.72.210.D NMAC, states that any term 

or condition imposed by the Department on a permit is enforceable to the same 

extent as a regulation of the Environmental Improvement Board.

Introduction

B101

A. The contents of a permit application specifically identified by the Department shall 

become the terms and conditions of the permit or permit revision. Unless modified 

by conditions of this permit, the permittee shall construct or modify and operate the 

Facility in accordance with all representations of the application and supplemental 

submittals that the Department relied upon to determine compliance with applicable 

regulations and ambient air quality standards. If the Department relied on air quality 

modeling to issue this permit, any change in the parameters used for this modeling 

shall be submitted to the Department for review. Upon the Department’s request, the 

permittee shall submit additional modeling for review by the Department. Results of 

that review may require a permit modification. (20.2.72.210.A NMAC)

Legal

B. Any future physical changes, changes in the method of operation or changes in 

restricted area may constitute a modification as defined by 20.2.72 NMAC, 

Construction Permits. Unless the source or activity is exempt under 20.2.72.202 

NMAC, no modification shall begin prior to issuance of a permit. (20.2.72 NMAC 

Sections 200.A.2 and E, and 210.B.4)

C. Changes in plans, specifications, and other representations stated in the application 

documents shall not be made if they cause a change in the method of control of 

emissions or in the character of emissions, will increase the discharge of emissions or 

affect modeling results. Any such proposed changes shall be submitted as a revision 

or modification. (20.2.72 NMAC Sections 200.A.2 and E, and 210.B.4)

D. The permittee shall establish and maintain the property’s Restricted Area as 

identified in plot plan submitted with the application. (20.2.72 NMAC Sections 

200.A.2 and E, and 210.B.4)

E. Applications for permit revisions and modifications shall be submitted to:

Program Manager, Permits Section
NSR Permit No. 0063M8 Page 37 of 54

New Mexico Environment Department

Air Quality Bureau

1301 Siler Road, Building B

Santa Fe, New Mexico 87507-3113

F. At all times, including periods of startup, shutdown, and malfunction, owners and 

operators shall, to the extent practicable, maintain and operate the source including 

associated air pollution control equipment in a manner consistent with good air 

pollution control practice for minimizing emissions. (20.2.7.109, 20.2.72.210.A, 

20.2.72.210.B, 20.2.72.210.C, 20.2.72.210.E NMAC) The establishment of 

allowable malfunction emission limits does not supersede this requirement.

B102

A. This permit is issued pursuant to the Air Quality Control Act (Act) and regulations 

adopted pursuant to the Act including Title 20, Chapter 2, Part 72 of the New Mexico 

Administrative Code (NMAC), (20.2.72 NMAC), Construction Permits and is 

enforceable pursuant to the Act and the air quality control regulations applicable to 

this source.

Authority

B. The Department is the Administrator for 40 CFR Parts 60, 61, and 63 pursuant to the 

delegation and exceptions of Section 10 of 20.2.77 NMAC (NSPS), 20.2.78 NMAC 

(NESHAP), and 20.2.82 NMAC (MACT).

B103

A. The Department will assess an annual fee for this Facility. The regulation 20.2.75 

NMAC set the fee amount at $1,500 through 2004 and requires it to be adjusted 

annually for the Consumer Price Index on January 1. The current fee amount is 

available by contacting the Department or can be found on the Department’s website. 

The AQB will invoice the permittee for the annual fee amount at the beginning of 

each calendar year. This fee does not apply to sources which are assessed an annual 

fee in accordance with 20.2.71 NMAC. For sources that satisfy the definition of 

“small business” in 20.2.75.7.F NMAC, this annual fee will be divided by two. 

(20.2.75.11 NMAC)

Annual Fee

B. All fees shall be remitted in the form of a corporate check, certified check, or money 

order made payable to the “NM Environment Department, AQB” mailed to the 

address shown on the invoice and shall be accompanied by the remittance slip 

attached to the invoice.
NSR Permit No. 0063M8 Page 38 of 54

B104

A. Any person who participated in a permitting action before the Department and who is 

adversely affected by such permitting action, may file a petition for hearing before 

the Environmental Improvement Board. The petition shall be made in writing to the 

Environmental Improvement Board within thirty (30) days from the date notice is 

given of the Department's action and shall specify the portions of the permitting 

action to which the petitioner objects, certify that a copy of the petition has been 

mailed or hand-delivered and attach a copy of the permitting action for which review 

is sought. Unless a timely request for hearing is made, the decision of the 

Department shall be final. The petition shall be copied simultaneously to the 

Department upon receipt of the appeal notice. If the petitioner is not the applicant or 

permittee, the petitioner shall mail or hand-deliver a copy of the petition to the 

applicant or permittee. The Department shall certify the administrative record to the 

board. Petitions for a hearing shall be sent to: (20.2.72.207.F NMAC)

Appeal Procedures

Secretary, New Mexico Environmental Improvement Board

1190 St. Francis Drive, Runnels Bldg. Rm. N2153

P.O. Box 5469

Santa Fe, New Mexico 87502

B105

A. Stack Test Protocols and Stack Test Reports shall be submitted electronically to 

Submittal of Reports and Certifications

Stacktest.AQB@state.nm.us or as directed by the Department.

B. Excess Emission Reports shall be submitted electronically to 

eereports.aqb@state.nm.us. (20.2.7.110 NMAC)

C. Regularly scheduled reports shall be submitted to:

Manager, Compliance and Enforcement Section

New Mexico Environment Department

Air Quality Bureau

1301 Siler Road, Building B

Santa Fe, New Mexico 87507-3113

B106

A. If a facility is subject to a NSPS standard in 40 CFR 60, each owner or operator that 

installs and operates a continuous monitoring device required by a NSPS regulation 

shall comply with the excess emissions reporting requirements in accordance with 40 

CFR 60.7(c), unless specifically exempted in the applicable subpart.

NSPS and/or MACT Startup, Shutdown, and Malfunction Operations
NSR Permit No. 0063M8 Page 39 of 54

B. If a facility is subject to a NSPS standard in 40 CFR 60, then in accordance with 40 

CFR 60.8(c), emissions in excess of the level of the applicable emission limit during 

periods of startup, shutdown, and malfunction shall not be considered a violation of 

the applicable emission limit unless otherwise specified in the applicable standard.

C. If a facility is subject to a MACT standard in 40 CFR 63, then the facility is subject 

to the requirement for a Startup, Shutdown and Malfunction Plan (SSM) under 40 

CFR 63.6(e)(3), unless specifically exempted in the applicable subpart.

B107

A. The establishment of permitted startup, shutdown, and maintenance (SSM) emission 

limits does not supersede the requirements of 20.2.7.14.A NMAC. Except for 

operations or equipment subject to Condition B106, the permittee shall establish and 

implement a plan to minimize emissions during routine or predictable start up, shut 

down, and scheduled maintenance (SSM work practice plan) and shall operate in 

accordance with the procedures set forth in the plan. (SSM work practice plan. 

(20.2.7.14.A NMAC)

Startup, Shutdown, and Maintenance Operations

B108

A. These requirements do not supersede or relax requirements of federal regulations.

General Monitoring Requirements

B. The following monitoring requirements shall be used to determine compliance with 

applicable requirements and emission limits. Any sampling, whether by portable 

analyzer or EPA reference method, that measures an emission rate over the 

applicable averaging period greater than an emission limit in this permit constitutes 

noncompliance with this permit. The Department may require, at its discretion, 

additional tests pursuant to EPA Reference Methods at any time, including when 

sampling by portable analyzer measures an emission rate greater than an emission 

limit in this permit; but such requirement shall not be construed as a determination 

that the sampling by portable analyzer does not establish noncompliance with this 

permit and shall not stay enforcement of such noncompliance based on the sampling 

by portable analyzer.

C. If the emission unit is shutdown at the time when periodic monitoring is due to be 

accomplished, the permittee is not required to restart the unit for the sole purpose of 

performing the monitoring. Using electronic or written mail, the permittee shall 

notify the Department’s Compliance and Enforcement Section of a delay in emission 

tests prior to the deadline for accomplishing the tests. Upon recommencing operation, 

the permittee shall submit any pertinent pre-test notification requirements set forth in 

the current version of the Department’s Standard Operating Procedures For Use Of 

Portable Analyzers in Performance Test, and shall accomplish the monitoring.
NSR Permit No. 0063M8 Page 40 of 54

D. The requirement for monitoring during any monitoring period is based on the 

percentage of time that the unit has operated. However, to invoke monitoring 

exemptions at B108.D(2), hours of operation shall be monitored and recorded. 

(1) If the emission unit has operated for more than 25% of a monitoring period, then 

the permittee shall conduct monitoring during that period.

(2) If the emission unit has operated for 25% or less of a monitoring period then the 

monitoring is not required. After two successive periods without monitoring, the 

permittee shall conduct monitoring during the next period regardless of the time 

operated during that period, except that for any monitoring period in which a unit 

has operated for less than 10% of the monitoring period, the period will not be 

considered as one of the two successive periods.

(3) If invoking the monitoring period exemption in B108.D(2), the actual operating 

time of a unit shall not exceed the monitoring period required by this permit 

before the required monitoring is performed. For example, if the monitoring 

period is annual, the operating hours of the unit shall not exceed 8760 hours 

before monitoring is conducted. Regardless of the time that a unit actually 

operates, a minimum of one of each type of monitoring activity shall be

conducted during any five-year period.

E. For all periodic monitoring events, except when a federal or state regulation is more 

stringent, three test runs shall be conducted at 90% or greater of the unit’s capacity as 

stated in this permit, or in the permit application if not in the permit, and at additional 

loads when requested by the Department. If the 90% capacity cannot be achieved, 

the monitoring will be conducted at the maximum achievable load under prevailing 

operating conditions except when a federal or state regulation requires more 

restrictive test conditions. The load and the parameters used to calculate it shall be 

recorded to document operating conditions and shall be included with the monitoring 

report.

F. When requested by the Department, the permittee shall provide schedules of testing 

and monitoring activities. Compliance tests from previous NSR and Title V permits 

may be re-imposed if it is deemed necessary by the Department to determine whether 

the source is in compliance with applicable regulations or permit conditions.

G. If monitoring is new or is in addition to monitoring imposed by an existing 

applicable requirement, it shall become effective 120 days after the date of permit 

issuance. For emission units that have not commenced operation, the associated new 

or additional monitoring shall not apply until 120 days after the units commence 

operation. All pre-existing monitoring requirements incorporated in this permit shall 

continue to apply from the date of permit issuance.
NSR Permit No. 0063M8 Page 41 of 54

B109

A. The permittee shall maintain records to assure and verify compliance with the terms 

and conditions of this permit and any other applicable requirements that become 

effective after permit issuance. The minimum information to be included in these 

records is: 

General Recordkeeping Requirements

(1) equipment identification (include make, model and serial number for all tested 

equipment and emission controls); 

(2) date(s) and time(s) of sampling or measurements;

(3) date(s) analyses were performed;

(4) the qualified entity that performed the analyses;

(5) analytical or test methods used;

(6) results of analyses or tests; and

(7) operating conditions existing at the time of sampling or measurement.

B. Except as provided in the Specific Conditions, records shall be maintained on-site or 

at the permittee’s local business office for a minimum of two (2) years from the time 

of recording and shall be made available to Department personnel upon request. 

Sources subject to 20.2.70 NMAC “Operating Permits” shall maintain records on-site 

for a minimum of five (5) years from the time of recording.

C. Malfunction emissions and routine and predictable emissions during startup, 

shutdown, and scheduled maintenance (SSM):

(1) The permittee shall keep records of all events subject to the plan to minimize 

emissions during routine or predictable SSM. (20.2.7.14.A NMAC)

(2) If the facility has allowable SSM emission limits in this permit, the permittee shall 

record all SSM events, including the date, the start time, the end time, and a 

description of the event. This record also shall include a copy of the 

manufacturer’s, or equivalent, documentation showing that any maintenance 

qualified as scheduled. Scheduled maintenance is an activity that occurs at an 

established frequency pursuant to a written protocol published by the 

manufacturer or other reliable source. The authorization of allowable SSM 

emissions does not supersede any applicable federal or state standard. The most 

stringent requirement applies.

(3) If the facility has allowable malfunction emission limits in this permit, the 

permittee shall record all malfunction events to be applied against these limits, 

including the date, the start time, the end time, and a description of the event. 

Malfunction means any sudden, infrequent, and not reasonably preventable 

failure of air pollution control and monitoring equipment, process equipment, or a 

process to operate in a normal or usual manner which causes, or has the potential 
NSR Permit No. 0063M8 Page 42 of 54

to cause, the emission limitations in an applicable standard to be exceeded. 

Failures that are caused in part by poor maintenance or careless operation are not 

malfunctions. (40 CFR 63.2, 20.2.7.7.E NMAC) The authorization of allowable 

malfunction emissions does not supersede any applicable federal or state standard. 

The most stringent requirement applies. This authorization only allows the 

permittee to avoid submitting reports under 20.2.7 NMAC for total annual 

emissions that are below the authorized limit. 

B110

(20.2.72 NMAC Sections 210 and 212)

General Reporting Requirements

A. Records and reports shall be maintained on-site unless specifically required to be 

submitted to the Department or EPA by another condition of this permit or by a state 

or federal regulation. Records for unmanned sites may be kept at the nearest 

company office.

B. The permittee shall notify the Department’s Compliance Reporting Section using the 

current Submittal Form posted to NMED’s Air Quality web site under Compliance 

and Enforcement/Submittal Forms in writing of, or provide the Department with 

(20.2.72.212.A and B):

(1) the anticipated date of initial startup of each new or modified source not less than 

thirty (30) days prior to the date. Notification may occur prior to issuance of the 

permit, but actual startup shall not occur earlier than the permit issuance date;

(2) after receiving authority to construct, the equipment serial number as provided by 

the manufacturer or permanently affixed if shop-built and the actual date of initial 

startup of each new or modified source within fifteen (15) days after the startup 

date; and 

(3) the date when each new or modified emission source reaches the maximum 

production rate at which it will operate within fifteen (15) days after that date.

C. The permittee shall notify the Department’s Permitting Program Manager, in writing 

of, or provide the Department with (20.2.72.212.C and D):

(1) any change of operators or any equipment substitutions within fifteen (15) days of 

such change;

(2) any necessary update or correction no more than sixty (60) days after the operator 

knows or should have known of the condition necessitating the update or 

correction of the permit.

D. Results of emission tests and monitoring for each pollutant (except opacity) shall be 

reported in pounds per hour (unless otherwise specified) and tons per year. Opacity 

shall be reported in percent. The number of significant figures corresponding to the 

full accuracy inherent in the testing instrument or Method test used to obtain the data
NSR Permit No. 0063M8 Page 43 of 54

shall be used to calculate and report test results in accordance with 20.2.1.116.B and 

C NMAC. Upon request by the Department, CEMS and other tabular data shall be 

submitted in editable, MS Excel format.

E. The permittee shall submit reports of excess emissions in accordance with 

20.2.7.110.A NMAC. 

B111

A. Compliance Tests

General Testing Requirements

(1) Compliance test requirements from previous permits (if any) are still in effect, 

unless the tests have been satisfactorily completed. Compliance tests may be reimposed if it is deemed necessary by the Department to determine whether the 

source is in compliance with applicable regulations or permit conditions. (20.2.72 

NMAC Sections 210.C and 213)

(2) Compliance tests shall be conducted within sixty (60) days after the unit(s) 

achieve the maximum normal production rate. If the maximum normal 

production rate does not occur within one hundred twenty (120) days of source 

startup, then the tests must be conducted no later than one hundred eighty (180) 

days after initial startup of the source.

(3) Unless otherwise indicated by Specific Conditions or regulatory requirements, the 

default time period for each test run shall be at least 60 minutes and each 

performance test shall consist of three separate runs using the applicable test 

method. For the purpose of determining compliance with an applicable emission 

limit, the arithmetic mean of results of the three runs shall apply. In the event that 

a sample is accidentally lost or conditions occur in which one of the three runs 

must be discontinued because of forced shutdown, failure of an irreplaceable 

portion of the sample train, extreme meteorological conditions, or other 

circumstances, beyond the owner or operator's control, compliance may, upon the 

Department approval, be determined using the arithmetic mean of the results of 

the two other runs.

(4) Testing of emissions shall be conducted with the emissions unit operating at 90 to 

100 percent of the maximum operating rate allowed by the permit. If it is not 

possible to test at that rate, the source may test at a lower operating rate, subject to 

the approval of the Department.

(5) Testing performed at less than 90 percent of permitted capacity will limit 

emission unit operation to 110 percent of the tested capacity until a new test is 

conducted.

(6) If conditions change such that unit operation above 110 percent of tested capacity 

is possible, the source must submit a protocol to the Department within 30 days of 

such change to conduct a new emissions test.
NSR Permit No. 0063M8 Page 44 of 54

B. EPA Reference Method Tests

(1) All compliance tests required by this permit, unless otherwise specified by 

Specific Conditions of this permit, shall be conducted in accordance with the 

requirements of CFR Title 40, Part 60, Subpart A, General Provisions, and the 

following EPA Reference Methods as specified by CFR Title 40, Part 60, 

Appendix A:

(a) Methods 1 through 4 for stack gas flowrate

(b) Method 5 for TSP

(c) Method 6C and 19 for SO2

(d) Method 7E for NOX (test results shall be expressed as nitrogen dioxide 

(NO2) using a molecular weight of 46 lb/lb-mol in all calculations (each 

ppm of NO/NO2 is equivalent to 1.194 x 10-7 lb/SCF)

(e) Method 9 for opacity

(f) Method 10 for CO

(g) Method 19 may be used in lieu of Methods 1-4 for stack gas flowrate upon 

approval of the Department. A justification for this proposal must be 

provided along with a contemporaneous fuel gas analysis (preferably on 

the day of the test) and a recent fuel flow meter calibration certificate 

(within the most recent quarter).

(h) Method 7E or 20 for Turbines per 60.335 or 60.4400

(i) Method 29 for Metals

(j) Method 201A for filterable PM10 and PM2.5 (Dry Stacks)

(k) Method 5, 5B or 5I for filterable PM10 and PM2.5 (Wet Stacks)

(l) Method 202 for condensable PM

(m) Method 320 for organic Hazardous Air Pollutants (HAPs)

(n) Method 25A for VOC reduction efficiency

(2) Alternative test method(s) may be used if the Department approves the change

C. Periodic Monitoring and Portable Analyzer Requirements

(1) Periodic emissions tests (periodic monitoring) may be conducted in accordance 

with EPA Reference Methods or by utilizing a portable analyzer. Periodic 

monitoring utilizing a portable analyzer shall be conducted in accordance with the 

requirements of ASTM D 6522-00. However, if a facility has met a previously 

approved Department criterion for portable analyzers, the analyzer may be 

operated in accordance with that criterion until it is replaced.
NSR Permit No. 0063M8 Page 45 of 54

(2) Unless otherwise indicated by Specific Conditions or regulatory requirements, the 

default time period for each test run shall be as follows:

(a) For quarterly monitoring, at least 20 minutes

(b) For annual monitoring, at least 60 minutes

Each performance test shall consist of three separate runs. The arithmetic mean 

of results of the three runs shall be used to determine compliance with the 

applicable emission limit

(3) Testing of emissions shall be conducted with the emissions unit operating at 90 to 

100 percent of the maximum operating rate allowed by the permit. If it is not 

possible to test at that rate, the source may test at a lower operating rate, subject to 

prior approval of the Department.

(4) During emissions tests, pollutant, O2 concentration and fuel flow rate shall be 

monitored and recorded. This information shall be included with the test report 

furnished to the Department.

(5) Pollutant emission rate shall be calculated in accordance with 40 CFR 60, 

Appendix A, Method 19 utilizing fuel flow rate (scf) and fuel heating value 

(Btu/scf) obtained during the test.

D. Test Procedures:

(1) The permittee shall notify the Department’s Program Manager, Compliance and 

Enforcement Section at least thirty (30) days before the test date and allow a 

representative of the Department to be present at the test.

(2) Equipment shall be tested in the "as found" condition. Equipment may not be 

adjusted or tuned prior to any test for the purpose of lowering emissions, and then 

returned to previous settings or operating conditions after the test is complete.

(3) Contents of test notifications, protocols and test reports shall conform to the 

format specified by the Department’s Universal Test Notification, Protocol and 

Report Form and Instructions. Current forms and instructions are posted to 

NMED’s Air Quality web site under Compliance and Enforcement Testing. 

(4) The permittee shall provide (a) sampling ports adequate for the test methods 

applicable to the facility, (b) safe sampling platforms, (c) safe access to sampling 

platforms and (d) utilities for sampling and testing equipment. 

(5) The stack shall be of sufficient height and diameter and the sample ports shall be 

located so that a representative test of the emissions can be performed in 

accordance with the requirements of EPA Method 1 or ASTM D 6522-00 as 

applicable.

(6) Where necessary to prevent cyclonic flow in the stack, flow straighteners shall be 

installed
NSR Permit No. 0063M8 Page 46 of 54

(7) Unless otherwise indicated by Specific Conditions or regulatory requirements, test 

reports shall be submitted to the Department no later than 30 days after 

completion of the test.

B112

A. The Department shall be given the right to enter the facility at all reasonable times to 

verify the terms and conditions of this permit. Required records shall be organized 

by date and subject matter and shall at all times be readily available for 

inspection. The permittee, upon verbal or written request from an authorized 

representative of the Department who appears at the facility, shall immediately 

produce for inspection or copying any records required to be maintained at the 

facility. Upon written request at other times, the permittee shall deliver to the 

Department paper or electronic copies of any and all required records maintained on 

site or at an off-site location. Requested records shall be copied and delivered at the 

permittee’s expense within three business days from receipt of request unless the 

Department allows additional time. Required records may include records required 

by permit and other information necessary to demonstrate compliance with terms and 

conditions of this permit. (NMSA 1978, Section 74-2-13)

Compliance

B. A copy of the most recent permit(s) issued by the Department shall be kept at the 

permitted facility or (for unmanned sites) at the nearest company office and shall be 

made available to Department personnel for inspection upon request.

(20.2.72.210.B.4 NMAC)

C. Emissions limits associated with the energy input of a Unit, i.e. lb/MMBtu, shall 

apply at all times unless stated otherwise in a Specific Condition of this permit. The 

averaging time for each emissions limit, including those based on energy input of a 

Unit (i.e. lb/MMBtu) is one (1) hour unless stated otherwise in a Specific Condition

of this permit or in the applicable requirement that establishes the limit. 

B113

A. The Department may revoke this permit if the applicant or permittee has knowingly 

and willfully misrepresented a material fact in the application for the permit. 

Revocation will be made in writing, and an administrative appeal may be taken to the 

Secretary of the Department within thirty (30) days. Appeals will be handled in 

accordance with the Department's Rules Governing Appeals From Compliance 

Orders.

Permit Cancellation and Revocation

B. The Department shall automatically cancel any permit for any source which ceases 

operation for five (5) years or more, or permanently. Reactivation of any source after 

the five (5) year period shall require a new permit. (20.2.72 NMAC)
NSR Permit No. 0063M8 Page 47 of 54

C. The Department may cancel a permit if the construction or modification is not 

commenced within two (2) years from the date of issuance or if, during the 

construction or modification, work is suspended for a total of one (1) year. (20.2.72 

NMAC)

B114

A. The permit and conditions apply in the event of any change in control or ownership 

of the Facility. No permit modification is required in such case. However, in the 

event of any such change in control or ownership, the permittee shall notify the 

succeeding owner of the permit and conditions and shall notify the Department’s 

Program Manager, Permits Section of the change in ownership within fifteen (15) 

days of that change. (20.2.72.212.C NMAC)

Notification to Subsequent Owners

B. Any new owner or operator shall notify the Department’s Program Manager, Permits 

Section, within thirty (30) days of assuming ownership, of the new owner’s or 

operator’s name and address. (20.2.73.200.E.3 NMAC)

B115

A. Before any asbestos demolition or renovation work, the permittee shall determine 

whether 40 CFR 61 Subpart M, National Emissions Standards for Asbestos applies. 

If required, the permittee shall notify the Department’s Program Manager, 

Compliance and Enforcement Section using forms furnished by the Department.

Asbestos Demolition

B116

A. The following Alternative Operating Scenario (AOS) addresses engine breakdown or 

periodic maintenance and repair, which requires the use of a short term replacement 

engine. The following requirements do not apply to engines that are exempt per 

20.2.72.202.B(3) NMAC. Changes to exempt engines must be reported in 

accordance with 20.2.72.202.B NMAC. A short term replacement engine may be 

substituted for any engine allowed by this permit for no more than 120 days in any 

rolling twelve month period per permitted engine. The compliance demonstrations 

required as part of this AOS are in addition to any other compliance demonstrations 

required by this permit.

Short Term Engine Replacement

(1) The permittee may temporarily replace an existing engine that is subject to the 

emission limits set forth in this permit with another engine regardless of 

manufacturer, model, and horsepower without modifying this permit. The 

permittee shall submit written notification to the Department within 15 days of the 

date of engine substitution according to condition B110.C(1).
NSR Permit No. 0063M8 Page 48 of 54

(a) The potential emission rates of the replacement engine shall be determined 

using the replacement engine’s manufacturer specifications and shall 

comply with the existing engine’s permitted emission limits.

(b) The direction of the exhaust stack for the replacement engine shall be 

either vertical or the same direction as for the existing engine. The 

replacement engine’s stack height and flow parameters shall be at least as 

effective in the dispersion of air pollutants as the modeled stack height and 

flow parameters for the existing permitted engine. The following equation 

may be used to show that the replacement engine disperses pollutants as 

well as the existing engine. The value calculated for the replacement 

engine on the right side of the equation shall be equal to or greater than the 

value for the existing engine on the left side of the equation. The 

permitting page of the Air Quality Bureau website contains a spreadsheet 

that performs this calculation.
NSR Permit No. 0063M8 Page 49 of 54

EXISTING ENGINE REPLACMENT ENGINE

[(g) x (h1)] + [(v1)2/2] + [(c) x (T1)] <= 

q1 q2

[(g) x (h2)] + [(v2)2/2] + [(c) x (T2)]

Where

g = gravitational constant = 32.2 ft/sec2

h1 = existing stack height, feet

v1 = exhaust velocity, existing engine, feet per second

c = specific heat of exhaust, 0.28 BTU/lb-degree F

T1 = absolute temperature of exhaust, existing engine = degree F + 460

q1 = permitted allowable emission rate, existing engine, lbs/hour

h2 = replacement stack height, feet

v2 = exhaust velocity, replacement engine, feet per second

T2 = absolute temperature of exhaust, replacement engine = degree F + 460

q2 = manufacturer’s potential emission rate, replacement engine, lbs/hour

The permittee shall keep records showing that the replacement engine is at least 

as effective in the dispersion of air pollutants as the existing engine.

(c) Test measurement of NOx and CO emissions from the temporary 

replacement engine shall be performed in accordance with Section B111 

with the exception of Condition B111A(3) and B111B for EPA Reference 

Methods Tests or SectionB111C for portable analyzer test measurements. 

Compliance test(s) shall be conducted within fifteen (15) days after the 

unit begins operation, and records of the results shall be kept according to 

section B109.B. This test shall be performed even if the engine is 

removed prior to 15 days on site.

i. These compliance tests are not required for an engine certified 

under 40CFR60, subparts IIII, or JJJJ, or 40CFR63, subpart ZZZZ 

if the permittee demonstrates that one of these requirements causes 

such engine to comply with all emission limits of this permit. The 

permittee shall submit this demonstration to the Department within 

48 hours of placing the new unit into operation. This submittal 

shall include documentation that the engine is certified, that the 

engine is within its useful life, as defined and specified in the 

applicable requirement, and shall include calculations showing that 

the applicable emissions standards result in compliance with the 

permit limits.

ii. These compliance tests are not required if a test was conducted by 

portable analyzer or by EPA Method test (including any required 

by 40CFR60, subparts IIII and JJJJ and 40CFR63, subpart ZZZZ) 

within the last 12 months. These previous tests are valid only if 
NSR Permit No. 0063M8 Page 50 of 54

conducted at the same or lower elevation as the existing engine 

location prior to commencing operation as a temporary 

replacement. A copy of the test results shall be kept according to 

section B109.B.

(d) Compliance tests for NOx and CO shall be conducted if requested by the 

Department in writing to determine whether the replacement engine is in 

compliance with applicable regulations or permit conditions.

(e) Upon determining that emissions data developed according to B116.A.1(c) 

fail to indicate compliance with either the NOx or CO emission limits, the 

permittee shall notify the Department within 48 hours. Also within that 

time, the permittee shall implement one of the following corrective 

actions:

i. The engine shall be adjusted to reduce NOx and CO emissions and 

tested per B116.A.1(c) to demonstrate compliance with permit 

limits. 

ii. The engine shall discontinue operation or be replaced with a 

different unit. 

(2) Short term replacement engines, whether of the same manufacturer, model, and 

horsepower, or of a different manufacturer, model, or horsepower, are subject to 

all federal and state applicable requirements, regardless of whether they are set 

forth in this permit (including monitoring and recordkeeping), and shall be subject 

to any shield afforded by this permit.

(3) The permittee shall maintain a contemporaneous record documenting the unit 

number, manufacturer, model number, horsepower, emission factors, emission 

test results, and serial number of any existing engine that is replaced, and the 

replacement engine. Additionally, the record shall document the replacement 

duration in days, and the beginning and end dates of the short term engine 

replacement. 

(4) The permittee shall maintain records of a regulatory applicability determination 

for each replacement engine (including 40CFR60, subparts IIII and JJJJ and 

40CFR63, subpart ZZZZ) and shall comply with all associated regulatory 

requirements. 

B. Additional requirements for replacement of engines at sources that are major as 

defined in regulation 20.2.74 NMAC, Permits – Prevention of Significant 

Deterioration

(1) Daily, the actual emissions from the replacement engine of each pollutant 

regulated by this permit for the existing engine shall be calculated and recorded. 

, section 7.AF. For sources that are major under PSD, the total 

cumulative operating hours of the replacement engine shall be limited using the 

following procedure:
NSR Permit No. 0063M8 Page 51 of 54

(2) The sum of the total actual emissions since the commencement of operation of the 

replacement engine shall not exceed the significant emission rates in Table 2 of 

20.2.74 NMAC, section 502 for the time that the replacement engine is located at 

the facility.

C. All records required by this section shall be kept according to section B109.

PART C

C100

MISCELLANEOUS

A. Copies of the following documents can be downloaded from NMED’s web site under 

Compliance and Enforcement or requested from the Bureau.

Supporting On-Line Documents

(1) Excess Emission Form (for reporting deviations and emergencies)

(2) Universal Stack Test Notification, Protocol and Report Form and Instructions 

(3) SOP for Use of Portable Analyzers in Performance Tests 

C101

A. “Daylight” is defined as the time period between sunrise and sunset, as defined by 

the Astronomical Applications Department of the U.S. Naval Observatory. (Data for 

one day or a table of sunrise/sunset for an entire year can be obtained at 

Definitions

http://aa.usno.navy.mil/. Alternatively, these times can be obtained from a Farmer’s 

Almanac or from http://www.almanac.com/rise/).

B. “Exempt Sources” and “Exempt Activities” is defined as those sources or activities 

that are exempted in accordance with 20.2.72.202 NMAC. Note; exemptions are 

only valid for most 20.2.72 NMAC permitting actions. 

C. “Fugitive Emission” means those emissions which could not reasonably pass 

through a stack, chimney, vent, or other functionally equivalent opening.

D. “Insignificant Activities” means those activities which have been listed by the 

department and approved by the administrator as insignificant on the basis of size, 

emissions or production rate. Note; insignificant activities are only valid for 20.2.70 

NMAC permitting actions.

E. “Natural Gas” is defined as a naturally occurring fluid mixture of hydrocarbons that 

contains 20.0 grains or less of total sulfur per 100 standard cubic feet (SCF) and is 

either composed of at least 70% methane by volume or has a gross calorific value of 

between 950 and 1100 Btu per standard cubic foot. (40 CFR 60.631)
NSR Permit No. 0063M8 Page 52 of 54

F. “Natural Gas Liquids” means the hydrocarbons, such as ethane, propane, butane, 

and pentane, that are extracted from field gas. (40 CFR 60.631)

G. “National Ambient air Quality Standards” means, unless otherwise modified, the 

primary (health-related) and secondary (welfare-based) federal ambient air quality 

standards promulgated by the US EPA pursuant to Section 109 of the Federal Act. 

H. “Night” is the time period between sunset and sunrise, as defined by the 

Astronomical Applications Department of the U.S. Naval Observatory. (Data for one 

day or a table of sunrise/sunset for an entire year can be obtained at 

http://aa.usno.navy.mil/. Alternatively, these times can be obtained from a Farmer’s 

Almanac or from http://www.almanac.com/rise/).

I. “Night Operation or Operation at Night” is operating a source of emissions at 

night.

J. “NO2” or "Nitrogen dioxide" means the chemical compound containing one atom of 

nitrogen and two atoms of oxygen, for the purposes of ambient determinations. The 

term "nitrogen dioxide," for the purposes of stack emissions monitoring, shall 

include nitrogen dioxide (the chemical compound containing one atom of nitrogen 

and two atoms of oxygen), nitric oxide (the chemical compound containing one atom 

of nitrogen and one atom of oxygen), and other oxides of nitrogen which may test as 

nitrogen dioxide and is sometimes referred to as NOx or NOx. (20.2.2 NMAC)

K. “NOx” see NO2

L. “Potential Emission Rate” means the emission rate of a source at its maximum 

capacity to emit a regulated air contaminant under its physical and operational 

design, provided any physical or operational limitation on the capacity of the source 

to emit a regulated air contaminant, including air pollution control equipment and 

restrictions on hours of operation or on the type or amount of material combusted, 

stored or processed, shall be treated as part of its physical and operational design 

only if the limitation or the effect it would have on emissions is enforceable by the 

department pursuant to the Air Quality Control Act or the federal Act.

M. “Restricted Area” is an area to which public entry is effectively precluded. Effective 

barriers include continuous fencing, continuous walls, or other continuous barriers 

approved by the Department, such as rugged physical terrain with a steep grade that 

would require special equipment to traverse. If a large property is completely 

enclosed by fencing, a restricted area within the property may be identified with 

signage only. Public roads cannot be part of a Restricted Area.

N. "Shutdown", for requirements under 20.2.72 NMAC, means the cessation of 

operation of any air pollution control equipment, process equipment or process for 

any purpose, except routine phasing out of batch process units. 
NSR Permit No. 0063M8 Page 53 of 54

O. "SSM", for requirements under 20.2.7 NMAC, means routine or predictable startup, 

shutdown, or scheduled maintenance.

(1) "Shutdown", for requirements under 20.2.7 NMAC, means the cessation of 

operation of any air pollution control equipment or process equipment. 

(2) "Startup", for requirements under 20.2.7 NMAC, means the setting into 

operation of any air pollution control equipment or process equipment.

P. "Startup" , for requirements under 20.2.72 NMAC, means the setting into operation 

of any air pollution control equipment, process equipment or process for any 

purpose, except routine phasing in of batch process units.

C102 Acronyms

2SLB ........................................................................................................ 2-stroke lean burn

4SLB ........................................................................................................ 4-stroke lean burn

4SRB.........................................................................................................4-stroke rich burn

acfm........................................................................................... actual cubic feet per minute

AFR....................................................................................................................air fuel ratio

AP-42 ...........................................................................EPA Air Pollutant Emission Factors

AQB........................................................................................................Air Quality Bureau

AQCR ....................................................................................... Air Quality Control Region

ASTM ............................................................. American Society for Testing and Materials

BTU......................................................................................................British Thermal Unit

CAA.............................................................Clean Air Act of 1970 and 1990 Amendments

CEM................................................................................. continuous emissions monitoring

cfh ........................................................................................................... cubic feet per hour

cfm .......................................................................................................cubic feet per minute

CFR........................................................................................... Code of Federal Regulation

CI ........................................................................................................compression ignition

CO............................................................................................................ carbon monoxides

COMS ...................................................................... continuous opacity monitoring system

EIB............................................................................... Environmental Improvement Board

EPA.......................................................... United States Environmental Protection Agency

gr./100 cf.......................................................................... grains per one hundred cubic feet

gr./dscf .............................................................................grains per dry standard cubic foot

GRI.....................................................................................................Gas Research Institute

HAP...................................................................................................hazardous air pollutant

hp .......................................................................................................................horsepower

H2S..............................................................................................................hydrogen sulfide

IC ..........................................................................................................internal combustion

KW/hr ...................................................................................................... kilowatts per hour

lb/hr..............................................................................................................pounds per hour

lb/MMBtu .............................................................pounds per million British Thermal Unit
NSR Permit No. 0063M8 Page 54 of 54

MACT ............................................................. Maximum Achievable Control Technology

MMcf/hr......................................................................................million cubic feet per hour

MMscf.........................................................................................million standard cubic feet

N/A..................................................................................................................not applicable

NAAQS.................................................................National Ambient Air Quality Standards 

NESHAP .................................National Emission Standards for Hazardous Air Pollutants

NG ....................................................................................................................... natural gas

NGL ......................................................................................................... natural gas liquids

NMAAQS ......................................................New Mexico Ambient Air Quality Standards

NMAC............................................................................ New Mexico Administrative Code

NMED.....................................................................New Mexico Environment Department

NMSA.................................................................................New Mexico Statues Annotated

NOx...............................................................................................................nitrogen oxides 

NSCR.................................................................................non-selective catalytic reduction

NSPS............................................................................. New Source Performance Standard

NSR.......................................................................................................New Source Review

PEM ..................................................................................parametric emissions monitoring

PM................................ particulate matter (equivalent to TSP, total suspended particulate)

PM10 .......................................................particulate matter 10 microns and less in diameter

PM2.5 .....................................................particulate matter 2.5 microns and less in diameter

pph................................................................................................................pounds per hour

ppmv ......................................................................................... parts per million by volume

PSD .........................................................................Prevention of Significant Deterioration

RATA...........................................................................Relative Accuracy Test Assessment

RICE ....................................................................reciprocating internal combustion engine

rpm.................................................................................................... revolutions per minute

scfm.......................................................................................standard cubic feet per minute

SI ................................................................................................................... spark ignition

SO2 ..................................................................................................................sulfur dioxide

SSM...................................................Startup Shutdown Maintenance (see SSM definition)

TAP........................................................................................................ Toxic Air Pollutant

TBD.............................................................................................................to be determined

THC..........................................................................................................total hydrocarbons

TSP..........................................................................................Total Suspended Particulates

tpy .....................................................................................................................tons per year

ULSD ..................................................................................................ultra low sulfur diesel

USEPA..................................................... United States Environmental Protection Agency

UTM......................................................Universal Transverse Mercator Coordinate system

UTMH................................................................Universal Transverse Mercator Horizontal

UTMV....................................................................Universal Transverse Mercator Vertical

VHAP...................................................................................volatile hazardous air pollutant

VOC.......................................................................................... volatile organic compounds
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Appendix C C-1

Appendix C. Sargent & Lundy Design, Process Description, 

and Cost Estimates
PUBLIC SERVICE OF NEW MEXICO

SAN JUAN GENERATING STATION UNITS 1, 2, 3, & 4

SNCR AND SCR COST ESTIMATES

Final Report

March 29, 2013

Project 11278-034

Prepared by:

55 East Monroe Street 

Chicago, IL 60603 
LEGAL NOTICE 

This Deliverable was prepared by Sargent & Lundy, L.L.C. (S&L), at the request of and expressly for the sole use of 

Public Service of New Mexico (Client) in accordance with the agreement between S&L and Client. This Deliverable was 

prepared using the degree of skill and care ordinarily exercised by engineers practicing under similar circumstances. Client 

acknowledges: (1) S&L prepared this Deliverable subject to the particular scope limitations, budgetary and time 

constraints, and business objectives of the Client; (2) information and data provided by others may not have been 

independently verified by S&L; and (3) the information and data contained in this Deliverable are time sensitive and 

changes in the data, applicable codes, standards, and acceptable engineering practices may invalidate the findings of this 

Deliverable. 
Project No. 11278-034 

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SNCR AND SCR COST ESTIMATES i

Table of Contents 

1. INTRODUCTION AND BACKGROUND ......................................................................................................1

2. BART COST ESTIMATING .....................................................................................................................2

3. S&L’S CONTROL TECHNOLOGY COST ESTIMATES .............................................................................4

3.1 EMISSION UNITS AND CONTROL SYSTEM DESIGN PARAMETERS ............................................................... 4

3.2 SCR COST ESTIMATE METHODOLOGY & ASSUMPTIONS ........................................................................... 6

3.2.1 Factors Affecting the Design: .................................................................................................................. 6

3.2.2 Project-Specific SCR Design Criteria and Assumptions.......................................................................... 9

3.3 SNCR COST ESTIMATE METHODOLOGY.................................................................................................... 11

3.3.1 Factors Affecting the SNCR Design ...................................................................................................... 12

3.3.2 Project-Specific SNCR Design Criteria and Assumptions..................................................................... 13

3.4 PLANT ECONOMIC ASSUMPTIONS ............................................................................................................... 15

3.5 OPERATING & MAINTENANCE COST ASSUMPTION.................................................................................... 17

3.6 COST ESTIMATES .......................................................................................................................................... 18

3.6.1 SNCR Cost Estimates............................................................................................................................. 19

3.6.2 SCR Cost Estimates ............................................................................................................................... 19

4. SUMMARY.............................................................................................................................................21

Attachment A. SJGS Units 1 – 4 SNCR Cost Estimates 

Attachment B. SJGS Units 1 & 2 SCR Cost Estimates 

Attachment C. SJGS Units 3 & 4 SCR Cost Estimates 
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1. INTRODUCTION AND BACKGROUND 

On February 15, 2013, PNM entered into a Term Sheet agreement with the U.S. Environmental Protection 

Agency (EPA) and the State of New Mexico. Provisions specified in the Term Sheet reflect “a tentative 

agreement on technical terms and an appended corresponding timeline for action intended to address pollution 

control requirements for the San Juan Generating Station under the Clean Air Act’s requirements for regional 

haze and interstate transport for visibility.” Among other requirements, the agreement requires PNM to submit a 

new Best Available Retrofit Technology (BART) analysis to the New Mexico Environment Department 

(NMED). The Term Sheet requires PNM to prepare a “five-factor BART analysis in accordance with the BART 

Guidelines, and other EPA guidance, as applicable, including documentation relied upon in making the BART 

determination.” 

EPA published guidelines for conducting a BART determination on July 6, 2005 (40 CFR Part 51 Appendix Y, 

70 Fed. Reg. 39156). The five basic steps of a BART analysis are: 

1. Identify All Available Retrofit Control Technologies. 

2. Eliminate Technically Infeasible Options. 

3. Evaluate Control Effectiveness of Remaining Control Technologies. 

4. Evaluate Impacts and Document Results. 

5. Evaluate Visibility Impacts. 

Step 4 of the five-factor BART analysis includes an evaluation of the compliance costs associated with each 

technically feasible and available control technology. The BART Guidance includes the following three-step 

approach to developing an equipment cost estimate: (1) identify the emissions units being controlled; (2) identify 

design parameters for emission controls; and (3) develop cost estimates based on these design parameters.1

 The 

guidance document instructs that the basis for equipment cost estimates should be documented, either with data 

supplied by an equipment vendor or by a referenced source such as EPA’s OAQPS Control Cost Manual.2

 The 

cost analysis should take into account any site-specific design or other conditions that affect the cost of a 

particular control technology, provided that the cost estimate includes documentation of any additional 

 

1

 See, 70 FR 39166, col. 2. 

2

 OAQPS Control Cost Manual, Fifth Edition, February 1996, EPA 453/B-96-001. 
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information that was used for the cost calculations that affects assumptions regarding purchased equipment costs, 

equipment life, replacement of major components, and any other element of the calculation that differs from the 

Control Cost Manual.3

 As part of its agreement to prepare a BART analysis for the San Juan Generating Station (SJGS), PNM 

contracted S&L to update previously prepared conceptual cost estimates for both selective catalytic reduction 

(SCR) and selective non-catalytic reduction (SNCR) control systems. In 2011, S&L prepared a conceptual 

design, cost estimate, and Engineer, Procurement & Construction (EPC) specification to install SCR on all four 

units; and in September 2012, S&L developed a scoping-level cost estimates for SNCR. Based on PNM’s 

request, S&L updated these costs estimates to reflect the approach described in EPA’s Control Cost Manual. 

Cost estimates were prepared for the following control technology options: 

Option 1: Installing selective catalytic reduction (SCR) control on all four units; 

Option 2: Installing selective non-catalytic reduction (SNCR) control on all four units; and 

Option 3: Installing SNCR on Units 1 & 4 and retiring Units 2 & 3. 

This report provides a summary of the SCR and SNCR cost estimates prepared for SJGS, and includes an 

overview of the approach, design parameters, and assumptions used to develop the cost estimates. Cost estimates 

for each option, including capital costs, annual operating and maintenance (O&M) costs, and total annual costs 

are included in Attachments A, B, and C to the report, respectively. 

2. BART COST ESTIMATING 

The Appendix Y BART Guidelines describe the methodology that should be used to determine control system 

costs and to calculate control system cost effectiveness. The guidelines state that “[i]n order to maintain and 

improve consistency, cost estimates should be based on the Control Cost Manual, where possible.” The Control 

Cost Manual describes the equipment and other directs costs that are typically included in a cost estimate, and 

provides cost factors that can be used to calculate certain indirect costs, if needed. Specific chapters are provided 

for a number of add-on air pollution control systems, including both SNCR (Section 4.2 – NOx PostCombustion, Chapter 1) and SCR (Section 4.2, Chapter 2). 

 

3

 See, 70 FR 39166, col. 3, and footnote 15. 
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With respect to cost-effectiveness evaluations, the Control Cost Manual provides a methodology to calculate the 

Total Annual Cost (TAC) associated with the air pollution control system. TAC includes three elements, and is 

calculated using the following equation: 

TAC = DC + IC – RC (Cost Manual, equation 2-1, page 2-7) 

Where: 

DC = direct costs; 

IC = indirect costs; and 

RC = recovery credits 

Direct costs are those that tend to be directly proportional (variable costs) or partially proportional (semi-variable 

costs) to some measure of productivity (e.g., exhaust gas process by the control system per unit time). Direct 

costs include raw materials (reagents), utilities, waste treatment and disposal, maintenance materials, replacement 

parts, and operating, supervisory, and maintenance labor. Indirect, or “fixed”, annual costs are independent of 

the level of production, and would be incurred even if the control system were shut down. Indirect costs include 

the capital recovery costs, administrative charges, property taxes, and insurance. Recovery credits account for 

materials or energy recovered by the control system, which may be sold, recycled, or reused to offset the direct 

and indirect annual costs. 

Capital recovery can represent a significant portion of the annual indirect costs, especially on large, capital 

intensive air pollution control projects. Capital recovery is an annualized cost of capital calculated as an annual 

payment sufficient to finance total capital costs over the life of the investment. The annualized capital recovery 

cost is a function of the Total Capital Investment (TCI), operational life of the control technology, and an 

appropriate discount interest rate that reflects the financial structure of the applicants business.4

 

TCI includes all costs required to purchase equipment needed for the control system (purchased equipment cost), 

the costs of labor and materials for installing that equipment (direct installation costs), costs for site preparation 

and buildings, and certain other costs (indirect installation costs).5

 TCI also includes costs for working capital 

and off-site facilities.6

 Direct installation costs include costs for foundations and supports, erecting and handling 

the equipment, electrical work, piping, insulation, and painting. Indirect installation costs include costs such as 

engineering costs; construction and field expenses (i.e., cost for construction supervisory personnel, office 

 

4

 See, OAQPS Control Cost Manual, page 2-21. 

5 Id. at page 2-5. 

6 Id. 
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personnel, rental of temporary offices, etc.); contractor fees (for construction and engineering firms involved in 

the project); start-up and performance test costs (to get the control system running and to verify that it meets 

performance guarantees); and contingencies. 

The Control Cost Manual provides flexibility, and is not so proscriptive as to explicitly exclude from a cost 

estimate actual tangible costs that an applicant will incur as part of an air pollution control project. For example, 

the manual states that “the user has to be able to exercise ‘engineering judgment’ on those occasions when the 

procedures may need to be modified or disregarded;”7

 and that “the application of an appropriate [indirect capital 

cost] factor requires the subjective application of the analyst’s best judgment.”8

 In addition, the Control Costs 

Manual specifically states that for certain control systems (e.g., SCR reactors and FGD units) it deviates from its 

standard approach of providing study level costs and, instead, provides a description of the factors that influence 

TCI for the analyst to consider when dealing with a vendor quotation.9

 The Control Cost Manual takes this 

approach because “the control in question is either so large or so site-specific in design that suppliers design, 

fabricate, and construct each control according to the specific needs of the facility.”10

3. S&L’S CONTROL TECHNOLOGY COST ESTIMATES 

PNM contracted S&L to prepare the following three cost estimates for NOx control options at its San Juan 

Generation Station: (1) Selective Non-Catalytic Reduction (SNCR) control on SJGS Units 1, 2, 3, & 4; (2) 

SNCR control systems on SJGS Units 1 & 4 only; and (3) SCR control on all four units. 

3.1 Emission Units and Control System Design Parameters 

SJGS is located 15 miles west of Farmington, New Mexico, and is comprised of Units 1 and 2 (nominally 

370 MW each) and Units 3 and 4 (nominally 544 MW each). All four units fire western subbituminous coal 

produced at an adjacent mine. The steam generating units for Units 1 and 2 were manufactured by Foster 

Wheeler Corporation and the steam generating units for Units 3 and 4 were manufactured by The Babcock & 

Wilcox Company. All four steam turbine generators were originally manufactured by General Electric. All four 

units are designed with low-NOx burners and over-fired air systems to control NOx emissions, activated carbon 

injection for mercury control, pulse jet fabric filter baghouse control systems for particulate matter control, and 

 

7 Id., at page 1-7. 

8 Id., at page 2-28. 

9 Id., at page 2-27.

10 Id. 
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wet flue gas desulfurization (WFGD) for sulfur dioxide control. The units are also equipped with hot-side 

electrostatic precipitators (ESPs) that were de-energized upon installation of the baghouses. 

Design and operating parameters affecting the design of both SCR and SNCR control technologies include, but 

are not necessarily limited to boiler heat input, flue gas volumes and residence time, flue gas temperatures, 

uncontrolled NOx emissions, and the design target NOx emission rates. Operating parameters for the San Juan 

units were developed based on Process Information (PI) data available from the station, as well as experience 

from similar control technology projects. Design and operating parameters used as the basis of the SCR and 

SNCR cost estimates are summarized in Table 1. 

Table 1. SJGU Units 1, 2, 3, & 4 Design & Operating Parameters 

Plant Operating Data 

Variable Units Unit 1 Unit 2 Unit 3 Unit 4 Status* 

Gross Load MW 370 370 544 544 v 

Minimum Load MW 144 144 222 222 v 

Heat Input mmBtu/hr 3,707 3,688 5,758 5,649 v 

O2 at Economizer 

Outlet 

%vol (set) 3.36 2.67 3.00 2.78 v 

Air H2O lb/lb dry air 0.013 0.013 0.013 0.013 ej 

Ash-Boiler wt% 20 20 20 20 ej 

Ambient Pressure psia 12.08 12.08 12.08 12.08 v 

Ambient Temp oF 70 70 70 70 v 

Economizer Outlet 

Pressure 

in. w.c. +11.7 +11.4 +6.9 +7.3 v 

Boiler SO2 to SO3

oxidation 

wt% SO2 0.8 0.8 0.8 0.8 ej 

Control System Design Parameters 

SCR SO2 to SO3

Oxidation 

wt% SO2 0.5 0.5 0.5 0.5 design 

Economizer Outlet 

Temperature 

o

F 658 ± 15 670 ± 20 670 ± 20 680 ± 15 v 

Minimum Load 

Temperature 

o

F 500 475 450 450 ej 

Inlet Ash Loading lb/mmBtu 18.34 18.34 18.34 18.34 v 

Maximum Inlet NOx lb/mmBtu 0.40 0.40 0.40 0.40 design 

Average Inlet NOx lb/mmBtu 0.30 0.30 0.30 0.30 design 

NOx Emission Limit 

(SCR) 

lb/mmBtu 0.05 0.05 0.05 0.05 v 

SCR Pressure Drop in. w.c. -8.0 to -11.0 -8.0 to -11.0 -8.0 to -11.0 -8.0 to -11.0 design 

NH3 Slip (SCR) ppmvd @3% O2 2 2 2 2 design 

NOx Emission Limit 

(SNCR) 

lb/mmBtu 0.23 0.23 0.23 0.23 design 

NH3 Slip (SNCR) ppmvd @3% O2 10 10 10 10 design 
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* v = verified; uv = unverified; ej = engineering judgment; design = design criteria 

3.2 SCR Cost Estimate Methodology & Assumptions 

In 2011, PNM contracted S&L to prepare a conceptual design, project cost estimate, and technical portions of an 

Engineer, Procurement, and Construction (EPC) specification as a preliminary step towards awarding a contract 

to install SCR control systems on SJGS Units 1, 2, 3, & 4. The SCR cost estimate was based on equipment cost 

estimates provided by equipment vendors for the major components of the SCR control system (e.g., SCR 

reaction vessel, SCR catalyst, ammonia handling system, etc.), and unit-specific balance-of-plant costs (e.g., 

economizer bypass modification, ash handling modification, tie-ins, duct work, fan modifications, foundations, 

structural steel, etc.). The following initial tasks were performed to establish the SCR control system design 

parameters and to prepare the documents to support a construction request for proposals: 

 Review and analyze the operating conditions at SJGS including air flow, temperature data, fuel data, 

pressure drop across the SCR, ash flow and handling, fan capacity, and alternative reagents. 

 Review ductwork and/or boiler stiffening required to withstand the new operating conditions required for 

compliance with NFPA-85, air heater modifications, and modifications necessary after the SCR addition. 

 Evaluate the existing auxiliary electric system to determine what modifications are required to 

accommodate the addition of SCRs and the sorbent injection system. 

 Develop General Arrangement (GA) drawings for the SCRs, new ductwork, and the other additional 

equipment required to safely and reliably integrate the SCRs into the plant’s operation. 

 Estimate the quantities of materials (e.g., steel, concrete, piping, ductwork, etc.) needed for SCR 

installation based on the GA drawings. 

 Obtain budgetary equipment cost quotes from manufacturers of the major system components. 

3.2.1 Factors Affecting the Design: 

Several site-specific factors affect the conceptual design of the SJGS SCR control systems. Design 

considerations affecting the SCR cost estimates include the congested existing plant configuration, the high ash 

content of the coal-fired, NOx reduction requirements, and the existing and anticipated permit limits for other 

regulated air pollutants. Some of the more significant factors affecting the design of the SCR control systems are 

described in more detail below. 

Site Congestion: SJGS is a congested site. One site congestion issue that affects SCR design and 

construction is that SJGS has de-energized “hot-side” ESPs that are located ahead of the air preheater in the 

flue gas path. Most coal-fired power plants have “cold-side” ESPs that are located downstream of the air 

preheater. Because the ESPs for the SJGS are located in front of the air heaters, they are in the middle of the 
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boiler outlet duct area. Because the stacks are also located adjacent to the air heaters, the area in which SCRs 

may be installed is severely restricted. 

The conceptual design study prepared for the SCR control systems concluded that, given the space 

constraints, the best location for the SCRs will be above the existing air heaters. Building SCRs in this 

location will require installation of ducts to convey the full gas path above the existing ESPs. The bottom 

ducts of the SCRs will be 120 feet above ground level, requiring more structural support than would be 

required if they were located closer to the ground. The congestion also limits the options for structural steel 

column placements to support the new SCR reactors and ductwork, contributing to a less efficient steel 

arrangement and increasing the complexity of the design compared to a more open installation. 

Another manifestation of the congested site is that all four units are constructed side by side in a row. This 

leaves two units (Unit 2 and Unit 3) on the interior of the row. There is very little space between the units. 

This tight configuration creates constructability issues because it limits crane placement and the type of 

structural foundations that can be added to support the weight of the SCR. Crane placement is important 

because of the need to build the ductwork over the existing ESPs, which means lifts spanning above the two 

outside units to reach the two interior units will be required, where there is also limited room to assemble and 

disassemble the cranes. The long spans and limited placement choices limit the crane selection choices to the 

larger, more expensive cranes. 

The tight site configuration also dictates that a more expensive type of deep structural foundations be used. 

The very low overhead clearances and tight quarters adjacent to the existing stacks, particularly south of the 

Unit 1 stack where the adjacent fabric filter restricts access to the area and also south of the Unit 2 stack 

where existing ash piping, would hamper access during construction and leads to the choice of micropiles for 

support of the new SCRs and ductwork. This construction option is a special type of pile that requires 

special installation equipment and expertise. The installed cost of this type of pile by a specialty contractor 

will be high compared to other deep foundation installations, at least double the cost of conventional drilled 

or driven piles. The cost of structural foundations also increases due to the height of the SCR above ground 

level, as discussed earlier for the structural steel support structure. 

Controlled NOx Emission Limit: Based on the August 22, 2011 Regional Haze Federal Implementation Plan 

(the “Regional Haze FIP”),11 the SJGS SCRs would be required to achieve an enforceable NOx emission 

 

11 See, 76 Fed. Reg. 52388 
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limit of 0.05 lb/mmBtu. Thus, the SCRs must be designed to achieve a controlled NOx emission rate of less 

than 0.05 lb/mmBtu under most operating scenarios to provide compliance margin during those periods of 

time when NOx emissions may exceed the limit (e.g., startup, shutdown, and malfunction). To achieve 

controlled NOx emissions of less than 0.05 lb/mmBtu, the conceptual design study determined that the SJGS 

SCRs should be designed to hold four layers of catalyst. Three layers will be installed initially, with the 

fourth layer being added after approximately two years of operation. Once the fourth layer has been added to 

the SCR, one layer of catalyst would be replaced every two years. The four-layer catalyst design 

requirement affects SCR costs by: 

 Fan upgrades will be required to accommodate the additional pressure drop across the SCRs; 

 Four layers of catalyst results in a larger SCR reaction box and additional weight that must be 

supported by the structural steel; 

 Increased ammonia consumption will be required to achieve the lower NOx emission rate, which 

affects the cost of the ammonia handling system, ammonia storage, and delivery to the SCR; and 

 Increased construction costs in terms of initial catalyst procurement. 

Sulfuric Acid Mist Emission Limit: SJGS is required by the Regional Haze FIP to meet a sulfuric acid mist 

(SAM) emission limit of 2.6 x 10-4 lb/mmBtu (or approximately 0.10 ppmvd @ 3% O2). SCR controls result 

in increased SO2 to SO3 oxidation. SO3 formed across the SCR catalyst can react with water in the flue gas 

to form SAM, increasing SAM loading to downstream equipment. In order to meet the SAM emission limit, 

the conceptual design study specified an ultra-low conversion catalyst to minimize SO3 formation across the 

SCR. Ultra-low conversion catalyst will increase the size of the SCR reactor box and increase the weight of 

the SCR. Based on vendor input from recent SCR installations, it is unlikely that PNM will be able to obtain 

a guaranteed SAM emission limit of 2.6 x 10-4 lb/mmBtu from any of the SCR contractors. Therefore, the 

conceptual design study specified installation of dry sorbent injection (DSI) for SO3 control. Installation of 

the SCR control systems significantly increases the need for DSI control, and it is very unlikely that the units 

will meet the SAM emission limit without DSI control. 

Fugitive Emissions Control and Balanced Draft Conversion: As part of the SCR design review process, 

PNM verified that the SJGS may be required to reduce existing fugitive emissions at the plant. Most of the 

fugitive emissions result from the boilers’ pressurized design. Internal boiler and ductwork pressures push 

fine ash particles out through any small openings in the existing ductwork. Converting the plant to a 

balanced draft operation, which means internal pressures in the boiler and ductwork will be close to 

atmospheric pressure, will minimize or eliminate these fugitive emissions. Because of the potential need to 

address fugitive emissions, ancillary equipment costs (including fan sizing, boiler and ductwork stiffening 
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requirements, auxiliary power requirements, and electrical system upgrades) were developed to address both 

the pressure drop through the SCR and balanced draft conversion. Because of the significant pressure drop 

across the SCR, new fans will be required on all four SJGS units regardless of whether the units are 

converted to balanced draft. Balanced draft conversion would incrementally add to the size (and cost) of the 

new fans and electrical system upgrades, and would require additional boiler and ductwork stiffening. Based 

on an evaluation of fan sizing needed for the SCR project alone, these costs were split between the two 

projects by assigning 80% of the costs to the SCR and 20% to the additional needed for balance draft 

conversion. 

3.2.2 Project-Specific SCR Design Criteria and Assumptions 

Based on a site-specific review of the NOx reduction requirements and retrofit challenges associated with the 

installation of SCR control systems at SJGS, the following project-specific issues were taken into consideration 

in the development of the SCR cost estimates: 

 SCR Location. The proposed SCR reactors are located above the existing air heaters. The ductwork 

from the economizer outlet to the air heater inlet will be replaced. The existing electrostatic precipitators 

will be abandoned in place. Galleries will be provided at each catalyst level, at the ammonia injection 

grid level, and at the ash handling levels to allow for maintenance and inspection of the SCR system. 

 SCR Reactors. The conceptual design calls for a single reactor per unit for Units 1 and 2 and two 

reactors per unit for Units 3 and 4. Each reactor will have slots for four layers of catalyst (three layers 

plus a spare) and will use anhydrous ammonia as the reagent. 

 Economizer Bypass. Based on SJGS coal parameters, an economizer outlet temperature of at least 580 

°F is required for proper operation of the SCR. If flue gas flowing through the SCR is less than 580 °F, 

ammonia cannot be injected into the SCR and catalyst reactivity will be reduced. For periods of 

operation when the economizer outlet temperature is less than 580 °F, a means to increase the outlet 

temperature must be included in the SCR design. A water-side bypass in the economizer has been used 

on other recent SCR installation projects to increase the economizer outlet temperature, and a similar 

low-load temperature control system is needed on the SJGS units to allow low-load operation and unit 

cycling. Thus, economizer bypass costs were included in the cost estimate for the SJGS SCRs. 

 Demolition of the Existing Hot-Side ESPs. Demolition of the existing hot-side precipitators is needed to 

fit the retrofit SCR control systems into the available space. The configuration of the SCR control 

system requires that it be placed above the existing air heater. Due to the height of the ductwork leading 

to the air heater, the top of the SCR, as designed, is already approaching the top of the boiler building. If 

this height is exceeded, impacts on the existing chimney and plume dispersion would need to be 

evaluated. As designed, the bottom of the inlet duct to the SCR runs at the same elevation as the top hotside precipitator, necessitating removal of the existing precipitator. Reusing the existing ductwork was 

evaluated and found not to be acceptable due to the increase in flue gas velocity. We also evaluated 
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using the top hot-side precipitator as a duct, but again the degradation of the equipment and flue gas 

velocities would not support the design. 

 Catalyst Layers. To achieve the required NOx emission reductions on a consistent basis with ultra-low 

SO2 to SO3 conversion catalyst, three layers of catalyst, rather than the two layers specified for other 

similar projects, will be required for the SJGS SCRs. The SJGS SCRs would be designed to hold four 

layers of catalyst, with three layers being loaded initially. The additional layer of catalyst is needed to 

meet an enforceable NOx emission limit of 0.05 lb/mmBtu, which could not be met with two layers. The 

fourth layer of catalyst would be added to the SCR after approximately two years of operation. 

Furthermore, the ash content of the coal used at SJGS results in increased costs for the catalyst, as well 

as increased complexity and costs of the ash handling systems. 

 Air Heater Modifications. Based on the temperatures expected for the SCR operation, it can be expected 

that the ammonia and the sulfur trioxide will react to form ammonium bisulfate in the intermediate 

section of the air heater. However, based on operating experience with low sulfur fuel containing 

calcium oxide, air heater plugging and corrosion is not expected on these units. Therefore, no costs were 

included for air heater modifications. 

 Economizer Ash Handling System. The existing economizer ash handling system was taken out of 

service, and the top of the ash hoppers has been covered with a metal plate. To remove large particles of 

ash prior to the SCR, this abandoned system needs to be removed and a new system installed. The new 

system would consist of a dry ash chain conveyor that collects the economizer ash in a storage tank and 

uses the bottom ash system to sluice the ash to the existing dewatering bins. Installing this system also 

requires the demolition of the existing gas recirculation fans to make room for the ash collection tanks. 

 Baghouse Ash Handling System. Baghouse control systems have been installed on all four units at 

SJGS. The ash handling system installed with the baghouses were designed to collect only a portion of 

the fly ash because up to 50% of the particulates fall out in the existing ESPs. Removing the existing 

ESPs, which is needed to install the SCR control systems, will increase particulate loading to the 

baghouses, and increase the quantity of ash handled by the baghouse ash handling system. This requires 

expanding the baghouse ash handling system to accommodate the additional ash flow. 

 Sootblowers on SCR. The method of cleaning the fly ash that settles on the catalyst is extremely 

important to obtain the guaranteed life of the catalyst. For this reason, the use of steam sootblowers, in 

addition to sonic horns, is recommended for the SJGS units. Steam sootblowers will remove fly ash that 

settles on the catalyst and the sonic horns will keep the fly ash moving through the catalyst. Air 

sootblowers were also considered but, due to the high loss on ignition (LOI) at the plant, were 

determined to be a potential fire hazard. The top layer of catalyst will be provided with steam 

sootblowers. The balance of the catalyst layers will be cleaned using sonic horns. This system will 

require compressed air to operate. A separate compressor for each unit was assumed for the cost 

estimate. 

 Large Particle Ash Screen. To collect the maximum amount of fly ash at the economizer hopper, a large 

particle ash screen will be installed at the exit of the economizer. This ash screen will be used to divert 

larger fly ash particles that can plug the SCR catalyst into the economizer ash hoppers. This may also 

eliminate the need for additional fly ash systems at the SCR inlet and outlet ductwork. 
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 SCR Catalyst Replacement. An elevator was included in the SCR cost estimate to replace spent catalyst 

at the end of the catalyst life. 

 Dry Sorbent Injection. The SCR will increase the formation of SO3 and SAM loading to downstream 

equipment. To meet the units’ existing SAM emission limit with an SCR, require installation and 

operation of a DSI control system. Therefore, costs for a DSI control system were included in the SCR 

cost estimate. 

 Ammonia System. The location of the ammonia system is dependent on the type of ammonia being used 

and whether each unit will have a separate ammonia storage facility. The SCR cost estimate was based 

on the assumption that all four units would share a single ammonia storage facility with the associated 

truck delivery and unloading facilities. 

 Auxiliary Power Upgrades. Operation of the SCR control system will require upgraded fans and 

electrical systems to allow the plant to operate at full load with the additional pressure loss generated by 

the SCR. Fan modifications include replacement of the rotors and other fan modifications for the forced 

draft (FD) fans on all units, replacement of the induced draft (ID) fans and motors on all units, and 

addition of variable frequency drives to replace the existing fan inlet dampers. The existing electrical 

system of Units 1 and 2 may not be capable of handling the new fan loads required to operate the SCR 

control systems, and may require a new power line and related electrical equipment from the existing 

switchyard. Costs for these upgrades were included in the cost estimate. 

 Structural Stiffening. Structural stiffening of the boiler, ductwork, and equipment downstream of the 

boiler will be required to operate the SCR control system and to operate the plant in a balanced draft 

configuration. These costs were included, along with the fan and electrical system upgrades, in the 

balanced draft conversion cost estimate. However, as discussed above, a majority of theses costs would 

be incurred (e.g., fan and electrical system upgrades) with the installation of SCR control systems and no 

concurrent balanced draft conversion. Therefore, these costs were split between the SCR and balanced 

draft projects by assigning 80% of the costs to the SCR and 20% to the additional needed for balance 

draft conversion. 

 Control Systems. The existing DCS system will need to be expanded to accommodate the additional 

signals from the SCR system. 

 Construction Costs and Special Cranes. A review of the site arrangement shows that the free space 

between the units is limited due to modifications to the plant with the addition of the baghouses and the 

coal conveyor running between the units. In order to have the lifting capacity that is required to install 

an SCR and accommodate the demolition that is required, special cranes are required. Construction 

difficulty is very high for this very tight site. 

3.3 SNCR Cost Estimate Methodology 

S&L used unit-specific SJGS operating data (e.g., fuel characteristics and consumption, flue gas flow rates and 

temperatures, and NOx emission rates) developed for previous PNM studies, as well as experience from similar 

SNCR control system studies, to develop capital and O&M costs for the SNCR control option. S&L also 
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contacted Fuel Tech, an SNCR Original Equipment Manufacturer (OEM) for preliminary equipment pricing 

estimates and BOP requirements. Fuel Tech’s preliminary cost estimate was developed based on boiler-specific 

operation information provided by S&L. Equipment costs were provided for the major components, including 

urea handling system, injection lances, piping, pumps, etc. Due to similarities in size, it was assumed that costs 

would be similar for each ‘sister’ unit (e.g., Units 1 & 2 and for Units 3 & 4). 

3.3.1 Factors Affecting the SNCR Design 

Several site-specific factors affect the design and effectiveness of SNCR control systems. Based on a review of 

preliminary design information provided by Fuel Tech, primary design considerations affecting SNCR design 

include the carbon monoxide (CO) concentration in the boiler flue gas and NOx reduction requirements. 

Carbon Monoxide and Combustion Controls: Fuel Tech’s budgetary SNCR equipment cost estimate 

assumed a CO concentration in the flue gas at the furnace bull nose of 350 ppm for Units 1 & 2 and 300 ppm 

for Units 3 & 4. Based on a review of historian data available from the SJGS units, CO concentrations at the 

bull nose could be significantly greater than 350 ppm, and may be in the range of 3,000 ppm or more. 

Industry experience has shown that CO levels below 1,000 ppm at the bull nose are needed to obtain the 

highest SNCR NOx removal efficiency. If CO levels exceed 5,000 ppm at the bull nose, SNCR is not a 

viable technology due to a number of factors, including low urea utilization, low removal efficiency and high 

ammonia slip. The SNCR equipment cost estimate was developed based on the assumption that CO 

concentrations in each boiler at the bull nose can be controlled to a level that allows for effective NOx 

removal, and that the SNCRs can be designed to achieve NOx removal efficiencies of 25% to 30%. 

Controlled NOx Emissions: Cost estimates provided herein are based on Fuel Tech’s July 10, 2012 SNCR 

budgetary proposal. The July 2012 proposal was a revision of the proposal Fuel Tech submitted August 10, 

2011 at the request of S&L, to assist in evaluating the viability of SNCR technology in meeting a controlled 

NOx emission limit of 0.23 lb/mmBtu. No technical specifications were developed for solicitation of this 

proposal, which is based primarily on Fuel Tech’s experience in the industry. 

The Fuel Tech proposal included several urea injector options, including options for retractable injectors, 

High Energy Reagent Technology (HERT) lances, and Multi-Nozzle Lance (MNL) injectors. Locating the 

urea injection lances within the appropriate temperature window within the boiler, and designing the lances 

to promote flue gas/urea mixing, are important design considerations for an SNCR control system. 

Assuming an average uncontrolled NOx emission rate of 0.30 lb/mmBtu, the SNCR would have to achieve 

an average removal efficiency of approximately 25% to consistently achieve a controlled NOx emission rate 
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of 0.23 lb/mmBtu. Based on achieving a removal efficiency of 25%, S&L assumed the use of HERT 

injectors for the SNCR cost estimates. Boiler gas species mapping will need to be done before the SNCR 

OEM can supply PNM with a removal efficiency guarantee. Combustion tuning will likely be required to 

reduce the CO levels in the boilers. If additional removal is needed for NOx compliance, PNM would need 

to consider the MNL option. 

Fugitive Emissions Control and Balanced Draft Conversion: As discussed above, PNM may be required to 

reduce existing fugitive emissions at the plant. Fugitive emissions from the existing boilers could be 

minimized or eliminated by converting the boilers to balanced draft operation. Balanced draft conversion 

would require the installation of new fans, boiler and ductwork stiffening, and upgrades to the existing 

electrical systems. However, unlike the SCR project, SNCR could be installed and operated on the units 

without these upgrades; therefore, balance draft costs were not included in the SNCR cost estimate. 

3.3.2 Project-Specific SNCR Design Criteria and Assumptions 

Based on a site-specific review of the NOx reduction requirements and retrofit challenges for the installation of 

SNCR control systems and associated plant changes at SJGS, the following project-specific issues were taken 

into consideration in the development of the SNCR cost estimates: 

 Urea Delivery, Unloading, and Storage. The SNCR cost estimate is based on using urea as the reactant. 

Urea solution (50% aqueous urea by weight) would be delivered to the site via truck to either urea 

unloading area. Urea is a solid on its own, but when mixed with water it becomes a clear liquid solution. 

It would be delivered in this form and unloaded via onboard truck pumps into the FRP storage tanks. 

The total storage capacity is sized for 14 days of continuous operation per unit at full load. The tanks 

would be heat traced and insulated in order to keep the 50% urea solution above 80 °F to prevent 

precipitation of urea solids out of solution. 

 Urea Circulation. The urea storage tanks would be cross tied and transfer the 50% urea solution from the 

storage area to the units via 2 x 100% centrifugal pumps. The urea solution would be transferred using 

stainless steel piping. A loop from the storage tanks to the unit metering modules and back to the storage 

tanks continuously circulates the 50% urea solution. Process heat trace is required to keep the urea 

solution above 80 °F. 

 Urea Dilution and Metering. Dilution water would be pumped via 2 x 100% centrifugal pumps to the 

metering modules located in the unit, where it would mix with the 50% urea solution prior to injection 

into the boiler. Dilution of the urea solution to 5-10 wt% urea is required prior to injection. Variable 

frequency drives would be utilized to maintain a constant pressure of dilution water in response to 

changing flow demands. The metering modules provide flow and pressure control of the fluids used in 

the SNCR process. 

 Diluted Urea Distribution and Injection. The distribution modules would provide diluted urea solution 

and atomizing air to individual injectors. The modules are typically located near the injectors on the 
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same elevation. Diluted urea solution is fed from the metering modules to the distribution modules. The 

distribution module outputs one (1) atomizing air line and one (1) urea solution line to each injector. The 

injectors are used for dispersion of diluted urea solution within targeted areas of the boiler. Design, 

quantity, type and placement of the injectors are critical to SNCR performance; furnace temperature, 

residence time, and droplet size are important design parameters controlled by injector placement. The 

exact locations of the injectors will be determined by the SNCR OEM based on computational fluid 

dynamics (CFD) modeling of the furnace. For the SNCR cost estimate, injector locations were selected 

based on S&L’s industry experience, assuming the use of HERT injectors. 

 Balance of Plant (BOP) Systems. Demands on the ancillary systems are influenced by the SNCR OEM’s 

equipment design. BOP systems and costs included in this study are based on the Fuel Tech budgetary 

cost proposal provided for SJGS. 

 Raw Water & Water Treatment. Raw water will be utilized for urea dilution water. A tie-in to the 

existing raw water line located below grade between Units 3 and 4 will be made to supply the required 

water. Based on a review of the station’s existing water supply system, adequate pressure, flow and 

pump redundancy are currently available at this tie-in location. S&L also received a water analysis for 

the raw water, and reviewed the SNCR OEM dilution water quality requirements. In order to meet the 

dilution water quality requirement by the SNCR OEM, S&L added a common water treatment system. 

The water treatment system includes filters to remove suspended solids, zeolite softeners for the removal 

of hardness and a 10,000 gallon head tank for temporary dilution water storage. 

 Plant and Instrument Air System. The addition of the SNCR system adds a large air user to each unit. To 

meet the air consumption requirements for the atomizing air, 2 x 100% capacity, oil-free compressors 

would be added per unit. These compressors would also provide compressed air to all new intermittentuser (valves, instruments, tools, etc.); therefore, no additional compressed air load would be added to the 

existing plant compressed air systems. All air would be dried to -40 °F dew point by implementing 

2 x 100% regenerative desiccant dryers. Instrument air piping would be stainless steel. 

 Air Heater Evaluation. The application of SNCR technology to coal-fired power plants creates a 

potential problem with the deposition of ammonia-sulfur salts in the air preheater. SO3 is formed in the 

boiler from oxidation of sulfur in the coal. Urea that is injected in the boiler decomposes into ammonia 

and is not fully used, creating a slip stream of ammonia that exits through the economizer. If the 

concentration of ammonia is more than twice that of the SO3 in the flue gas, the ammonia slip can react 

with SO3 to form ammonium bisulfate (ABS). ABS will condense from the gas stream and form a sticky 

deposit on the heat transfer surface of the air heater at a temperature of 380 – 450 F. Fly ash particles 

will tend to stick to the ABS resulting in the gradual pluggage of the air preheater (APH). Depending on 

the degree of formation, this could result in an increase in APH pressure drop (impacting ID fan 

capacity), as well as a loss in thermal efficiency for the plant. ABS is also corrosive (acidic in nature) 

and will corrode the mild steel or low alloy steel surfaces of the APH. The flue gas path at SJGS 

includes a hot-side ESP, which has been de-energized since the baghouse installation. This means that 

some of the particulate matter upon which the SO3 and ammonia could condense will be removed prior 

to the temperature window for ABS formation. Removing solid particles from the flue gas stream prior 

to the APH should minimize the possibility of plugging due to flyash sticking to ABS in the APH. 

Because of this, it is not expected that coating of the APH baskets will be necessary at SJGS. However, 
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before knowing exactly how much gaseous SO3 and ammonia will pass through the ESP and into the 

APH, the performance should be closely monitored. 

 Fire Protection System. Fire protection for the new pre-engineered buildings would include alarm and 

detection, as well as fire extinguishers. It is anticipated no additional fire hydrants or a dispersion system 

will be required for the urea unloading area. 

 Furnace Modifications. Penetrations in the boiler water wall will be required at the injector locations. 

To support the injector penetrations, water wall tubes will need to be removed and replaced with tubes 

curved around the penetration location, a boot and a flange. The injector(s) mount to the flange. In 

some instances additional structural reinforcement may be required to support the injectors. 

 Lighting and Maintenance Power System. The cost estimate was based on the assumption that the 

lighting power system would consist of normal AC lighting, DC emergency lighting, and convenience 

receptacles, and that the lighting system would follow the lighting system at the existing plant. 

 Grounding System. The cost estimate was based on the assumption that the station’s grounding system 

would be extended with an interconnected network of bare copper conductors and copper ground rods. 

The systems would be designed to protect plant personnel and equipment from the hazards that can occur 

during power system faults and lightning strikes. The grounding system would be designed in 

accordance with applicable IEEE standards and would be installed in accordance with the NEC. 

Lightning protection design would be in accordance with NFPA 780. 

 Process and Freeze Protection Heat Tracing System. Freeze protection system would be provided for 

outdoor piping (8” and smaller), instruments, and other devices subject to freezing in cold weather. The 

freeze protection system would be designed to accommodate both normal plant operations and extended 

plant shutdowns during cold weather. All urea piping and tanks would be process heat traced to a 

minimum temperature of 80 oF to avoid crystallization. 

3.4 Plant Economic Assumptions 

Cost estimates prepared for SJGS are conceptual in nature, based largely on budgetary equipment costs provided 

by equipment suppliers, costs incurred on similar projects, and S&L’s experience with the design and installation 

of retrofit SNCR and SCR control systems. Allowances have been included, where necessary, to address sitespecific retrofit issues and design assumptions described above. Contracting strategies and cost assumptions 

used as the basis for the SCR and SNCR cost estimates are summarized below: 

 Contracting Strategy. The capital cost for the plant modifications are based on hiring an Engineer, 

Procure and Construct (EPC) contractor to provide a ‘turn-key’ air quality control system. Design of the 

control system would be performed by the EPC contractor. All equipment would be purchased directly 

by and installed by the EPC contractor. 

 Equipment Costs. Equipment costs include only those costs for the manufactured equipment. For the 

SNCR control system these items include the SNCR system, compressors, water treatment, tanks, pumps, 

and motors. For the SCR control system these items include the SCR reactor vessel and catalyst 
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modules, economizer bypass and low load temperature control system, ammonia system, dry sorbent 

injection control system, and related ancillary equipment. 

 Material Costs. Material costs include those costs for commodity-like materials, such as structural steel, 

concrete, piping, valves, cable, cable tray, and conduit. All material unit costs were estimated on the 

basis of S&L in-house data, vendor catalogs, and industry publications. Quantities of materials were 

developed based on the conceptual designs and general arrangement drawings prepared for each control 

system. 

 Labor Costs. Union craft labor rates were developed for both projects for the Albuquerque, New Mexico 

area from the publication RS Means. Union rates were then incorporated into work crews appropriate for 

the activities by adding allowances for payroll taxes, worker’s compensation, fringe benefits, incidentals, 

small tools, construction equipment, and site overheads to arrive at crew rates detailed in the cost 

estimate. 

 Labor Incentives (SNCR). Labor incentives for the SNCR work are estimated based on 5 days x 10 

hours/day work week for the non-outage work. The boiler tube insert modifications and scaffolding 

required for this work will be performed during an outage, and are estimated based on 6 days x 10 

hours/day work schedule. The cost estimate reflects this assumption for overtime calculations. For 

common areas, is it assumed all work would be performed during pre-outage, and therefore reflects 5 

days x 10 hours/day schedule. 

 Labor Incentives (SCR). Labor incentives for the SCR work are estimated based on 5 days x 10 

hours/day work week for the non-outage work. Outage labor incentives were estimated based on 7 days 

and two shifts of 12 hours/day. 

 Labor Productivity. A 1.15 labor productivity factor was used in the estimates based on the regional 

labor productivity factor in the New Mexico area as published in Compass International Global 

Construction Cost and Reference Yearbook. 

 Subsistence Pay. Cost estimates assume no subsistence pay. 

 Project Indirect Costs. Project indirect costs assumed for the SCR and SNCR cost estimates include: 

 Freight - Materials: 5% of Material Cost 

 Freight – Equipment: Included in equipment cost 

 Consumables: 0.5% of Labor & Materials 

 Sales Tax: Not included 

 EPC Engineering, Procurement 

 and Project Services (SCR): 8% of total direct & construction indirect costs 

 EPC Engineering, Procurement 

 and Project Services (SNCR): 6% of total direct & construction indirect costs 

 EPC Management Support (SCR) 3% of total direct & construction indirect costs 

 Owners Engineering (SNCR): 2% of total direct & construction indirect costs 

 Construction Management Support (SNCR): 2% of total direct & construction indirect costs 

 Owners Engineering & Construction 
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Management (SCR): 4% of total direct & construction indirect costs 

 EPC Startup & Commissioning 1% of total direct & construction indirect costs 

 EPC Fee: 15% of total direct & construction indirect costs 

 Escalation. None. Escalation is typically included in cost estimates for major retrofit control projects 

and is intended to account for increases in equipment, material, and labor costs that occur during the 

duration of the project; however, escalation was not included in the SCR/SNCR cost estimates. Cost 

estimates attached to this report are shown in 2013 dollars. 

 Contingency. Contingency is intended to represent unforeseeable elements of cost, particularly in fixed 

investment estimates, which previous experience has shown to be statistically likely to occur. 

Contingency is allowed by the Control Cost Manual approach, and should be based on the level of 

project definition (typically expressed as the percent of complete design). Contingency was included in 

both the SNCR and SCR cost estimates as follows: 

 Contingency (SNCR): 

 10% of Equipment Costs 

 20% of Material Costs 

 20% of Labor Costs 

 20% of Construction Indirect Costs 

 Contingency (SCR): 

 20% of Total Direct and Indirect Construction Costs 

 Allowance for Funds Used During Construction (AFUDC) or Interest During Construction (IDC). None. 

AFUDC and/or IDC were not included in the SCR/SNCR cost estimates. AFUDC accounts for the time 

value of money associated with the distribution of construction cash flows over the construction period, 

which for an SCR system could be spread over a construction period of 36+ months. TCI, as defined in 

the Control Cost Manual, includes all costs required to purchase equipment needed for the control system 

(purchased equipment costs), the costs of labor and materials for installing that equipment (direct 

installation costs), costs for site preparation and building, working capital, and off-site facilities.12 Thus, 

the Control Cost Manual allows the time value of money, measured by the real discount rate, to be 

incorporated into the cost estimate. Although AFUDC can represent a significant cost that PNM will 

incur with and SCR project (estimated to be in the range of $38 to $45 million), AFUDC was excluded 

from the SCR and SNCR cost estimates. 

 New Mexico Gross Receipt Tax. The New Mexico Gross Receipt Tax (NMGRT) of 6.3125% was 

applied to the total cost (i.e., purchased equipment and services performed) of both the SNCR and SCR 

projects. 

 

12 OAQPS Control Cost Manual, page 2-5. 
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3.5 Operating & Maintenance Cost Assumption 

Annual O&M costs include both fixed and variable costs and indirect operating costs. Variable O&M costs are 

items that generally vary in proportion to the plant capacity factor. Variable costs associated with SCR and 

SNCR control systems include: reagent costs (e.g., urea or anhydrous ammonia); catalyst replacement costs 

(SCR); and auxiliary power costs associated with operating the equipment, water, and steam. Variable O&M 

costs can also include a boiler efficiency penalty if the control system results in reduce boiler efficiency (e.g., 

SNCR). Fixed costs are independent of the level of production, and would be incurred even if the control system 

were shut down and include costs such as maintenance labor and materials, administrative charges, property 

taxes, and insurance. 

Both fixed and variable O&M costs were included in the SCR and SNCR cost estimates. Assumptions used to 

calculate annual O&M costs are listed in each of the cost estimate worksheets, respectively. 

3.6 Cost Estimates 

Conceptual cost estimates were developed for the SNCR and SCR control systems based on the design criteria 

and assumptions provided herein. Cost estimates prepared for the control systems include all costs associated 

with equipment, labor, freight, and the New Mexico Gross Receipts Tax related to the respective projects. Costs 

for the major system components were based on budgetary equipment quotes obtained from equipment vendors, 

S&L in-house data, vendor catalogs, industry publications (such as Means and Richardson), and costs from other 

similar projects. Cost estimates for the SJGS projects include the costs to install the control systems, as well as 

the associated ductwork and equipment modifications taking into account site-specific operating conditions and 

site constraints. Cost estimates include EPC engineering, procurement and project services; EPC construction 

management support; EPC commissioning; and an EPC fee, as well as costs for owner’s engineering and 

management. Cost estimates do not include escalation for equipment, material, or labor that could occur over the 

time period necessary to complete construction, and do not include an allowance for funds used during 

construction (AFUDC). Capital cost estimates for the SNCR and SCR projects summarized in Attachments A, 

B, and C include the following: 

Cost Estimates for SNCR Systems: 

 Estimate 31803B: Unit 1 (and Unit 2) SNCR Conceptual Cost Estimate 

 Estimate 31804B: Unit 3 (and Unit 4) SNCR Conceptual Cost Estimate 

 Estimate 31807B: SNCR Common Equipment Conceptual Cost Estimate 

Cost Estimates for SCR System: 
Project No. 11278-034 

SAN JUAN GENERATING STATION 03/29/2013 

SNCR AND SCR COST ESTIMATES Page 19 

 Estimate 31326C: Unit 1 SCR Conceptual Cost Estimate 

 Estimate 31327C: Unit 2 SCR Conceptual Cost Estimate 

 Estimate 31328C: Units 1 & 2 SCR Common Equipment Conceptual Cost Estimate 

 Estimate 31329C: Unit 3 SCR Conceptual Cost Estimate 

 Estimate 31330C: Unit 4 SCR Conceptual Cost Estimate 

 Estimate 31331C: Units 1, 2, 3, & 4 SCR Common Equipment Conceptual Cost Estimate 

3.6.1 SNCR Cost Estimates 

The following costs are included in the SNCR conceptual cost estimates: 

Units 1 (and Unit 2) Base Estimate (Estimate 31803B): 

 SNCR equipment 

 Boiler modifications and injection lance installation 

 Urea unloading area consisting of two (2) FRP tanks 

 Urea circulating skids, circulating pumps 

 Compressed air and dryer system 

 Metering modules 

Units 3 (and Unit 4) Base Estimate (Estimate 31804B): 

 SNCR equipment 

 Boiler modifications and injection lance installation 

 Urea unloading area consisting of three (3) FRP tanks 

 Urea circulating skids, circulating pumps 

 Compressed air and dryer system 

 Metering modules 

Units 1 & 3 Common Equipment Cost Estimate (Estimate 31807B): 

 Dilution water treatment system 

3.6.2 SCR Cost Estimates 

The following costs are included in the SCR conceptual cost estimates: 

Units 1 & 2 Base Estimate (Estimates 31326C & 31327C): 

 SCR equipment & ductwork – each unit 

 Demolition of upper hot-side ESP penthouse – each unit 

 Demolition of ash handling system on economizer hoppers – each unit 
Project No. 11278-034 

SAN JUAN GENERATING STATION 03/29/2013 

SNCR AND SCR COST ESTIMATES Page 20 

 Demolition of seal air fan area on hot-side ESPs 

 Dry flight chain conveyor system on economizer hopper with storage tank – each unit 

 Sorbent injection unit for sulfuric acid control – each unit 

 Sorbent silo & blowers for Units 1 & 2 (two silos total) 

 Addition of a second ash handling system on the existing Units 1 & 2 baghouses. Hoppers have 

connections for equipment, but need new feeders, piping system and blowers to transport ash to 

existing silos 

 Equipment and materials for gas path upgrades needed to handle pressure drop associated with SCR, 

as well as added scope for balanced draft conversion 

Units 1 & 2 Common Equipment Cost Estimate (Estimate 31328C): 

 Ammonia storage tank and tank equipment – one storage tank for two units 

 Common elevator for Units 1 & 2 

Units 3 & 4 Base Estimate (Estimates 31329C & 31330C): 

 SCR equipment & ductwork – each unit 

 Elevator – each unit 

 Demolition of upper hot-side ESP penthouse – each unit 

 Demolition of hot-side ESP electrical control room 

 Demolition of ash handling system on economizer hoppers – each unit 

 Demolition of Gas Recirculation fan (1 fan Unit 3 north side and 1 fan Unit 4 south side) 

 Demolition of seal air fan area on hot-side ESPs 

 Dry flight chain conveyor system on economizer hopper with storage tank – each unit 

 Sorbent injection unit for sulfuric acid control – each unit 

 Sorbent silo & blowers for Units 3 & 4 (two silos total) 

 Ammonia storage tank – each unit 

 Addition of a second ash handling system on the existing Units 3 & 4 baghouses. Hoppers have 

connections for equipment, but need new feeders, piping system and blowers to transport ash to 

existing silos 

 Additional gallery on north side of units for dilution air skids 

 Equipment and materials for gas path upgrades needed to handle pressure drop associated with SCR, 

as well as added scope for balanced draft conversion 

Units 1, 2, 3 & 4 Common Equipment Cost Estimate (Estimate 31331C): 

 Ammonia delivery (truck unloading station) & storage area 

 Demolition of sulfuric acid storage tank & spare tank in acid storage area 

 Demolition of stairs & platforms in tank area 
Project No. 11278-034 

SAN JUAN GENERATING STATION 03/29/2013 

SNCR AND SCR COST ESTIMATES Page 21 

 Saw cut wall on east side of containment area to redefine as a non-confinement space 

 Modifications to existing mechanical systems (piping modifications) 

4. SUMMARY 

Based on the design parameters, costs, site constraints, and assumptions outlined above, capital and O&M costs 

estimates were prepared for retrofit SNCR and SCR controls on SJGS Units 1, 2, 3 & 4. The cost estimating 

methodology described above is consistent with the approach described in EPA’s Control Cost Manual, and 

provides a conceptual cost estimate, or scoping-level estimate. Cost estimates prepared using default factors 

provided in the Control Cost Manual are directed toward a study-level estimate with a nominal accuracy of 

±30%.13 Study-level estimates are generally acceptable for regulatory development, because they represent a 

compromise between the less accurate order-of-magnitude and the more accurate, but more costly, estimate 

types.14 However, the Control Cost Manual does not mandate a study-level cost estimate, and “offers the user an 

opportunity for greater accuracy than that used by regulators.”15 The methodology used by S&L to prepare the 

SCR and SNCR cost estimates provides a more accurate estimate of the costs that PNM would incur to install 

and operate SNCR and SCR control systems at SJGS. 

Project-specific issues and key project elements affecting the cost of retrofit control technologies on the SJGS 

units were identified and accounted for in the development of the cost estimates. The most significant projectspecific issue affecting the cost of installing SCR control systems is the tight site configuration available for SCR 

installation. As described in Section 3.2.1, site constraints will make SCR installation significantly more 

complex and expensive that similarly sized projects with adequate space. Other project related issues affecting 

control system costs include the NOx emission reduction requirements and the existing and anticipated permit 

limits for other regulated air pollutants. 

 

13 OAQPS Control Cost Manual, page 2-3. 

14 Id., at page 2-4. 

15 Id,. at page 2-3.
Project No. 11278-034 

SAN JUAN GENERATING STATION 03/29/2013 

SNCR AND SCR COST ESTIMATES Page 22 

ATTACHMENT A.

SAN JUAN GENERATING STATION

UNITS 1, 2, 3, AND 4 

SNCR COST ESTIMATES
Unit 1 Unit 2 Unit 3 Unit 4

Capacity (MWg) 370 370 544 544

Capacity (MWn) 327 327 497 507

Maximum Heat Input (MMBtu/hr) 3707 3688 5758 5649

Annual Capacity Factor (%) 85% 85% 85% 85%

Baseline NOx Emission Rate (lb/MMBtu) 0.30 0.30 0.30 0.30

Baseline NOx Emission Rate (lb/hr) 1112.1 1106.4 1727.4 1694.7

Controlled NOx Emission Rate (lb/MMBtu) 0.23 0.23 0.23 0.23

Controlled NOx Emission Rate (lb/hr) 852.6 848.2 1324.3 1299.3

Cost Item UNIT 1 UNIT 2 UNIT 3 UNIT 4 Remarks/Cost Basis

CAPITAL COST 

Direct Costs 

Purchased Equipment Costs

SNCR System $1,730,300 $1,730,300 $1,724,000 $1,724,000 Acct. Nos. 31-53-1

CFD Model Study $150,000 $150,000 $150,000 $150,000 Acct. Nos. 31-53-2 

Boiler Tuning $150,000 $150,000 $150,000 $150,000 Acct. Nos. 31-53-3 

Air Compressor & Accessories $360,000 $360,000 $360,000 $360,000 Acct. Nos. 31-17

Steel $129,100 $129,100 $113,500 $113,500 Acct. Nos. 23

Instrumentation and Control System $145,000 $145,000 $145,000 $145,000 Acct. Nos. 44

Boiler Injection Ports $83,000 $83,000 $83,000 $83,000 Acct. Nos. 31-99

Architectural $352,500 $352,500 $352,500 $352,500 Acct. Nos. 24

Fire Protection $3,600 $3,600 $3,600 $3,600 Acct. Nos. 31-45

Pumps $30,000 $30,000 $30,000 $30,000 Acct. Nos. 31-75

Tanks $22,500 $22,500 $22,500 $22,500 Acct. Nos. 31-83

Dilution Water Treatment System $375,000 $375,000 $375,000 $375,000 Acct. Nos. 31-93

Subtotal capital cost (CC) $3,531,000 $3,531,000 $3,509,100 $3,509,100

Freight $88,200 $88,200 $87,900 $87,900 Acct. Nos. 91-5

Total purchased equipment cost (PEC) $3,619,200 $3,619,200 $3,597,000 $3,597,000

Direct installation costs 

Handling & erection (includes labor costs) $4,549,300 $4,549,300 $4,435,600 $4,435,600 Acct. Nos. 11 through 44 Labor Costs (excluding 31-99 Labor)

Foundation & supports $257,100 $257,100 $295,800 $295,800 Acct. Nos. 21 and 22

Electrical $615,650 $615,650 $610,350 $610,350 Acct. Nos. 41 through 43

Piping $576,950 $576,950 $537,550 $537,550 Acct. Nos. 35

Insulation $30,900 $30,900 $28,000 $28,000 Acct. Nos. 36

Painting $10,500 $10,500 $700 $700 Acct. Nos. 27

Demolition and Relocation $7,500 $7,500 $22,500 $22,500 Acct. Nos. 11

Scaffolding $168,100 $168,100 $165,300 $165,300 Acct. Nos. 91-1

Boiler Port Installation $393,400 $393,400 $402,200 $402,200 Acct. Nos. 31-99 (Labor)

Cost Due to Overtime $726,900 $726,900 $718,000 $718,000 Acct. Nos. 91-2

Consumables $33,650 $33,650 $33,050 $33,050 Acct. Nos. 91-4

Total direct installation costs (DIC) $7,369,950 $7,369,950 $7,249,050 $7,249,050

Total direct costs (DC) = (PEC) + (DIC) $10,989,150 $10,989,150 $10,846,050 $10,846,050

Indirect Costs 

Owner's Engineering $219,800 $219,800 $217,000 $217,000 Acct. Nos. 93-1A

EPC Engineering, Procurement and Project Services $659,300 $659,300 $650,800 $650,800 Acct. Nos. 93-1B

Owner's cost $0 $0 $0 $0 Acct Nos. 93-4

Construction management $219,800 $219,800 $217,000 $217,000 Acct. Nos. 93-2

Start-up and spare parts $110,000 $110,000 $108,500 $108,500 Acct. Nos. 93-3

EPC Fee $1,829,650 $1,829,650 $1,805,850 $1,805,850 Acct. Nos. 93-5

Total indirect costs (IC) $3,038,550 $3,038,550 $2,999,150 $2,999,150

New Mexico Gross Receipts Tax (GRT) $885,000 $885,000 $874,000 $874,000 (DC + IC) X 6.3125% 

Project Contingency (PC) $2,478,900 $2,478,900 $2,444,300 $2,444,300 Acct. Nos. 95-1 through 95-4

Total Capital Investment

(TCI)=(DC)+(IC)+(GRT)+(PC) $17,391,600 $17,391,600 $17,163,500 $17,163,500

Privileged & Confidential

San Juan Units 1 - 4

SNCR Cost Estimate

SNCR COST ANALYSIS
Unit 1 Unit 2 Unit 3 Unit 4

Capacity (MWg) 370 370 544 544

Capacity (MWn) 327 327 497 507

Maximum Heat Input (MMBtu/hr) 3707 3688 5758 5649

Annual Capacity Factor (%) 85% 85% 85% 85%

Baseline NOx Emission Rate (lb/MMBtu) 0.30 0.30 0.30 0.30

Baseline NOx Emission Rate (lb/hr) 1112.1 1106.4 1727.4 1694.7

Controlled NOx Emission Rate (lb/MMBtu) 0.23 0.23 0.23 0.23

Controlled NOx Emission Rate (lb/hr) 852.6 848.2 1324.3 1299.3

Cost Item UNIT 1 UNIT 2 UNIT 3 UNIT 4 Remarks/Cost Basis

Privileged & Confidential

San Juan Units 1 - 4

SNCR Cost Estimate

SNCR COST ANALYSIS

ANNUAL COST 

Direct Annual Costs 

Fixed annual costs 

Operating labor $0 $0 $0 $0 Assumed no operating labor for the SNCR

Annual Maintenance Cost $260,900 $260,900 $257,500 $257,500 TCI X 1.5% [EPA Cost Manual Section 4.2, Chapter 1, Eqn.1.21]

Total fixed annual costs $260,900 $260,900 $257,500 $257,500

Variable annual costs 

Reagent Consumption $3,353,700 $3,353,700 $6,177,200 $6,177,200

Based on 225.2 gph (U1&U2, each) and 414.8 gph (U3&U4, each) 

(50% urea solution) per Fuel Tech Proposal 11-B-122, Rev.1, 07-10-

2012. Assumes $2.0/gal and 85% CF.

Water Consumption $134,000 $134,000 $150,100 $150,100

Based on 50 gpm (U1&U2, each) and 56 gpm (U3&U4, each) per 

Fuel Tech Proposal 11-B-122, Rev.1, 07-10-2012. Assumes 

$6/1000 gal and 85% CF.

Power Requirement $42,700 $42,700 $51,000 $51,000

Based on 155 kW (U1&U2, each) and 185 kw (U3&U4, each) per 

per Fuel Tech Proposal 11-B-122, Rev.1, 07-10-2012 and S&L 

BOP estimate. Assumes $37/MWh and 85% CF.

Total variable annual costs $3,530,400 $3,530,400 $6,378,300 $6,378,300

Total direct annual costs (DAC) $3,791,300 $3,791,300 $6,635,800 $6,635,800

Indirect Annual Costs 

Cost for capital recovery $1,609,000 $1,609,000 $1,588,000 $1,588,000 (TCI) X 9.25% CRF at 8.44% interest & 30 year life 

Total indirect annual costs (IDAC) $1,609,000 $1,609,000 $1,588,000 $1,588,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $5,400,300 $5,400,300 $8,223,800 $8,223,800

Emission Reductions (ton/yr) 966 961 1,501 1,472 Based on baseline NOx rate of 0.30 lb/MMBtu and controlled rate 

of 0.23 lb/MMBtu

Cost Effectiveness ($/ton) 5,590 5,618 5,480 5,587

Cost ($/kW) 47.0 47.0 31.6 31.6
Unit 1 Unit 4

Capacity (MWg) 370 544

Capacity (MWn) 327 507

Maximum Heat Input (MMBtu/hr) 3707 5649

Annual Capacity Factor (%) 85% 85%

Baseline NOx Emission Rate (lb/MMBtu) 0.30 0.30

Baseline NOx Emission Rate (lb/hr) 1112.1 1694.7

Controlled NOx Emission Rate (lb/MMBtu) 0.23 0.23

Controlled NOx Emission Rate (lb/hr) 852.6 1299.3

Cost Item UNIT 1 UNIT 4 Remarks/Cost Basis

CAPITAL COST 

Direct Costs 

Purchased Equipment Costs

SNCR System $1,730,300 $1,724,000 Acct. Nos. 31-53-1

CFD Model Study $150,000 $150,000 Acct. Nos. 31-53-2 

Boiler Tuning $150,000 $150,000 Acct. Nos. 31-53-3 

Air Compressor & Accessories $360,000 $360,000 Acct. Nos. 31-17

Steel $129,100 $113,500 Acct. Nos. 23

Instrumentation and Control System $145,000 $145,000 Acct. Nos. 44

Boiler Injection Ports $83,000 $83,000 Acct. Nos. 31-99

Architectural $352,500 $352,500 Acct. Nos. 24

Fire Protection $3,600 $3,600 Acct. Nos. 31-45

Pumps $30,000 $30,000 Acct. Nos. 31-75

Tanks $22,500 $22,500 Acct. Nos. 31-83

Dilution Water Treatment System $375,000 $375,000 Acct. Nos. 31-93

Subtotal capital cost (CC) $3,531,000 $3,509,100

Freight $88,200 $87,900 Acct. Nos. 91-5

Total purchased equipment cost (PEC) $3,619,200 $3,597,000

Direct installation costs 

Handling & erection (includes labor costs) $4,549,300 $4,435,600 Acct. Nos. 11 through 91 Labor Costs

Foundation & supports $257,100 $295,800 Acct. Nos. 21 and 22

Electrical $615,650 $610,350 Acct. Nos. 41 through 43

Piping $576,950 $537,550 Acct. Nos. 35

Insulation $30,900 $28,000 Acct. Nos. 36

Painting $10,500 $700 Acct. Nos. 27

Demolition and Relocation $7,500 $22,500 Acct. Nos. 11

Scaffolding $168,100 $165,300 Acct. Nos. 91-1

Boiler Port Installation $393,400 $402,200 Acct. Nos. 31-99 (Labor)

Cost Due to Overtime $726,900 $718,000 Acct. Nos. 91-2

Consumables $33,650 $33,050 Acct. Nos. 91-4

Total direct installation costs (DIC) $7,369,950 $7,249,050

Total direct costs (DC) = (PEC) + (DIC) $10,989,150 $10,846,050

Indirect Costs 

Owner's Engineering $219,800 $217,000 Acct. Nos. 93-1A

EPC Engineering, Procurement and Project Services $659,300 $650,800 Acct. Nos. 93-1B

Owner's cost $0 $0 Acct Nos. 93-4

Construction management $219,800 $217,000 Acct. Nos. 93-2

Start-up and spare parts $110,000 $108,500 Acct. Nos. 93-3

EPC Fee $1,829,650 $1,805,850 Acct. Nos. 93-5

Total indirect costs (IC) $3,038,550 $2,999,150

New Mexico Gross Receipts Tax (GRT) $885,000 $874,000 (DC + IC) X 6.3125% 

Project Contingency (PC) $2,478,900 $2,444,300 Acct. Nos. 95-1 through 95-4

Total Capital Investment

(TCI)=(DC)+(IC)+(GRT)+(PC) $17,391,600 $17,163,500

Privileged & Confidential

San Juan Units 1 and 4

SNCR Cost Estimate

SNCR COST ANALYSIS
Unit 1 Unit 4

Capacity (MWg) 370 544

Capacity (MWn) 327 507

Maximum Heat Input (MMBtu/hr) 3707 5649

Annual Capacity Factor (%) 85% 85%

Baseline NOx Emission Rate (lb/MMBtu) 0.30 0.30

Baseline NOx Emission Rate (lb/hr) 1112.1 1694.7

Controlled NOx Emission Rate (lb/MMBtu) 0.23 0.23

Controlled NOx Emission Rate (lb/hr) 852.6 1299.3

Cost Item UNIT 1 UNIT 4 Remarks/Cost Basis

Privileged & Confidential

San Juan Units 1 and 4

SNCR Cost Estimate

SNCR COST ANALYSIS

ANNUAL COST 

Direct Annual Costs 

Fixed annual costs 

Operating labor $0 $0 Assumed no operating labor for the SNCR

Annual Maintenance Cost $260,900 $257,500 TCI X 1.5% [EPA Cost Manual Section 4.2, Chapter 1, Eqn.1.21]

Total fixed annual costs $260,900 $257,500

Variable annual costs 

Reagent Consumption $3,353,700 $6,177,200 Based on 225.2 gph (Unit 1) and 414.8 gph (Unit 4) (50% urea solution) per Fuel Tech 

Proposal 11-B-122, Rev.1, 07-10-2012. Assumes $2.0/gal and 85% CF.

Water Consumption $134,000 $150,100 Based on 50 gpm (Unit 1) and 56 gpm (Unit 4) per Fuel Tech Proposal 11-B-122, Rev.1, 07-

10-2012. Assumes $6/1000 gal and 85% CF.

Power Requirement $42,700 $51,000 Based on 155 kW (Unit 1) and 185 kw (Unit 4) per per Fuel Tech Proposal 11-B-122, Rev.1, 

07-10-2012 and S&L BOP estimate. Assumes $37/MWh and 85% CF.

Total variable annual costs $3,530,400 $6,378,300

Total direct annual costs (DAC) $3,791,300 $6,635,800

Indirect Annual Costs 

Cost for capital recovery $1,609,000 $1,588,000 (TCI) X 9.25% CRF at 8.44% interest & 30 year life 

Total indirect annual costs (IDAC) $1,609,000 $1,588,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $5,400,300 $8,223,800

Emission Reductions (ton/yr) 966 1,472 Based on baseline NOx rate of 0.30 lb/MMBtu and controlled rate of 0.23 lb/MMBtu

Cost Effectiveness ($/ton) 5,590 5,587

Cost ($/kW) 47.0 31.6
Basis: S&L Cost Estimte 31803B (3/21/2012)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

DIRECT & CONSTRUCTION INDIRECT COST

11 Demolition & Relocation $0 $16,000 $16,00021 Civil Work $15,100 $15,100

22 Concrete $140,100 $244,300 $384,40023 Steel $129,100 $171,800 $300,90024 Architectural27 Painting & Coating $10,000 $15,200 $25,200

31-17, 31-

53 Mechanical Equipment $2,390,300 $0 $295,900 $2,686,200

31-53-1 SNCR System $1,730,300 $267,400 $1,997,700

31-53-2 CFD Model Study $150,000 $150,00031-53-3 Boiler Tuning $150,000 $150,000

31-17 Air Compressor & Accessories $360,000 $28,500 $388,500

35 Piping $547,900 $1,859,500 $2,407,40036 Insulation $28,800 $74,200 $103,00041 Electrical Equipment $87,500 $149,400 $444,500 $681,40042 Raceway, Cable Tray & Conduit $32,500 $53,500 $86,00043 Cable $30,100 $105,100 $135,20044 Control & Instrumentation $130,000 $131,100 $261,100

SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,607,800 $1,067,900 $3,426,200 $7,101,900Other Direct & Construction Indirects

91-1 Scaffolding $122,800 $122,800

31-99 Boiler Injection Port Installation $60,000 $23,000 $393,400 $476,400

91-2A Overtime: 5 - 10 hr days $449,700 $449,700

91-2B Overtime: 6 - 10 hr days $125,900 $125,900

91-4 Consumables $24,600 $24,60091-5 Freight on Material $54,500 $54,500

 SUBTOTAL $60,000 $77,500 $1,116,400 $1,253,900

92 TOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,667,800 $1,145,400 $4,542,600 $8,355,800

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 1
Basis: S&L Cost Estimte 31803B (3/21/2012)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 1

INDIRECT COST

93-1A Owner's Engineering $167,100 

93-1B EPC Engineering $501,300 

93-2 Construction Management $167,100 93-3 Startup Commissioning $83,600 

93-4 Owner's Cost $0

93-5 EPC Fee (% of Total Directs, Indirects) $1,391,200 

93 TOTAL INDIRECT COST $2,310,300

Total EscalationContingency

95-1 Contingency on Equipment $266,800 95-2 Contingency on Material $229,100 95-3 Contingency on Labor $908,500 95-4 Contingency on Indirect $462,100 

95 Total Contingency $1,866,500

TOTAL CONSTRUCTION COST $12,532,600

97 Interest During Construction $0

TOTAL PROJECT COST $12,532,600
Basis: S&L Cost Estimte 31803B (3/21/2011)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

DIRECT & CONSTRUCTION INDIRECT COST

11 Demolition & Relocation $0 $16,000 $16,00021 Civil Work $15,100 $15,100

22 Concrete $140,100 $244,300 $384,40023 Steel $129,100 $171,800 $300,90024 Architectural27 Painting & Coating $10,000 $15,200 $25,200

31-17, 31-

53 Mechanical Equipment $2,390,300 $0 $295,900 $2,686,200

31-53-1 SNCR System $1,730,300 $267,400 $1,997,700

31-53-2 CFD Model Study $150,000 $150,00031-53-3 Boiler Tuning $150,000 $150,000

31-17 Air Compressor & Accessories $360,000 $28,500 $388,500

35 Piping $547,900 $1,859,500 $2,407,40036 Insulation $28,800 $74,200 $103,00041 Electrical Equipment $87,500 $149,400 $444,500 $681,40042 Raceway, Cable Tray & Conduit $32,500 $53,500 $86,00043 Cable $30,100 $105,100 $135,20044 Control & Instrumentation $130,000 $131,100 $261,100

SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,607,800 $1,067,900 $3,426,200 $7,101,900Other Direct & Construction Indirects

91-1 Scaffolding $122,800 $122,800

31-99 Boiler Injection Port Installation $60,000 $23,000 $393,400 $476,400

91-2A Overtime: 5 - 10 hr days $449,700 $449,700

91-2B Overtime: 6 - 10 hr days $125,900 $125,900

91-4 Consumables $24,600 $24,60091-5 Freight on Material $54,500 $54,500

 SUBTOTAL $60,000 $77,500 $1,116,400 $1,253,900

92 TOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,667,800 $1,145,400 $4,542,600 $8,355,800

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 2
Basis: S&L Cost Estimte 31803B (3/21/2011)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 2

INDIRECT COST

93-1A Owner's Engineering $167,100 

93-1B EPC Engineering $501,300 

93-2 Construction Management $167,100 93-3 Startup Commissioning $83,600 

93-4 Owner's Cost $0

93-5 EPC Fee (% of Total Directs, Indirects) $1,391,200 

93 TOTAL INDIRECT COST $2,310,300

Total EscalationContingency

95-1 Contingency on Equipment $266,800 95-2 Contingency on Material $229,100 95-3 Contingency on Labor $908,500 95-4 Contingency on Indirect $462,100 

95 Total Contingency $1,866,500

TOTAL CONSTRUCTION COST $12,532,600

97 Interest During Construction $0

TOTAL PROJECT COST $12,532,600
Basis: S&L Cost Estimte 31804B (11/1/2012)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

DIRECT & CONSTRUCTION INDIRECT COST

11 Demolition & Relocation $15,000 $35,700 $50,70021 Civil Work $16,600 $16,600

22 Concrete $178,800 $304,500 $483,30023 Steel $113,500 $138,800 $252,30024 Architectural27 Painting & Coating $200 $7,300 $7,500

31-17, 31-

53 Mechanical Equipment $2,384,000 $0 $429,700 $2,813,700

31-53-1 SNCR System $1,724,000 $401,200 $2,125,200

31-53-2 CFD Model Study $150,000 $150,00031-53-3 Boiler Tuning $150,000 $150,000

31-17 Air Compressor & Accessories $360,000 $28,500 $388,500

35 Piping $508,500 $1,586,800 $2,095,30036 Insulation $25,900 $71,900 $97,80041 Electrical Equipment $87,500 $135,200 $408,200 $630,90042 Raceway, Cable Tray & Conduit $37,200 $60,200 $97,40043 Cable $34,300 $121,700 $156,00044 Control & Instrumentation $130,000 $131,100 $261,100

SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,601,500 $1,048,600 $3,312,500 $6,962,600Other Direct & Construction Indirects

91-1 Scaffolding $120,000 $120,000

31-99 Boiler Injection Port Installation $48,000 $35,000 $402,200 $485,200

91-2A Overtime: 5 - 10 hr days $431,300 $431,300

91-2B Overtime: 6 - 10 hr days $135,400 $135,400

91-4 Consumables $24,000 $24,00091-5 Freight on Material $54,200 $54,200

 SUBTOTAL $48,000 $89,200 $1,112,900 $1,250,100

92 TOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,649,500 $1,137,800 $4,425,400 $8,212,700

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 3
Basis: S&L Cost Estimte 31804B (11/1/2012)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 3

INDIRECT COST

93-1A Owner's Engineering $164,300 

93-1B EPC Engineering $492,800 

93-2 Construction Management $164,300 93-3 Startup Commissioning $82,100 

93-4 Owner's Cost $0

93-5 EPC Fee (% of Total Directs, Indirects) $1,367,400 

93 TOTAL INDIRECT COST $2,270,900

Total EscalationContingency

95-1 Contingency on Equipment $265,000 95-2 Contingency on Material $227,600 95-3 Contingency on Labor $885,100 95-4 Contingency on Indirect $454,200 

95 Total Contingency $1,831,900

TOTAL CONSTRUCTION COST $12,315,500

97 Interest During Construction $0

TOTAL PROJECT COST $12,315,500
Basis: S&L Cost Estimte 31804B (11/1/2012)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

DIRECT & CONSTRUCTION INDIRECT COST

11 Demolition & Relocation $15,000 $35,700 $50,70021 Civil Work $16,600 $16,600

22 Concrete $178,800 $304,500 $483,30023 Steel $113,500 $138,800 $252,30024 Architectural27 Painting & Coating $200 $7,300 $7,500

31-17, 31-

53 Mechanical Equipment $2,384,000 $0 $429,700 $2,813,700

31-53-1 SNCR System $1,724,000 $401,200 $2,125,200

31-53-2 CFD Model Study $150,000 $150,00031-53-3 Boiler Tuning $150,000 $150,000

31-17 Air Compressor & Accessories $360,000 $28,500 $388,500

35 Piping $508,500 $1,586,800 $2,095,30036 Insulation $25,900 $71,900 $97,80041 Electrical Equipment $87,500 $135,200 $408,200 $630,90042 Raceway, Cable Tray & Conduit $37,200 $60,200 $97,40043 Cable $34,300 $121,700 $156,00044 Control & Instrumentation $130,000 $131,100 $261,100

SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,601,500 $1,048,600 $3,312,500 $6,962,600Other Direct & Construction Indirects

91-1 Scaffolding $120,000 $120,000

31-99 Boiler Injection Port Installation $48,000 $35,000 $402,200 $485,200

91-2A Overtime: 5 - 10 hr days $431,300 $431,300

91-2B Overtime: 6 - 10 hr days $135,400 $135,400

91-4 Consumables $24,000 $24,00091-5 Freight on Material $54,200 $54,200

 SUBTOTAL $48,000 $89,200 $1,112,900 $1,250,100

92 TOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,649,500 $1,137,800 $4,425,400 $8,212,700

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 4
Basis: S&L Cost Estimte 31804B (11/1/2012)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 4

INDIRECT COST

93-1A Owner's Engineering $164,300 

93-1B EPC Engineering $492,800 

93-2 Construction Management $164,300 93-3 Startup Commissioning $82,100 

93-4 Owner's Cost $0

93-5 EPC Fee (% of Total Directs, Indirects) $1,367,400 

93 TOTAL INDIRECT COST $2,270,900

Total EscalationContingency

95-1 Contingency on Equipment $265,000 95-2 Contingency on Material $227,600 95-3 Contingency on Labor $885,100 95-4 Contingency on Indirect $454,200 

95 Total Contingency $1,831,900

TOTAL CONSTRUCTION COST $12,315,500

97 Interest During Construction $0

TOTAL PROJECT COST $12,315,500
Basis: S&L Cost Estimte 31807B (11/1/2011)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

DIRECT & CONSTRUCTION INDIRECT COST

11 Demolition & Relocation $15,000 $35,700 $50,70021 Civil Work $195,000 $8,400 $203,40022 Concrete $39,000 $67,600 $106,600

23 Steel $024 Architectural $705,000 $519,500 $1,224,50027 Painting & Coating $1,000 $24,400 $25,400

31 Mechanical Equipment $855,000 $7,200 $158,500 $1,020,700

31-45 Fire Protection $7,200 $3,000 $10,200

31-75 Pumps $60,000 $10,600 $70,60031-83 Tanks $45,000 $7,900 $52,90031-93 Dilution Water Treatement System $750,000 $137,000 $887,000

35 Piping $58,100 $137,300 $195,40036 Insulation $4,200 $10,300 $14,50041 Electrical Equipment $117,600 $238,100 $382,800 $738,50042 Raceway, Cable Tray & Conduit $149,700 $468,000 $617,70043 Cable $126,900 $355,900 $482,80044 Control & Instrumentation $30,000 $77,800 $107,800

SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $1,197,600 $1,344,200 $2,246,200 $4,788,000Other Direct & Construction Indirects

91-1 Scaffolding $90,600 $90,600

31-99 Boiler Injection Port Installation $0

91-2A Overtime: 5 - 10 hr days $302,600 $302,600

91-2B Overtime: 6 - 10 hr days $0

91-4 Consumables $18,100 $18,10091-5 Freight on Material $67,300 $67,300

 SUBTOTAL $0 $67,300 $411,300 $478,600

92 TOTAL DIRECT & CONSTRUCTION INDIRECT COST $1,197,600 $1,411,500 $2,657,500 $5,266,600

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Common Areas (Units 1 & 3)
Basis: S&L Cost Estimte 31807B (11/1/2011)

Acct. No. Description Equipment Cost Material Cost Labor Cost Total 

Detailed SNCR Cost Estimate Summary - San Juan Generating Station Common Areas (Units 1 & 3)

INDIRECT COST

93-1A Owner's Engineering $105,300 

93-1B EPC Engineering $316,000 

93-2 Construction Management $105,300 93-3 Startup Commissioning $52,700 

93-4 Owner's Cost $0

93-5 EPC Fee (% of Total Directs, Indirects) $876,900 

93 TOTAL INDIRECT COST $1,456,200

Total EscalationContingency

95-1 Contingency on Equipment $119,800 95-2 Contingency on Material $282,300 95-3 Contingency on Labor $531,500 95-4 Contingency on Indirect $291,200 

95 Total Contingency $1,224,800

TOTAL CONSTRUCTION COST $7,947,600

97 Interest During Construction $0

TOTAL PROJECT COST $7,947,600
Project No. 11278-034 

SAN JUAN GENERATING STATION 03/29/2013 

SNCR AND SCR COST ESTIMATES Page 23 

ATTACHMENT B.

SAN JUAN GENERATING STATION

UNITS 1 & 2 

SCR COST ESTIMATES
Unit 1 Unit 2

Capacity (MW-gross) 370 370

Capacity (MW-net) 327 327

Maximum Heat Input (MMBtu/hr) 3,707 3,688

Annual Capacity Factor (%) 85% 85%

Baseline NOx Emission Rate (lb/MMBtu) 0.30 0.30 Adjusted to match Dec. 2012 SNCR Cost Estimate

Baseline NOx Emission Rate (lb/hr) 1,112.1 1,106.4

Controlled NOx Emission Rate (lb/MMBtu) 0.05 0.05

Controlled NOx Emission Rate (lb/hr) 185.4 184.4

Cost Item Unit 1 Unit 2 Remarks/Cost Basis

CAPITAL COST 

S&L Cost Estaimtes 31326C (Unit 1 SCR); 31327C (Unit 2 SCR); 31328C (Unit 1 

& 2 SCR Common Equipment). Common equipment costs were split equally 

between the two units.

Direct Costs 

Purchased Equipment Costs

SCR and Economizer Bypass $14,910,900 $14,910,900 Acct. Nos. A-31

Sorbent Injection System $880,000 $880,000 Acct. Nos. B-31

Baghouse Handling System $875,000 $875,000 Acct. Nos. C-33

Anhydrous Ammonia System $601,500 $601,500 Acct. Nos. D-31

Electrical Equipment $2,775,100 $2,775,100 Acct. Nos. E-41, E-42, E-43

Instrumentation and Control System $1,039,000 $1,039,000 Acct. Nos. E-44

Substation and Switchyard Equipmenet $200,000 $200,000 Acct. Nos. E-51

Flue Gas - Gas Pass Upgrades for SCR

 Mechanical Equipment $2,768,100 $2,768,100

 Electrical Equipment $5,777,800 $5,777,800

 Instrumentation & Controls $392,000 $392,000

 345 kV Substation Modifications $470,400 $470,400

Balanced Draft Conversion

 Mechanical Equipment $692,000 $692,000

 Electrical Equipment $1,444,400 $1,444,400

 Instrumentation & Controls $98,000 $98,000

Subtotal Equipment Costs (EC) $32,924,200 $32,924,200

Freight on Materials $1,138,600 $1,153,100 Acct. Nos. 91-5 

Total Purchased Equipment Cost (PEC) $34,062,800 $34,077,300 Equipment Costs + Freight

Direct Installation Costs

Site Preparation

 SCR Area and Economizer Bypass $785,100 $785,100 Acct. Nos. A-11 and A-21 (Demolition and Civil Work)

 Sorbent Injection System $27,000 $27,000 Acct. Nos. B-21 (Civil Work)

 Baghouse Ash Handling System $27,800 $24,700 Acct. Nos. C-21 (Civil Work)

 Flue Gas - Gas Pass Upgrades for SCR $22,000 $22,000 Applied 80% of Acct. Nos. F-21 and F-25 (Civil Work/Trenching) to SCR Project

 Balanced Draft Conversion $5,500 $5,500 Applied 20% of Acct. Nos. F-21 and F-25 (Civil Work/Trenching) to Balance Draft

Foundations & Supports

 SCR Area and Economizer Bypass $14,259,500 $14,506,100 Acct. Nos. A-22 and A-23 (Concrete and Steel)

 Sorbent Injection System $24,600 $24,600 Acct. Nos. B-22 and B-23 (Concrete and Steel)

 Baghouse Ash Handling System $23,500 $18,000 Acct. Nos. C-23 (Steel)

 Flue Gas - Gas Pass Upgrades for SCR $118,200 $24,700 Applied 80% of Acct. Nos. D-22 and D-23 (Concrete/Steel) to SCR Project

 Balanced Draft Conversion $29,600 $6,200 Applied 20% of Acct. Nos. D-22 and D-23 (Concrete/Steel) to Balanced Draft

Handling & Erection (Includes Labor Costs)

 SCR Area and Economizer Bypass $33,266,300 $44,433,200 Acct. Nos. A-11 through A-36 Labor Costs*

 Sorbent Injection System $122,400 $185,500 Acct. Nos. B-21 through B-36 Labor Costs

 Baghouse Ash Handling System $748,300 $753,500 Acct. Nos. C-21 through C-35 Labor Costs

 Anhydrous Ammonia System $229,700 $465,400 Acct. Nos. D-21 through D-35 Labor Costs

 Electrical $4,538,900 $4,538,900 Acct. Nos. E-41 through E-51 Labor Costs

 Flue Gas - Gas Pass Upgrades for SCR $5,223,500 $5,223,500 Applied 80% of Acct. Nos. F-21 through F-51 (Labor Costs) to SCR Project

 Balanced Draft Conversion $1,305,900 $1,305,900 Applied 20% of Acct. Nos. F-21 through F-51 (Labor Costs) to Balanced Draft

Piping $186,200 $231,000 Acct. Nos. A-35, B-35, D-35

Insulation $1,033,400 $1,034,500 Acct. Nos. A-36 and B-36

Scaffolding $1,749,100 $2,022,000 Acct. Nos. 91-1

Cost Due to Overtime $5,327,900 $6,527,600 Acct. Nos. 91-2A (working 5 - 10 hour days)

Cost Due to Overtime $3,993,600 $4,892,900 Acct. Nos. 91-2B (working 7 -12 hour days during the tie-in)

Per Diem $0 $0 Not Included

Consumables $349,800 $404,400 Acct. Nos. 91-4

Contractor G&A Expenses $0 $0 Included in EPC Fee

Contractor Profit $0 $0 Included in EPC Fee

Total Direct Installation Costs (DIC) $73,397,800 $87,462,200

Total Direct Costs (DC) = (PEC) + (DIC) $107,460,600 $121,539,500

Privileged & Confidential

San Juan Units 1 & 2

SCR Cost Estimate

SCR COST ANALYSIS

Applied 80% of Acct. Nos. F-31, F-41, F-42, F-43, F-44, and F-51 (Equipment and 

Material Costs) to gas pass upgrades required for the SCR Project.

Applied 20% of Acct. Nos. F-31, F-41, F-42, F-43, F-44, and F-51 (Equipment and 

Material Costs) to account for additional gas pass upgrades that would be required 

for Balanced Draft Conversion.
Privileged & Confidential

San Juan Units 1 & 2

SCR Cost Estimate

Indirect Costs 

EPC Engineering, Procurement and Project Services $8,720,400 $9,788,900 Acct. Nos. 93-1

EPC Construction Management Support $3,270,200 $3,670,900 Acct. Nos. 93-2

EPC Startup Commissioning $1,090,100 $1,223,700 Acct. Nos. 93-3

EPC Fee $18,312,800 $20,556,700 Acct. Nos. 93-4

Architectural $250,000 $250,000 Acct. Nos. A-24

Owner's Engineer & Construction Management $3,777,100 $3,777,100 Acct. Nos. 93-5-1

Performance Testing $100,000 $100,000 Acct. Nos. 93-5-2

Total Indirect Costs (IC) $35,520,600 $39,367,300

New Mexico Gross Receipt Tax (GRT) $9,025,700 $10,157,200 (DC + IC) X 6.3125% 

Project Contingency (PC) $28,854,900 $32,295,900 Acct. Nos. 95

Total Capital Investment (DC + IC + GRT + PC) $180,861,800 $203,359,900

ANNUAL COST 

Direct Annual Costs 

Fixed Annual Costs

Operating Labor $0 $0 Assumed no additional operating labor for the SCR

Maintenance Labor & Materials $2,712,900 $3,050,400 TCI X 1.5% [EPA Cost Manual Section 4.2, Chapter 2, Eqn. 2.46]

Annual Emissions Testing $25,000 $25,000

Catalyst Activity Testing $5,000 $5,000

Fly Ash Sampling and Analysis $20,000 $20,000

Total Fixed Annual Costs $2,762,900 $3,100,400

Variable Annual Costs 

Reagent Consumption (Ammonia) $1,051,000 $1,045,600

Reagent Consumption (DSI) $22,800 $22,800

Auxiliary & ID Fan Power $745,800 $728,600

Steam Cost $72,400 $72,400

Water Cost $0 $0

Catalyst Replacement Cost $773,000 $773,000

Total Variable Annual Costs $2,665,000 $2,642,400

Total Direct Annual Costs (DAC) $5,427,900 $5,742,800

Indirect Annual Costs 

Capital Recovery Factor (CRF) 0.0925 0.0925 Calculated using 8.44% interest and 30 year equipment life

Cost for Capital Recovery $16,737,000 $18,819,000 TCI x CRF

Total Indirect Annual Costs (IDAC) $16,737,000 $18,819,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $22,164,900 $24,561,800

Baseline Annual Emissions (tpy) 4,140 4,119

Project Post-Project Annual Emissions (tpy) 690 687

Emission Reductions (ton/yr) 3,450 3,432

Cost Effectiveness ($/ton) $6,425 $7,157

Cost ($/kW) $489 $550

Interest Rate 8.44%

Equipment Economic Life 30

CRF 0.0925

*Note: A cost premium of approximately 40% was included in the Unit 2 SCR labor costs (sub-account A-23 including ductwork between the economizer outlet and SCR 

inlet, SCR outlet and AH inlet, SCR reactor boxes, and support framing) to account for the significant site restrictions and congestion around the Unit 2 SCR compared to the 

Unit 1 SCR.

See, O&M Cost Worksheet
SCR O&M Costs

SJGS Unit 1 SJGS Unit 2

SCR Type High Dust High Dust

Plant Gross Capacity MW 370.0 370.0

Capacity Factor % 85.00 85.00

NOx Control Rate lb/MMBtu 0.050 0.050

Average NOx Inlet lb/MBtu 0.30 0.30

Current Technology LNB/Neural Network LNB/Neural Network

Required Efficiency (Average) % 83.33 83.33

Fuel New Mexico Bituminous New Mexico Bituminous

Heat Input to Boiler at Full Load Btu/hr 3.707E+09 3.688E+09

Fuel Heating Value Btu/lb 9,502 9,502

Reagent Anhydrous Ammonia Anhydrous Ammonia

Average NH3 Consumption lb NH3/hr 360 358

Average Reagent Consumption tpy 1,339 1,332

Ammonia Cost $/dry ton 785 785

Auxiliary Power Cost $/MWhr 37 37

Water Cost $/1000 gal 6 6

Steam Cost $/MMBtu 5 5

Catalyst replacement $/m3 8,000 8,000

Hydrated Lime Cost $/ton 120 120

Initial Catalyst Volume m3 604 604

Initial Catalyst Layers 3 3

Catalyst replacement cycle yrs 2 2

Flue Gas Flow acfm 2,056,400 1,999,900

Pressure Drop in 8 8

Increase in Auxiliary Power Consumption - 

Full Load kW 2,707 2,645

Increase in Water Consumption gph 0 0

Steam Usage MMBtu/hr 1,556 1,556

Steam Quality MMBtu/lb 1,249 1,249

Dry Sorbent Injection lb/hr 51 51

Variable O&M Cost:

Ammonia Cost $/yr $1,051,000 $1,045,600

Catalyst Replacement Future Worth Factor 0.48 0.48

Catalyst Replacement Cost* $/yr $773,000 $773,000

Auxiliary Power Cost $/yr $745,800 $728,600

Steam Cost $/yr $72,400 $72,400

Water Cost $/yr $0 $0

Dry Sorbent Cost $/yr $22,800 $22,800

Total variable O&M Cost $/yr $2,665,000 $2,642,400

* Catalyst replacement costs were calculated based on replacing 1 layer of catalyst (approx. 202 m3) once every two 

years. Catalyst costs were calculated by multiplying the volume of catalyst by the installed unit cost of $8,000/m3 and 

using a future worth factor of 0.48 calculated as follows:

FWF = i * [ 1 / (1 + i)y - 1]; 

where i = an assumed interest rate of 8.44% and y = 2 (i.e., replacing one layer every other year.

See, Control Cost Manual, Section 4.2, Chapter 2, pg. 2-47
Basis: S&L Cost Estimte 31326C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 1 Notes

A-11 Demolition $100,000 $0 $1,985,300 $2,085,300A-21 Civil Work $638,500 $46,600 $39,300 $724,400A-22 Concrete $0 $77,000 $127,500 $204,500A-23 Steel $0 $14,157,400 $25,544,300 $39,701,700A-31 Mechanical Equipment $10,805,900 $4,030,000 $3,284,400 $18,120,300A-35 Piping $0 $105,700 $363,300 $469,000A-36 Insulation $0 $1,032,000 $1,821,700 $2,853,700

A. Total $11,544,400 $19,448,700 $33,165,800 $64,158,900

B-21 Civil Work $27,000 $0 $800 $27,800B-22 Concrete $0 $6,600 $10,100 $16,700B-23 Steel $0 $18,000 $45,700 $63,700B-31 Mechanical Equipment $880,000 $0 $0 $880,000B-35 Piping $0 $10,900 $63,500 $74,400B-36 Insulation $0 $1,400 $2,300 $3,700

B. Total $907,000 $36,900 $122,400 $1,066,300

C-21 Civil Work $0 $27,800 $41,500 $69,300C-23 Steel $0 $23,500 $24,300 $47,800C-33 Material Handling Equipment $875,000 $0 $682,500 $1,557,500C-35 Piping $0 $0 $0 $0

C. Total $875,000 $51,300 $748,300 $1,674,600

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 1

A. SCR Area and Economizer BypassB. Sorbent Injection SystemC. Baghouse Ash Handling System
Basis: S&L Cost Estimte 31326C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 1 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 1

D-31 Mechanical Equipment $181,000 $0 $16,300 $197,300D-35 Piping $0 $69,600 $176,300 $245,900

D. Total $181,000 $69,600 $192,600 $443,200

E-41 Electrical Equipment $1,194,500 $158,400 $711,500 $2,064,400E-42 Cable Tray $0 $368,400 $999,700 $1,368,100E-43 Cable $0 $1,053,800 $2,401,700 $3,455,500E-44 Control & Instrumentation $1,039,000 $0 $426,000 $1,465,000E-51 Substation, Switchyard & Transmission Line $200,000 $0 $0 $200,000

E. Total $2,433,500 $1,580,600 $4,538,900 $8,553,000

F-21 Civil Work $0 $27,200 $105,000 $132,200F-22 Concrete $0 $116,900 $262,800 $379,700F-23 Steel $0 $30,900 $29,700 $60,600F-31 Mechanical Equipment $3,340,100 $120,000 $2,590,400 $6,050,500F-41 Electrical Equipment $4,329,000 $1,053,200 $1,542,100 $6,924,300F-42 Raceway, Cable Tray & Conduit $660,000 $0 $1,400,400 $2,060,400F-43 Medium Voltage Power Cable & Termination $0 $114,900 $195,000 $309,900F-44 Control & Instrumentation $490,000 $0 $84,000 $574,000

F. Total $8,819,100 $1,463,100 $6,209,400 $16,491,600G. Total $1,757,600 $1,757,600

90 Subtotal $24,760,000 $22,650,200 $46,735,000 $94,145,200

G. Construction Equipment SupplementD. Anhydrous AmmoniaE. ElectricalF. Balanced Draft Conversion
Basis: S&L Cost Estimte 31326C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 1 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 1

91 Other Direct & Construction Indirect Costs

91-1 Scaffolding $1,734,600 $1,734,600 2.5% of Ac

91-2A Cost Due to overtime working 5 - 10 hour days $5,276,200 $5,276,200

91-2B Cost Due to overtime working 7 - 12 hour days during the tie-in

outage $3,954,800 $3,954,800

91-3 Per Diem $0 Not Includ91-4 Consumables $346,900 $346,900 0.5% of Ac91-5 Freight on materials $1,132,500 $1,132,500 5% of Acct91-7 Sales Tax $0 Not Includ91-9 Contractor G&A Expenses $0 Included in 

91-10 Contractor Profit $0 Included in 

91. Subtotal $0 $1,132,500 $11,312,500 $12,445,000

92 Total Direct & Construction Indirect Cost $24,760,000 $23,782,700 $58,047,500 $106,590,20093 Indirect Costs

93-1 EPC Engineering, Procurement & Project Services $8,527,200 8% of Acct

93-2 EPC Construction Management Support $3,197,700 3% of Acct93-3 EPC Startup Commissioning $1,065,900 1% of Acct93-4 EPC Fee $17,907,200 15% of Ac93-5 Owner's Costs $0

93-5-1 Owner's Engineer & Construction Management $3,777,100 By PNM93-5-2 Performance Testing $100,00093-5-3 Anhydrous Ammonia Risk Management & Training $0

93. Total $34,575,100
Basis: S&L Cost Estimte 31326C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 1 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 1

94 Total Escalation95 Total Contingency $28,233,000 20% of 92 96 Total Construction Cost $169,398,300

96A New Mexico Gross Receipt Tax (NMGRT) $10,693,300

96B Total Construction Cost with NMGRT $180,091,600

97 Interest During Construction Not Includ

97A Lost Generation During Extended Outage Not Includ

98 TOTAL PROJECT COST $180,091,600
Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 2 Notes

A-11 Demolition $100,000 $0 $1,985,300 $2,085,300A-21 Civil Work $638,500 $46,600 $39,300 $724,400A-22 Concrete $0 $77,000 $127,500 $204,500A-23 Steel $0 $14,404,000 $36,711,200 $51,115,200A-31 Mechanical Equipment $10,805,900 $4,030,000 $3,284,400 $18,120,300A-35 Piping $0 $105,700 $363,300 $469,000A-36 Insulation $0 $1,032,000 $1,821,700 $2,853,700

A. Total $11,544,400 $19,695,300 $44,332,700 $75,572,400

B-21 Civil Work $27,000 $0 $800 $27,800B-22 Concrete $0 $6,600 $10,100 $16,700B-23 Steel $0 $18,000 $64,000 $82,000B-31 Mechanical Equipment $880,000 $0 $0 $880,000B-35 Piping $0 $18,400 $106,600 $125,000B-36 Insulation $0 $2,500 $4,000 $6,500

B. Total $907,000 $45,500 $185,500 $1,138,000

C-21 Civil Work $0 $24,700 $36,900 $61,600C-23 Steel $0 $23,500 $34,100 $57,600C-33 Material Handling Equipment $875,000 $0 $682,500 $1,557,500C-35 Piping $0 $0 $0 $0

C. Total $875,000 $48,200 $753,500 $1,676,700

A. SCR Area and Economizer BypassB. Sorbent Injection SystemC. Baghouse Ash Handling System

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 2
Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 2 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 2

D-31 Mechanical Equipment $181,000 $0 $16,300 $197,300D-35 Piping $0 $106,900 $412,000 $518,900

D. Total $181,000 $106,900 $428,300 $716,200

E-41 Electrical Equipment $1,194,500 $158,400 $711,500 $2,064,400E-42 Cable Tray $0 $368,400 $999,700 $1,368,100E-43 Cable $0 $1,053,800 $2,401,700 $3,455,500E-44 Control & Instrumentation $1,039,000 $0 $426,000 $1,465,000E-51 Substation, Switchyard & Transmission Line $200,000 $0 $0 $200,000

E. Total $2,433,500 $1,580,600 $4,538,900 $8,553,000

F-21 Civil Work $0 $27,200 $105,000 $132,200F-22 Concrete $0 $116,900 $262,800 $379,700F-23 Steel $0 $30,900 $29,700 $60,600F-31 Mechanical Equipment $3,340,100 $120,000 $2,590,400 $6,050,500F-41 Electrical Equipment $4,329,000 $1,053,200 $1,542,100 $6,924,300F-42 Raceway, Cable Tray & Conduit $660,000 $0 $1,400,400 $2,060,400F-43 Medium Voltage Power Cable & Termination $0 $114,900 $195,000 $309,900F-44 Control & Instrumentation $490,000 $0 $84,000 $574,000

F. Total $8,819,100 $1,463,100 $6,209,400 $16,491,600G. Total $912,900 $912,900

90 Subtotal $24,760,000 $22,939,600 $57,361,200 $105,060,800

D. Anhydrous AmmoniaE. ElectricalF. Balanced Draft ConversionG. Construction Equipment Supplement
Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 2 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 2

91 Other Direct & Construction Indirect Costs

91-1 Scaffolding $2,007,500 $2,007,500 2.5% of 

91-2A Cost Due to overtime working 5 - 10 hour days $6,475,900 $6,475,900

91-2B Cost Due to overtime working 7 - 12 hour days during the tie-in 

outage $4,854,100 $4,854,100

91-3 Per Diem $0 Not Incl91-4 Consumables $401,500 $401,500 0.5% of 91-5 Freight on materials $1,147,000 $1,147,000 5% of A91-7 Sales Tax $0 Not Incl91-9 Contractor G&A Expenses $0 Included 

91-10 Contractor Profit $0 Included 

91. Subtotal $0 $1,147,000 $13,739,000 $14,886,000

92 Total Direct & Construction Indirect Cost $24,760,000 $24,086,600 $71,100,200 $119,946,80093 Indirect Costs

93-1 EPC Engineering, Procurement & Project Services $9,595,700 8% of A93-2 EPC Construction Management Support $3,598,400 3% of A93-3 EPC Startup Commissioning $1,199,500 1% of A93-4 EPC Fee $20,151,100 15% of A93-5 Owner's Costs $0

93-5-1 Owner's Engineer & Construction Management $3,777,100 By PNM93-5-2 Performance Testing $100,00093-5-3 Anhydrous Ammonia Risk Management & Training $0

93. Total $38,421,800
Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 2 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 2

94 Total Escalation95 Total Contingency $31,674,000 20% of 996 Total Construction Cost $190,042,600

96A New Mexico Gross Receipt Tax (NMGRT) $11,996,400

96B Total Construction Cost with NMGRT $202,039,000

97 Interest During Construction Not Incl

97A Lost Generation During Extended Outage Not Incl

98 TOTAL PROJECT COST $202,039,000
Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Units 1 & 2 Common Notes

A-22 Concrete $0 $13,300 $20,000 $33,300A-23 Steel $0 $36,900 $43,300 $80,200A-24 Architectural $500,000 $0 $123,200 $623,200A-31 Mechanical Equipment $150,000 $0 $14,500 $164,500

A. Total $650,000 $50,200 $201,000 $901,200

D-21 Civil Work $0 $0 $0 $0D-22 Concrete $0 $13,800 $23,000 $36,800D-31 Mechanical Equipment $841,000 $0 $51,200 $892,200

D. Total $841,000 $13,800 $74,200 $929,000

F-21 Civil Work $0 $0 $0 $0F-25 Earthwork, Excavation, Trench $0 $500 $2,300 $2,800F-35 Piping $0 $0 $0 $0F-41 Electrical Equipment $875,000 $79,100 $300,800 $1,254,900F-51 345kV Substation & Transmission Line $1,075,300 $100,800 $336,800 $1,512,900

F. Total $1,950,300 $180,400 $639,900 $2,770,600

90 Subtotal $3,441,300 $244,400 $915,100 $4,600,800

D. Anhydrous AmmoniaF. Balanced Draft ConversionA. SCR Area and Economizer Bypass

Detailed SCR Cost Estimate Summary - San Juan Generating Station Units 1 & 2 Common
Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Units 1 & 2 Common Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Units 1 & 2 Common

91 Other Direct & Construction Indirect Costs

91-1 Scaffolding $29,000 $29,000 2.5% of 

91-2A Cost Due to overtime working 5 - 10 hour days $103,300 $103,300

91-2B Cost Due to overtime working 7 - 12 hour days during the tie-in 

outage $77,500 $77,500

91-3 Per Diem $0 Not Incl91-4 Consumables $5,800 $5,800 0.5% of 91-5 Freight on materials $12,200 $12,200 5% of A91-7 Sales Tax $0 Not Incl91-9 Contractor G&A Expenses $0 Included 

91-10 Contractor Profit $0 Included 

91. Subtotal $0 $12,200 $215,600 $227,800

92 Total Direct & Construction Indirect Cost $3,441,300 $256,600 $1,130,700 $4,828,60093 Indirect Costs

93-1 EPC Engineering, Procurement & Project Services $386,300 8% of A93-2 EPC Construction Management Support $144,900 3% of A93-3 EPC Startup Commissioning $48,300 1% of A93-4 EPC Fee $811,200 15% of A93-5 Owner's Costs $0

93-5-1 Owner's Engineer & Construction Management $0 Included 93-5-2 Performance Testing $0 Included 93-5-3 Anhydrous Ammonia Risk Management & Training $0

93. Total $1,390,700
Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Units 1 & 2 Common Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Units 1 & 2 Common

94 Total Escalation95 Total Contingency $1,243,800 20% of 996 Total Construction Cost $7,463,100

96A New Mexico Gross Receipt Tax (NMGRT) $471,100

96B Total Construction Cost with NMGRT $7,934,200

97 Interest During Construction Not Incl

97A Lost Generation During Extended Outage Not Incl

98 TOTAL PROJECT COST $7,934,200
Project No. 11278-034 

SAN JUAN GENERATING STATION 03/29/2013 

SNCR AND SCR COST ESTIMATES Page 24 

ATTACHMENT C.

SAN JUAN GENERATING STATION

UNITS 3 & 4 

SCR COST ESTIMATES
Unit 3 Unit 4

Capacity (MW-gross) 544 544

Capacity (MW-net) 497 507

Maximum Heat Input (MMBtu/hr) 5,758 5,649

Annual Capacity Factor (%) 85% 85%

Baseline NOx Emission Rate (lb/MMBtu) 0.30 0.30 Adjusted to match Dec. 2012 SNCR Cost Estimate

Baseline NOx Emission Rate (lb/hr) 1,727.4 1,694.7

Controlled NOx Emission Rate (lb/MMBtu) 0.05 0.05

Controlled NOx Emission Rate (lb/hr) 287.9 282.5

Cost Item Unit 3 Unit 4 Remarks/Cost Basis

CAPITAL COST 

S&L Cost Estaimtes 31329C (Unit 3 SCR); 31330C (Unit 4 SCR); 31331C (Units 

1, 2, 3 & 4 SCR Common Equipment). Common equipment costs in estimate 

31330C were split equally between the larger units (Units 3 & 4)

Direct Costs 

Purchased Equipment Costs

SCR and Economizer Bypass $21,436,700 $21,436,700 Acct. Nos. A-31

Sorbent Injection System $880,000 $880,000 Acct. Nos. B-31

Baghouse Handling System $810,000 $810,000 Acct. Nos. C-33

Anhydrous Ammonia System $1,256,500 $1,256,500 Common Costs for all 4 SCR control systems, split equally between Units 3 & 4. 

Acct. Nos. D-31, D-41, D-42, D-43, D-44, D-51

Electrical Equipment $2,314,200 $2,314,200 Acct. Nos. E-41, E-42, E-43

Instrumentation and Control System $1,429,000 $1,429,000 Acct. Nos. E-44

Substation and Switchyard Equipmenet $200,000 $200,000 Acct. Nos. E-51

Flue Gas - Gas Pass Upgrades for SCR

 Mechanical Equipment $4,687,700 $4,687,700

 Electrical Equipment $4,606,300 $4,606,300

 Instrumentation & Controls $432,000 $432,000

 345 kV Substation Modifications $6,000 $6,000

Balanced Draft Conversion

 Mechanical Equipment $1,171,900 $1,171,900

 Electrical Equipment $1,151,600 $1,151,600

 Instrumentation & Controls $108,000 $108,000

 345 kV Substation Modifications $1,500 $1,500

Subtotal Equipment Costs (EC) $40,491,400 $40,491,400

Freight on Materials $1,572,600 $1,573,400 Acct. Nos. 91-5 

Total Purchased Equipment Cost (PEC) $42,064,000 $42,064,800 Equipment Costs + Freight

Direct Installation Costs

Site Preparation

 SCR Area and Economizer Bypass $146,600 $146,600 Acct. Nos. A-11 and A-21 (Demolition and Civil Work)

 Sorbent Injection System $89,500 $89,500 Acct. Nos. B-21 (Civil Work)

 Baghouse Ash Handling System $27,800 $15,500 Acct. Nos. C-21 (Civil Work)

 Anhydrous Ammonia $20,600 $20,600 Common Costs for all 4 SCR control systems, split equally between Units 3 & 4. 

Acct. Nos. D-11 and D-21 (Demolition and Civil Work)

 Flue Gas - Gas Pass Upgrades for SCR $1,300 $1,300 Applied 80% of Acct. No. F-21 (Civil Work) to SCR Project

 Balanced Draft Conversion $300 $300 Applied 20% of Acct. No. F-21 (Civil Work) to Balance Draft

Foundations & Supports

 SCR Area and Economizer Bypass $21,283,200 $21,283,200 Acct. Nos. A-22 and A-23 (Concrete and Steel)

 Sorbent Injection System $24,600 $24,600 Acct. Nos. B-22 and B-23 (Concrete and Steel)

 Baghouse Ash Handling System $23,500 $23,500 Acct. Nos. C-23 (Steel)

 Anhydrous Ammonia $35,900 $35,900 Common Costs for all 4 SCR control systems, split equally between Units 3 & 4. 

Acct. Nos. D-22 and D-23 (Concrete and Steel)

 Flue Gas - Gas Pass Upgrades for SCR $52,200 $52,200 Applied 80% of Acct. Nos. F-22 and F-32 (Concrete/Steel) to SCR Project

 Balanced Draft Conversion $13,000 $13,000 Applied 20% of Acct. Nos. F-22 and F-32 (Concrete/Steel) to Balanced Draft

Handling & Erection (Includes Labor Costs)

 SCR Area and Economizer Bypass $62,504,500 $47,632,300 Acct. Nos. A-11 through A-36 Labor Costs*

 Sorbent Injection System $191,000 $172,700 Acct. Nos. B-21 through B-36 Labor Costs

 Baghouse Ash Handling System $707,400 $679,200 Acct. Nos. C-21 through C-35 Labor Costs

 Anhydrous Ammonia System $1,227,500 $1,407,100 Acct. Nos. D-21 through D-35 Labor Costs

 Electrical $4,636,900 $4,636,900 Acct. Nos. E-41 through E-51 Labor Costs

 Flue Gas - Gas Pass Upgrades for SCR $1,114,600 $1,114,600

Applied 80% of Acct. Nos. F-21 through F-51 (Labor Costs) and F-51 

(Construction Power) to SCR Project

 Balanced Draft Conversion $1,114,600 $1,114,600

Applied 20% of Acct. Nos. F-21 through F-51 (Labor Costs) and F-51 

(Construction Power) to Balanced Draft Conversion

 Construction Equipment Supplement (Labor) $912,900 $277,800 Acct. Nos. G-61 (Labor)

Piping $307,900 $336,300 Acct. Nos. A-35, B-35, C-35, D-35

Insulation $1,589,000 $1,589,000 Acct. Nos. A-36 and B-36

Construction Equipment Supplement (Cranes) $0 $1,479,800 Acct. Nos. G-61

Scaffolding $2,680,000 $2,296,000 Acct. Nos. 91-1

Cost Due to Overtime $8,570,900 $6,835,200 Acct. Nos. 91-2A (working 5 - 10 hour days)

Cost Due to Overtime $6,327,200 $5,026,200 Acct. Nos. 91-2B (working 7 -12 hour days during the tie-in)

Per Diem $0 $0 Not Included

Consumables $536,100 $459,300 Acct. Nos. 91-4

Contractor G&A Expenses $0 $0 Included in EPC Fee

Contractor Profit $0 $0 Included in EPC Fee

Total Direct Installation Costs (DIC) $114,139,000 $96,763,200

Total Direct Costs (DC) = (PEC) + (DIC) $156,203,000 $138,828,000

Privileged & Confidential

San Juan Units 3 & 4

SCR Cost Estimate

SCR COST ANALYSIS

Applied 80% of Acct. Nos. F-31, F-41, F-42, F-43, F-44, and F-51 (Equipment and

Material Costs) to gas pass upgrades required for the SCR Project.

Applied 20% of Acct. Nos. F-31, F-41, F-42, F-43, F-44, and F-51 (Equipment and

Material Costs) to account for additional gas pass upgrades that would be required 

for Balanced Draft Conversion.
Privileged & Confidential

San Juan Units 3 & 4

SCR Cost Estimate

Indirect Costs 

EPC Engineering, Procurement and Project Services $12,803,500 $11,413,500 Acct. Nos. 93-1

EPC Construction Management Support $4,801,300 $4,280,000 Acct. Nos. 93-2

EPC Startup Commissioning $1,600,500 $1,426,700 Acct. Nos. 93-3

EPC Fee $26,887,200 $23,968,200 Acct. Nos. 93-4

Architectural $503,500 $503,500 Acct. Nos. A-24 and D-24

Owner's Engineer & Construction Management $5,742,700 $5,742,700 Acct. Nos. 93-5-1

Performance Testing $100,000 $100,000 Acct. Nos. 93-5-2

Total Indirect Costs (IC) $52,438,700 $47,434,600

New Mexico Gross Receipt Tax (GRT) $13,170,500 $11,757,800 (DC + IC) X 6.3125% 

Project Contingency (PC) $42,395,600 $37,919,600 Acct. Nos. 95

Total Capital Investment (DC + IC + GRT + PC) $264,207,800 $235,940,000

ANNUAL COST 

Direct Annual Costs 

Fixed Annual Costs

Operating Labor $0 $0 Assumed no additional operating labor for the SCR

Maintenance Labor & Materials $3,963,100 $3,539,100 TCI X 1.5% [EPA Cost Manual Section 4.2, Chapter 2, Eqn. 2.46]

Annual Emissions Testing $25,000 $25,000

Catalyst Activity Testing $5,000 $5,000

Fly Ash Sampling and Analysis $20,000 $20,000

Total Fixed Annual Costs $4,013,100 $3,589,100

Variable Annual Costs 

Reagent Consumption (Ammonia) $1,632,500 $1,601,600

Reagent Consumption (DSI) $72,400 $72,400

Auxiliary & ID Fan Power $1,107,200 $1,101,800

Steam Cost $108,500 $108,500

Water Cost $0 $0

Catalyst Replacement Cost $1,201,000 $1,201,000

Total Variable Annual Costs $4,121,600 $4,085,300

Total Direct Annual Costs (DAC) $8,134,700 $7,674,400

Indirect Annual Costs 

Capital Recovery Factor (CRF) 0.0925 0.0925 Calculated using 8.44% interest and 30 year equipment life

Cost for Capital Recovery $24,450,000 $21,834,000 TCI x CRF

Total Indirect Annual Costs (IDAC) $24,450,000 $21,834,000

Total Annual Cost (TAC) = (DAC) + (IDAC) $32,584,700 $29,508,400

Baseline Annual Emissions (tpy) 6,431 6,309

Project Post-Project Annual Emissions (tpy) 1,072 1,052

Emission Reductions (ton/yr) 5,359 5,257

Cost Effectiveness ($/ton) $6,080 $5,613

Cost ($/kW) $486 $434

Interest Rate 8.44%

Lifetime 30

CRF 0.0925

*Note: A cost premium of approximately 40% was included in the Unit 3 SCR labor costs (sub-account A-23 including ductwork between the economizer outlet and SCR 

inlet, SCR outlet and AH inlet, SCR reactor boxes, and support framing) to account for the significant site restrictions and congestion around the Unit 3 SCR compared to the 

Unit 4 SCR.

See, O&M Costs Worksheet
SCR O&M Costs

SJGS Unit 3 SJGS Unit 4

SCR Type High Dust High Dust

Plant Gross Capacity MW 544.0 544.0

Capacity Factor % 85.00 85.00

NOx Control Rate lb/MMBtu 0.050 0.050

Average NOx Inlet lb/MBtu 0.30 0.30

Current Technology LNB/Neural Network LNB/Neural Network

Required Efficiency (Average) % 83.33 83.33

Fuel New Mexico Bituminous New Mexico Bituminous

Heat Input to Boiler at Full Load Btu/hr 5.758E+09 5.649E+09

Fuel Heating Value Btu/lb 9,502 9,502

Reagent Anhydrous Ammonia Anhydrous Ammonia

Average NH3 Consumption lb NH3/hr 559 548

Average Reagent Consumption tpy 2,080 2,040

Ammonia Cost $/dry ton 785 785

Auxiliary Power Cost $/MWhr 37 37

Water Cost $/1000 gal 6 6

Steam Cost $/MMBtu 5 5

Catalyst replacement $/m3 8,000 8,000

Hydrated Lime Cost $/ton 120 120

Initial Catalyst Volume m3 938 938

Initial Catalyst Layers 3 3

Catalyst replacement cycle yrs 2 2

Flue Gas Flow acfm 3,206,400 3,191,200

Pressure Drop in 8 8

Increase in Auxiliary Power Consumption - Full 

Load kW 4,019 3,999

Increase in Water Consumption gph 0 0

Steam Usage lb/hr 2,333 2,333

Steam Quality MMBtu/lb 1,249 1,249

Dry Sorbent Injection lb/hr 162 162

Variable O&M Cost:

Ammonia Cost $/yr $1,632,500 $1,601,600

Catalyst Replacement Future Worth Factor 0.48 0.48

Catalyst Replacement Cost* $/yr $1,201,000 $1,201,000

Auxiliary Power Cost $/yr $1,107,200 $1,101,800

Steam Cost $/yr $108,500 $108,500

Water Cost $/yr $0 $0

Dry Sorbent Cost $/yr $72,400 $72,400

Total Variable O&M Cost $/yr $4,121,600 $4,085,300

* Catalyst replacement costs were calculated based on replacing 1 layer of catalyst (approx. 202 m3

) once every two years. 

Catalyst costs were calculated by multiplying the volume of catalyst by the installed unit cost of $8,000/m3

 and using a 

future worth factor of 0.48 calculated as follows:

FWF = i * [ 1 / (1 + i)y - 1]; 

where i = an assumed interest rate of 8.44% and y = 2 (i.e., replacing one layer every other year.

See, Control Cost Manual, Section 4.2, Chapter 2, pg. 2-47
Basis: S&L Cost Estimte 31329C (10/14/2011)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 3 Notes

A-11 Demolition $100,000 $0 $2,265,800 $2,365,800A-21 Civil Work $0 $46,600 $36,500 $83,100A-22 Concrete $0 $46,600 $72,200 $118,800A-23 Steel $0 $21,236,600 $52,052,300 $73,288,900A-24 Architectural $500,000 $0 $123,200 $623,200A-31 Mechanical Equipment $15,236,800 $6,199,900 $4,636,200 $26,072,900A-35 Piping $0 $154,200 $522,200 $676,400A-36 Insulation $0 $1,584,000 $2,796,100 $4,380,100

A. Total $15,836,800 $29,267,900 $62,504,500 $107,609,200

B-21 Civil Work $89,500 $0 $800 $90,300B-22 Concrete $0 $6,600 $10,100 $16,700B-23 Steel $0 $18,000 $64,000 $82,000B-31 Mechanical Equipment $880,000 $0 $0 $880,000B-35 Piping $0 $18,600 $108,100 $126,700B-36 Insulation $0 $5,000 $8,000 $13,000

B. Total $969,500 $48,200 $191,000 $1,208,700

C-21 Civil Work $0 $27,800 $41,500 $69,300C-23 Steel $0 $23,500 $34,100 $57,600C-33 Material Handling Equipment $810,000 $0 $631,800 $1,441,800C-35 Piping $0 $0 $0 $0

C. Total $810,000 $51,300 $707,400 $1,568,700

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 3

A. SCR Area and Economizer BypassB. Sorbent Injection SystemC. Baghouse Ash Handling System
Basis: S&L Cost Estimte 31329C (10/14/2011)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 3 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 3

D-21 Civil Work $0 $0 $0 $0D-22 Concrete $0 $13,800 $23,000 $36,800D-31 Mechanical Equipment $972,000 $0 $59,200 $1,031,200D-35 Piping $0 $67,600 $169,000 $236,600

D. Total $972,000 $81,400 $251,200 $1,304,600

E-41 Electrical Equipment $854,500 $168,400 $687,400 $1,710,300E-42 Conduit $0 $352,300 $934,300 $1,286,600E-43 Control & Instrument Cable $0 $939,000 $2,336,500 $3,275,500E-44 Control & Instrumentation $1,429,000 $0 $678,700 $2,107,700E-51 Substation, Switchyard & Transmission Line $200,000 $0 $0 $200,000

E. Total $2,483,500 $1,459,700 $4,636,900 $8,580,100

F-21 Civil Work $0 $1,600 $18,700 $20,300F-22 Concrete $0 $20,500 $49,500 $70,000F-23 Steel $0 $44,700 $43,000 $87,700F-31 Mechanical Equipment $5,787,600 $72,000 $3,508,900 $9,368,500F-41 Electrical Equipment $4,983,000 $0 $302,600 $5,285,600F-42 Raceway, Cable Tray & Conduit $660,000 $0 $1,400,400 $2,060,400F-43 Medium Voltage Power Cable & Termination $0 $114,900 $152,500 $267,400F-44 Control & Instrumentation $540,000 $0 $90,000 $630,000F-51 Construction Power $7,500 $0 $0 $7,500

F. Total $11,978,100 $253,700 $5,565,600 $17,797,400

G-61 Construction Equipment $0 $0 $912,900 $912,900

G. Total $0 $0 $912,900 $912,900

90 Subtotal $33,049,900 $31,162,200 $74,769,500 $138,981,600

G. Construction Equipment SupplementD. Anhydrous AmmoniaE. ElectricalF. Balanced Draft Conversion
Basis: S&L Cost Estimte 31329C (10/14/2011)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 3 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 3

91 Other Direct & Construction Indirect Costs

91-1 Scaffolding $2,648,300 $2,648,300 2.5% of 

91-2A Cost Due to overtime working 5 - 10 hour days $8,441,200 $8,441,200

91-2B Cost Due to overtime working 7 - 12 hour days during the tie-in 

outage $6,327,200 $6,327,200

91-3 Per Diem $0 Not Inclu91-4 Consumables $529,700 $529,700 0.5% of 91-5 Freight on materials $1,558,100 $1,558,100 5% of A91-7 Sales Tax $0 Not Inclu91-9 Contractor G&A Expenses $0 Included 

91-10 Contractor Profit $0 Included 

91. Total $0 $1,558,100 $17,946,400 $19,504,500

92 Total Direct & Construction Indirect Cost $33,049,900 $32,720,300 $92,715,900 $158,486,10093 Indirect Costs

93-1 EPC Engineering, Procurement & Project Services $12,678,900 8% of A93-2 EPC Construction Management Support $4,754,600 3% of A93-3 EPC Startup Commissioning $1,584,900 1% of A93-4 EPC Fee $26,625,700 15% of A93-5 Owner's Costs $0

93-5-1 Owner's Engineer & Construction Management $5,668,138 By PNM93-5-2 Performance Testing $100,00093-5-3 Anhydrous Ammonia Risk Management & Training $0

93. Total $51,412,238
Basis: S&L Cost Estimte 31329C (10/14/2011)

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 3 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 3

94 Total Escalation95 Total Contingency $41,979,700 20% of 996 Total Construction Cost $251,878,038

96A New Mexico Gross Receipt Tax (NMGRT) $15,899,801

96B Total Construction Cost with NMGRT $267,777,839

97 Interest During Construction Not Inclu98 TOTAL PROJECT COST $267,777,839
Basis: S&L Cost Estimate No. 31327C 10/14/2011

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 4 Notes

A-11 Demolition $100,000 $0 $2,265,800 $2,365,800A-21 Civil Work $0 $46,600 $36,500 $83,100A-22 Concrete $0 $46,600 $72,200 $118,800A-23 Steel $0 $21,236,600 $37,180,100 $58,416,700A-24 Architectural $500,000 $0 $123,200 $623,200A-31 Mechanical Equipment $15,236,800 $6,199,900 $4,636,200 $26,072,900A-35 Piping $0 $154,200 $522,200 $676,400A-36 Insulation $0 $1,584,000 $2,796,100 $4,380,100

A. Total $15,836,800 $29,267,900 $47,632,300 $92,737,000

B-21 Civil Work $89,500 $0 $800 $90,300B-22 Concrete $0 $6,600 $10,100 $16,700B-23 Steel $0 $18,000 $45,700 $63,700B-31 Mechanical Equipment $880,000 $0 $0 $880,000B-35 Piping $0 $18,600 $108,100 $126,700B-36 Insulation $0 $5,000 $8,000 $13,000

B. Total $969,500 $48,200 $172,700 $1,190,400

C-21 Civil Work $0 $15,500 $23,100 $38,600C-23 Steel $0 $23,500 $24,300 $47,800C-33 Material Handling Equipment $810,000 $0 $631,800 $1,441,800C-35 Piping $0 $0 $0 $0

C. Total $810,000 $39,000 $679,200 $1,528,200

A. SCR Area and Economizer BypassB. Sorbent Injection SystemC. Baghouse Ash Handling System

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 4
Basis: S&L Cost Estimate No. 31327C 10/14/2011

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 4 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 4

D-21 Civil Work $0 $0 $0 $0D-22 Concrete $0 $13,800 $23,000 $36,800D-31 Mechanical Equipment $972,000 $0 $59,200 $1,031,200D-35 Piping $0 $96,000 $348,600 $444,600

D. Total $972,000 $109,800 $430,800 $1,512,600

E-41 Electrical Equipment $854,500 $168,400 $687,400 $1,710,300E-42 Conduit $0 $352,300 $934,300 $1,286,600E-43 Cable $0 $939,000 $2,336,500 $3,275,500E-44 Control & Instrumentation $1,429,000 $0 $678,700 $2,107,700E-51 Substation, Switchyard & Transmission Line $200,000 $0 $0 $200,000

E. Total $2,483,500 $1,459,700 $4,636,900 $8,580,100

F-21 Civil Work $0 $1,600 $18,700 $20,300F-22 Concrete $0 $20,500 $49,500 $70,000F-23 Steel $0 $44,700 $43,000 $87,700F-31 Mechanical Equipment $5,787,600 $72,000 $3,508,900 $9,368,500F-41 Electrical Equipment $4,983,000 $0 $302,600 $5,285,600F-42 Raceway, Cable Tray & conduit $660,000 $0 $1,400,400 $2,060,400F-43 Medium Voltage Power Cable & Termination $0 $114,900 $152,500 $267,400F-44 Control & Instrumentation $540,000 $0 $90,000 $630,000F-51 Construction Power $7,500 $0 $0 $7,500

F. Total $11,978,100 $253,700 $5,565,600 $17,797,400

G-61 Construction Equipment $1,479,800 $0 $277,800 $1,757,600

G. Total $1,479,800 $0 $277,800 $1,757,600

90 Subtotal $34,529,700 $31,178,300 $59,395,300 $125,103,300

D. Anhydrous AmmoniaE. ElectricalF. Balanced Draft ConversionG. Construction Equipment Supplement
Basis: S&L Cost Estimate No. 31327C 10/14/2011

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 4 Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 4

91 Other Direct & Construction Indirect Costs

91-1 Scaffolding $2,264,300 $2,264,300 2.5% of Acct. No. 90 Lab

91-2A Cost Due to overtime working 5 - 10 hour days $6,705,500 $6,705,500

91-2B Cost Due to overtime working 7 - 12 hour days during the tie-in 

outage $5,026,200 $5,026,200

91-3 Per Diem $0 Not Included91-4 Consumables $452,900 $452,900 0.5% of Acct. No. 90 Lab91-5 Freight on materials $1,558,900 $1,558,900 5% of Acct. No. 90 (Mate91-7 Sales Tax $0 Not Included (See, Acct. 91-9 Contractor G&A Expenses $0 Included in EPC Fee

91-10 Contractor Profit $0 Included in EPC Fee

91. Total $0 $1,558,900 $14,448,900 $16,007,800

92 Total Direct & Construction Indirect Cost $34,529,700 $32,737,200 $73,844,200 $141,111,10093 Indirect Costs

93-1 EPC Engineering, Procurement & Project Services $11,288,900 8% of Acct. No. 9293-2 EPC Construction Management Support $4,233,300 3% of Acct. No. 9293-3 EPC Startup Commissioning $1,411,100 1% of Acct. No. 9293-4 EPC Fee $23,706,700 15% of Acct. Nos. 92, 9393-5 Owner's Costs $0

93-5-1 Owner's Engineer & Construction Management $5,668,138 By PNM93-5-2 Performance Testing $100,00093-5-3 Anhydrous Ammonia Risk Management & Training $0

93. Total $46,408,138

94 Total Escalation95 Total Contingency $37,503,700 20% of 92 + 9396 Total Construction Cost $225,022,938

96A New Mexico Gross Receipt Tax (NMGRT) $14,204,573

96B Total Construction Cost with NMGRT $239,227,511

97 Interest During Construction Not Included98 TOTAL PROJECT COST $239,227,511
Basis: S&L Cost Estimate No. 31327C 10/14/2011

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Units 3 & 4 Common Notes

D-11 Demolition $0 $0 $363,500 $363,500D-21 Civil Work $0 $41,200 $60,000 $101,200D-22 Concrete $0 $25,900 $40,700 $66,600D-23 Steel $0 $18,200 $15,100 $33,300D-24 Architectural $0 $7,000 $7,700 $14,700D-31 Mechanical Equipment $90,000 $0 $10,800 $100,800D-35 Piping $0 $134,900 $93,100 $228,000D-41 Electrical Equipment $45,700 $71,900 $449,600 $567,200D-42 Raceway $0 $109,500 $306,500 $416,000D-43 Cable $0 $165,900 $471,000 $636,900D-44 Control & Instrumentation $80,000 $0 $110,600 $190,600D-51 Substation, Switchyard & Transmission Line $0 $6,000 $24,000 $30,000

D. Total $215,700 $580,500 $1,952,600 $2,748,800

90 Subtotal $215,700 $580,500 $1,952,600 $2,748,80091 Other Direct & Construction Indirect Costs

91-1 Scaffolding $63,300 $63,300 2.5% of Acct. No. 90 L91-2 Cost Due to overtime working 5 - 10 hour days $259,400 $259,40091-3 Per Diem $0 Not Included91-4 Consumables $12,700 $12,700 0.5% of Acct. No. 90 L91-5 Freight on materials $29,000 $29,000 5% of Acct. No. 90 (M91-7 Sales Tax $0 Not Included (See, Ac91-9 Contractor G&A Expenses $0 Included in EPC Fee

91-10 Contractor Profit $0 Included in EPC Fee

91. Subtotal $0 $29,000 $335,400 $364,400

92 Total Direct & Construction Indirect Cost $215,700 $609,500 $2,288,000 $3,113,200

D. Anhydrous Ammonia

Detailed SCR Cost Estimate Summary - San Juan Generating Station Units 3 & 4 Common
Basis: S&L Cost Estimate No. 31327C 10/14/2011

Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Units 3 & 4 Common Notes

Detailed SCR Cost Estimate Summary - San Juan Generating Station Units 3 & 4 Common

93 Indirect Costs

93-1 EPC Engineering, Procurement & Project Services $249,100 8% of Acct. No. 9293-2 EPC Construction Management Support $93,400 3% of Acct. No. 9293-3 EPC Startup Commissioning $31,100 1% of Acct. No. 9293-4 EPC Fee $523,000 15% of Acct. Nos. 92, 93-5 Owner's Costs $0

93-5-1 Owner's Engineer & Construction Management $149,069 By PNM93-5-2 Anhydrous Ammonia Risk Management & Training $0

93. Total $1,045,669

94 Total Escalation95 Total Contingency $831,700 20% of 92 + 9396 Total Construction Cost $4,990,569

96A New Mexico Gross Receipt Tax (NMGRT) $315,030

96B Total Construction Cost with NMGRT $5,305,599

97 Interest During Construction Not Included98 TOTAL PROJECT COST $5,305,599
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Appendix D D-1

Appendix D. EPA Technical Support Document
Technical Support Document

Visibility Modeling for BART Determination: San Juan Generating 

Station, New Mexico

Prepared by:

U.S. Environmental Protection Agency, Region 6

Michael Feldman

Erik Snyder
2

Pictures taken by Erik Snyder January 2004 from a vantage point Southeast of Bloomfield/Farmington area 

on Hwy 550 looking towards La Plata Mountains around Mesa Verde (previous page and above) and snowcapped mountains in the background are part of Weminuche Wilderness.
3

Table of Contents

Table of Contents................................................................................................................ 3

List of Attachments............................................................................................................. 4

List of Tables and Figures................................................................................................... 5

Chapter 1: Background and Description of San Juan Generating Station...................... 6

1.1 Background .......................................................................................................... 6

1.2 Description of San Juan Generating Station ........................................................ 6

Chapter 2: BART Eligible Determination ...................................................................... 9

Chapter 3: Subject-to-BART Determination................................................................ 11

Chapter 4: BART Guidelines and Modeling Protocols................................................ 14

4.1 Background and Introduction............................................................................. 14

4.2 Calculation of Visibility Impact......................................................................... 16

4.2.1 IMPROVE Equation ................................................................................... 17

4.2.2 Revised IMPROVE Equation ..................................................................... 17

4.2.3 Deciview Impact Calculation...................................................................... 19

4.3 CALMET/CALPUFF MODELING .................................................................. 21

4.3.1 Modeling Protocol ...................................................................................... 21

4.3.2 Ammonia..................................................................................................... 27

4.3.3 Sulfuric Acid............................................................................................... 28

Chapter 5: B&V Approach ........................................................................................... 29

5.1 B&V Modeling Inputs........................................................................................ 29

5.1.1 Sulfuric Acid Emission Estimates .............................................................. 29

5.1.2 Background Ammonia Concentration ........................................................ 29

5.1.3 B&V Modeling Scenarios........................................................................... 30

5.2 Results of NMED visibility modeling............................................................... 32

Chapter 6: EPA approach ............................................................................................. 34

6.1 EPA Modeling Inputs......................................................................................... 34

6.1.1 NOx Emission Rate..................................................................................... 34

6.1.2 SO2 Emission Rate...................................................................................... 34

6.1.3 Sulfuric Acid Emission Estimates .............................................................. 35

6.1.3.1 Assumptions used in Sulfuric Acid Emission Calculations ................ 35

6.1.3.2 Comparison of Sulfuric Acid Emission Estimates.............................. 37

6.1.3.3 Sulfuric Acid Emission Limit.............................................................. 38

6.1.4 Background Ammonia Concentrations....................................................... 39

6.1.5 EPA Modeling Scenarios............................................................................ 42

6.2 EPA Visibility Modeling Impacts of SJGS........................................................ 43

6.2.1 Baseline to Revised (EPA) Baseline........................................................... 44

6.2.2 Visibility Improvement from Operation of SCR ........................................ 46
4

List of Attachments

Attachment 1. Revised BART Cost Effectiveness Analysis for Selective Catalytic 

Reduction at the Public Service Company of New Mexico San Juan 

Generating Station - Final Report, November 2010 prepared by Phyllis 

Fox, Ph.D., P.E. for EPA Region 6.

Attachment 2. Exhibit 1 for Cost Effectiveness Analysis Report – Spreadsheet of SJGS 

Cost Effectiveness Analysis.

Attachment 3. EPA CALPUFF Visibility Modeling Results
5

List of Tables and Figures

Table 1-1. SJGS Operational Characteristics..................................................................... 7

Table 3-1. WRAP BART CALPUFF screening results for SJGS................................... 13

Table 3-2. EPA Consent Decree baseline visibility modeling (1ppb background ammonia 

and Method 8)................................................................................................. 13

Table 4-1. Measured Visibility Impairment at Class I areas (2007 – 2008 average) ...... 14

Figure 4-1. Map of Class I Areas within 300 km of SJGS ............................................. 15

Table 4-2. Class I Areas in CALPUFF Modeling for SJGS............................................ 15

Table 4-3. Natural Background Concentrations used by NMED and EPA for ―Method 6‖

......................................................................................................................... 19

Table 4-4. Natural Background Concentrations used by EPA for ―Method 8‖............... 20

Figure 4-2. CALMET and CALPUFF computational domain. ....................................... 22

Table 4-5. Selected CALMET settings for SJGS ............................................................ 25

Table 4-6. Impacts of SJGS on Visibility using B&V post-consent decree baseline 

emissions (average of 98th percentile of daily maximum dv for 2001, 2002, 

and 2003) at Sixteen Class I Areas................................................................. 27

Table 5-1. Assumptions Used by B&V for H2SO4 Emission Estimates.......................... 29

Table 5-2. Ammonia background concentration in ppb .................................................. 29

Table 5-3. CALPUFF Modeling Emission Inputs (lb/hr)................................................ 31

Table 5-4. NMED Modeling Results -- Impacts of SJGS on Visibility (average of 98th

percentile of daily maximum dv for 2001, 2002, and 2003) at Sixteen Class I 

Areas............................................................................................................... 33

Table 6-1. Assumptions used in Sulfuric acid (H2SO4) Emissions Calculations by NPS.

......................................................................................................................... 36

Table 6-2. SJGS Facility-Wide Sulfuric Acid Emission Estimates................................. 38

Table 6-3. EPA Modeling Inputs (lb/hr).......................................................................... 43

Table 6-4. EPA Modeling Results – Impacts of SJGS on Visibility (maximum of 98th

Percentile of daily maximum dv of 2001, 2002, and 2003) at Sixteen Class I 

Areas (1ppb background ammonia concentration, Method 8)........................ 45

Table 6-5. EPA Modeling Results -Summary of total visibility impairment at all 16 Class 

I sites. .............................................................................................................. 45

Table 6-6. EPA Modeling Results – Impacts of SJGS on Visibility (maximum of 98th

Percentile of daily maximum dv of 2001, 2002, and 2003) at Sixteen Class I 

Areas (1ppb background ammonia concentration, Method 8)........................ 47

Table 6-7. EPA Modeling Results - Summary of total visibility impairment at all 16 

Class I sites. .................................................................................................... 47

Table 6-8. Average number of days per year SJGS visibility impacts exceed 1.0 and 0.5 

deciviews (1 ppb background ammonia and Method 8)................................. 48
6

Chapter 1: Background and Description of San Juan Generating 

Station

1.1 BACKGROUND

As described in our proposed action Federal Register notice, EPA is proposing to 

disapprove a portion of the State Implementation Plan (SIP) revision submitted by the 

State of New Mexico for the purpose of addressing the ―good neighbor‖ requirements of 

section 110(a)(2)(D)(i) of the Clean Air Act (CAA or Act) for the 1997 8-hour ozone 

National Ambient Air Quality Standards (NAAQS or standards) and the 1997 fine 

particulate matter (PM2.5) NAAQS. The SIP revision addresses the requirement that 

New Mexico‘s SIP must have adequate provisions to prohibit emissions from adversely 

affecting another state‘s air quality through interstate transport. EPA is proposing to 

disapprove the New Mexico Interstate Transport SIP provisions that address the 

requirement of section 110(a)(2)(D)(i)(II) that emissions from New Mexico sources do 

not interfere with measures required in the SIP of any other state under part C of the 

CAA to protect visibility. EPA is also proposing to promulgate a Federal Implementation 

Plan (FIP) to prevent emissions from New Mexico sources from interfering with other 

states‘ measures to protect visibility, and to implement nitrogen oxides (NOx) and sulfur 

dioxide (SO2) emission limits necessary at one source to prevent such interference. In 

addition, EPA is proposing sulfuric acid (H2SO4) and ammonia (NH3) hourly emission 

limits at the same source, to minimize the contribution of these compounds to visibility 

impairment. EPA also proposes that compliance with the emission limits be within three 

(3) years of the effective date of our final rule. Furthermore, EPA is proposing the FIP to 

address the requirement for best available retrofit technology (BART) for NOx for this 

source. This action is being taken under section 110 and part C of the CAA. This 

Technical Support Document, including attachments and appendices, and other docket 

materials provides much of the support for our proposed actions. 

1.2 DESCRIPTION OF SAN JUAN GENERATING STATION

The Public Service of New Mexico‘s (PNM) San Juan Generating Station (SJGS) 

includes four coal-fired boilers burning subbituminous coal from the San Juan Mine. 

SJGS is located in San Juan County, 15 miles west of Farmington in northwest New 

Mexico. SJGS Units 1 and 2 have a unit capacity of 350 and 360 MW, respectively. 

These units are subcritical, wall-fired boilers that operate in a forced draft mode. SJGS 

Units 3 and 4 have a unit capacity of 544 MW each and are equipped with subcritical, 

opposed wall-fired boilers that operate in a forced draft mode. Chapter 2 of this 

document addresses the SJGS as being BART eligible and Chapter 3 discusses the 

evaluation of SJGS as being subject-to-BART. The remaining chapters summarize the 

methodology and results of modeling to evaluate the degree of improvement in visibility 

which may reasonably be anticipated to result from the use of control technology.

On March 10, 2005, PNM entered into a consent decree with the Grand Canyon Trust, 

Sierra Club, and New Mexico Environmental Department (NMED), resulting in the 

installation of low-NOx burners (LNB) with overfire air (OFA) ports and a neural 

network (NN) system to reduce NOx emissions, and a full-sized pulse jet fabric filter 
7

(PJFF) to reduce PM emissions.1 The wet limestone scrubber was modified to eliminate 

flue gas bypass, and dibasic acid (DBA) was added to the scrubber process to improve 

SO2 removal. Installation of these controls on all four units was completed in the spring 

of 2009. Prior to installation of controls to meet the consent decree, all SGJS units were 

equipped with hot-side electrostatic precipitators (ESP) for PM control, and wet 

limestone flue gas desulfurization (FGD) systems for SO2 control. SJGS Units1, 3, and 4 

also had LNB controls for NOx prior to the installation of controls for the consent decree.

Table 1-1. SJGS Operational Characteristics

Unit #1 Unit #2 Unit #3 Unit #4

Unit Rating, MW 

(gross) 360 350 544 544

+Boiler Heat Input, 

MBtu/hr 3,707 3,688 5,758 5,649

Type of 

Boiler/Manufacturer

Wall-fired/ Foster 

Wheeler

Wall-fired/ Foster 

Wheeler

Opposed Wallfired/Babcock & 

Wilcox

Opposed Wallfired/Babcock & 

Wilcox

Existing emissions controls (post-consent decree):

NOx LNB/OFA/NN for all units

SO2 Wet FGD for all units

PM PJFF for all units

NOx Post-consent 

decree baseline 

emission rate

0.30 lb/MMBtu for each unit 

SO2 Presumptive 

BART emission rate

90% annual average control, not to exceed 0.250 lb/MMBtu for a seven day 

block average for each unit

PM Post-consent 

decree baseline 

emission rate

0.015 lb/MMBtu for each unit

In a permit modification to the construction permit for SJGS, NMED issued a revised 

construction permit (NSR Air Quality Permit No. 0063-M6) on April 22, 2008 to 

incorporate some of the conditions from the consent decree. The construction permit was 

issued by the Air Quality Bureau of the NMED to SJGS pursuant to the New Mexico Air 

Quality Control Act and regulations and is considered a federally enforceable permit. 

EPA is not a party to the consent decree, but the inclusion of limits from the consent 

decree that have been included in the construction permit for the facility were issued 

pursuant to the federally approved construction permitting program of the New Mexico 

SIP. Specifically, the construction permit includes the NOx, SO2 and PM limits from the 

consent decree that are identified in Table 1-1. This permit has since been superceded by 

a further construction permit modification that also includes the consent decree limits on 

NOx, SO2, and PM emissions and is federally enforceable.2 

 

1

 Consent Decree in The Grand Canyon Trust and Sierra Club, Plaintiffs, The State of New Mexico, 

Plaintiff-Intervenor, v. Public Service Company of New Mexico, Defendant, (CV 02-552 BB/ACT 

(ACE)), lodged in the United States District Court, District of New Mexico, on March 10, 2005, at 15-

16.

2

 New Mexico Environment Department Air Quality Bureau NSR Air Quality Permit No. 0063-M6R1 

was issued on September 12, 2008 and superceded Permit No. 0063-M6.
8

However, EPA does not believe this permit provides the necessary emission limits and 

enforceable mechanisms to ensure the levels used in the Western Regional Air 

Partnership (WRAP) photochemical modeling for the NOx and SO2 emissions of the 

SJGS units.3 Since other WRAP states are using levels modeled for the SJGS units in 

their demonstration of reasonable progress towards natural visibility conditions, any 

discrepancies between what was included in the WRAP photochemical modeling and 

what is presently enforceable, is a concern for this action. EPA must establish federally 

enforceable limits for pollutants that impact visibility projections within the WRAP 

photochemical modeling that were utilized by WRAP states to demonstrate reasonable 

progress towards natural visibility conditions. For the four SJGS units the consent decree 

limits of 0.30 lb/MMBtu of NOx on a 30-day rolling average is less restrictive than the 

0.27 and 0.28 lb/MMBtu of NOx emission rates that were included in the WRAP‘s 

photochemical modeling that are being used for assessing daily visibility impacts. Thus 

the NOx permit limits are at a higher level than what the WRAP modeling assumed.

Similarly, in previous communications to NMED and the WRAP, PNM had indicated 

that the 90% annual average control would be expected to yield roughly a 0.195 

lb/MMBtu of SO2, which is much higher than the 0.15 lb/MMBtu emission rate utilized 

in the WRAP‘s photochemical modeling.4 EPA notes that the 90% reduction is based on 

the annual average sulfur content in the coal combusted in the SJGS‘s four units and is 

not a hard limit. It is an annual average limit that can fluctuate depending upon the 

annual average of the sulfur content. The most restrictive of the emission limits within 

the current construction permit for SJGS is the 0.250 lb/MMBtu on a 7-day block average 

for each unit. This limit is much less restrictive than the 0.15 lb/MMBtu emission rate 

that was used for daily impacts within the WRAP‘s photochemical modeling. 

Thus, the NOx and SO2 permit limits are at a higher level than what the WRAP 

photochemical modeling assumed. EPA does not see an enforceable mechanism in place 

to guarantee the NOx and SO2 emission limits assumed in the WRAP modeling, which 

adjacent states are assuming in their reasonable progress demonstrations. Consequently, 

we are proposing to disapprove New Mexico‘s SIP as not meeting the requirement of 

prohibiting emissions from interfering with efforts to protect visibility in other states. 

CAA section 110(a)(2)(D)(i)(II). 

 

3

 The Western Regional Air Partnership (WRAP) is a voluntary partnership of state, tribal, federal, and 

local air agencies dealing with regional air quality issues in the West. Member states include Alaska, 

Arizona, California, Colorado, Idaho, Montana, New Mexico, North Dakota, Oregon, South Dakota, 

Utah, Washington, and Wyoming. The WRAP established various committees to assist in managing 

and developing RH work products. New Mexico is a WRAP member.

4

 Comments Received to-Date on the Draft 2018 Base Case Projections, Version: December 21, 2005. 

Available here: 

http://www.wrapair.org/forums/ssjf/documents/eictts/Projections/Summary%20of%20Comments_1221

05_final.pdf, pdf pagination 20.
9

Chapter 2: BART Eligible Determination

In 1999, EPA published a final rule to address a type of visibility impairment known as 

regional haze (64 FR 35714, July 1, 1999). The regional haze rule requires States to 

submit state implementation plans (SIPs) to address regional haze visibility impairment 

in 156 Federally-protected 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). As required by the 

CAA, 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. 

40 CFR Part 51.301 defines BART-eligible sources are those sources which have the 

potential to emit 250 tons per year or more of a visibility impairing air pollutant, were put 

in place between August 7, 1962 and August 7, 1977, and 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.

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

Rule published July 1, 1999. The 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 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; 

revised the BART provisions; included new BART Guidelines contained in a new 

Appendix Y to Part 51; and added the requirement that States use Appendix Y for 

determining BART at certain large electrical generating units (EGUs). 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 at 

power plants with a total generating capacity greater than 750 MW. The presumptive 

limits for NOx are based on coal type, boiler type and whether SCR or SNCR are already 

installed at the source.

New Mexico and the WRAP identified the BART eligible sources in New Mexico.5 In 

May 2006, NMED conducted an internal review of sources potentially subject to the 

BART rule and identified 11 source complexes that were BART eligible. The four coal-

 

5

 Draft Report ―Identification of BART-Eligible Sources in the WRAP Region‖, prepared for the WRAP 

by Eastern Research Group, Inc.; April 4, 2005.
10

fired EGU units (Units 1-4) at the San Juan Generation Station were identified as one of 

these 11 BART eligible source complexes by NMED and the WRAP.6

 

6

 WRAP spreadsheets revised (09/21/06) Appendix K: Eligibility of Steam Electric Plants at the Unit 

Level ―WRAP App_K_BART-Eligible_EGUs.XLS‖ and Appendix H: Master List of Sources and 

Their Eligibility WRAP App_H_All_Sources_v5.XLS‖.
11

Chapter 3: Subject-to-BART Determination

Section III of the BART Guidelines outlines the steps involved in identifying sources that 

are subject to BART. Previously, the state of New Mexico and the WRAP identified 

sources subject to BART in New Mexico. Based on the list of identified sources (see 

previous chapter discussion), the 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.7 The basic assumptions in the 

WRAP BART CALMET/CALPUFF modeling used for New Mexico are as follows:

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

• Visibility impacts due to emissions of SO2, NOx and primary PM emissions 

were calculated. 

• PM emissions were modeled as PM2.5.

• Visibility was calculated using the Original IMPROVE equation and Annual 

Average Natural Conditions.

Initial modeling was performed by the WRAP for the 11 source complexes in New 

Mexico that were considered BART eligible. 

As we note in the BART Guidelines, one of the first steps in determining whether a 

source causes or contributes to visibility impairment is to establish a threshold (measured 

in deciviews). A single source that is responsible for a 1.0 deciview change or more 

should be considered to  ̳ ̳cause‘‘ visibility impairment; a source that causes less than a 

1.0 deciview change may still contribute to visibility impairment and thus be subject to 

BART. The modeling of each individual source complexes‘ combined SO2, NOx, and 

PM emissions was completed and results of the 98th percentile visibility impacts at any 

Class I area were evaluated to determine if visibility impacts at any Class I area exceeded 

the 0.5 dv significance threshold. 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 (PNM San Juan Generating Station Boilers #1-

4). Of the 10 other source complexes, none exceed a 0.33 dv impact. Consequently, only 

the PNM San Juan Boilers #1-4 were determined by NMED to be subject to a BART 

determination. The results of this analysis (Table 3-1) indicated that the San Juan 

Generating Station (SJGS), on a facility-wide basis, ―causes‖ visibility impairment at all 

16 Class I areas within 300 km of the facility.8

Therefore, a conclusion was made that the units of the SJGS cause and/or contribute to 

visibility impairment in many nearby Class I areas. We note in the BART Guidelines 

that states (and by extension EPA when promulgating a FIP) have flexibility in 

 

7

―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 at: 

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

8

Summary of WRAP RMC BART Modeling for New Mexico Draft#4, April 21, 2006 

(http://pah.cert.ucr.edu/aqm/308/bart/calpuff/summary/NM_summary_v4_Apr21_2007.doc)
12

determining an appropriate threshold for determining whether a source ―contributes to 

any visibility impairment‖ for the purposes of BART. However, this threshold should 

not be higher than 0.5 deciviews. In the case of the SJGS, this decision point is moot, 

since visibility modeling indicates that even using the default contribution threshold of 

0.5 deciviews, the SJGS contributes to visibility impairment at a number of Class I areas. 

On November 9, 2006, New Mexico informed PNM that the modeling performed by the 

WRAP indicated the visibility impairment from the San Juan Generating Station (SJGS) 

was over the 0.5 dv threshold, and was therefore subject to a BART analysis

However, this modeling was based on the installed control technology at the time and 

does not reflect emission reductions due to the installation of consent decree controls. 

Refined modeling performed by the New Mexico Environmental Department (NMED)

and by the Environmental Protection Agency (EPA) (Table 3-2) in 2010, including the 

controls required by the consent decree, both show that each individual unit at SJGS still 

―cause‖ visibility impairment at Mesa Verde National Park, and contribute to visibility 

impairment at other Class I areas.9, 10 As discussed further in following Chapters, EPA‘s 

modeling was updated to utilize the latest EPA approved version of CALPUFF because 

of some technical concerns that had been raised with the later version of CALPUFF that 

was originally used in the WRAP‘s modeling. The changes in CALPUFF versions did 

not change the conclusions that were made for the SGJS units. Therefore, we find that 

units 1, 2, 3, and 4 of the SJGS are subject to BART. Details on modeling protocols and 

inputs used are discussed later in this document. 

 

9

 Visibility modeling was primarily performed by the contractor Black and Veatch for PNM and submitted 

to NMED for review. Throughout this document, any references to ―NMED modeling‖ refers to 

modeling performed or reviewed by NMED. 

10

 PNM San Juan Generating Station Refined BART Visibility Results, Black and Veatch, March 31, 2008 

(http://www.nmenv.state.nm.us/aqb/reghaz/documents/03312008Final_BART_Modeling_Response_wi

th_Attachments_0331.pdf)
13

Table 3-1. WRAP BART CALPUFF screening results for SJGS

Class I Area

Minimum 

Distance

98th Percentile for Each 

Year 3 year 

average (km) 2001 2002 2003

Arches 222 4.06 3.71 3.59 3.79

Bandelier Wilderness 210 2.47 2.90 3.08 2.82

Black Canyon of the Gunnison 

Wilderness 203 2.38 2.27 2.43 2.36

Canyonlands 170 6.21 4.33 4.44 4.99

Capitol Reef 232 4.00 2.02 2.35 2.79

Grand Canyon 285 2.12 1.50 1.18 1.60

Great Sand Dunes National Monument 269 1.47 1.59 1.74 1.60

La Garita Wilderness 169 1.63 1.82 1.77 1.74

Maroon Bells-Snowmass Wilderness 271 1.19 1.27 1.15 1.21

Mesa Verde 40 5.54 5.34 5.30 5.40

Pecos Wilderness 248 2.17 2.63 2.81 2.53

Petrified Forest 213 1.62 1.27 1.03 1.31

San Pedro Parks Wilderness 155 3.80 4.07 4.14 4.01

Weminuche Wilderness 98 2.24 2.99 2.41 2.55

West Elk Wilderness 216 2.14 1.90 2.20 2.08

Wheeler Peak Wilderness 258 1.94 1.73 1.97 1.88

Table 3-2. EPA Consent Decree baseline visibility modeling (1ppb background ammonia 

and Method 8) 

Class I Area Average of 98th percentile for 2001, 2002, and 2003 (dv)

Unit 1 Unit 2 Unit 3 Unit 4 Facility

Arches 0.47 0.47 0.69 0.67 2.03

Bandelier Wilderness 0.27 0.27 0.41 0.41 1.27

Black Canyon of the Gunnison 

Wilderness 0.23 0.23 0.37 0.36 1.15

Canyonlands 0.74 0.74 1.08 1.06 3.05

Capitol Reef 0.28 0.28 0.37 0.37 1.21

La Garita Wilderness 0.32 0.32 0.49 0.48 1.51

Grand Canyon 0.11 0.11 0.17 0.17 0.56

Great Sand Dunes National Monument 0.24 0.24 0.37 0.37 1.18

Mesa Verde 1.67 1.67 2.36 2.34 5.13

Pecos Wilderness 0.23 0.23 0.36 0.35 1.11

Petrified Forest 0.10 0.10 0.15 0.15 0.47

San Pedro Parks Wilderness 0.47 0.46 0.73 0.71 2.13

Maroon Bells Snowmass Wilderness 0.11 0.11 0.18 0.18 0.56

West Elk Wilderness 0.24 0.24 0.42 0.41 1.26

Weminuche Wilderness 0.58 0.58 0.85 0.83 2.41

Wheeler Peak Wilderness 0.22 0.22 0.34 0.33 1.07
14

Chapter 4: BART Guidelines and Modeling Protocols

4.1 BACKGROUND AND INTRODUCTION

The BART analysis includes engineering and modeling methods and procedures used to 

determine the appropriate controls for the SJGS Units to reduce the source‘s contribution 

to pollutant concentrations that result in visibility impairment in the surrounding Class I 

areas. The final factor to consider under EPA's BART Guidelines is the degree of 

visibility improvement from the BART control options.11 The BART guidelines 

recommend use of the CALPUFF air quality dispersion model to estimate the visibility 

improvements at each Class I area, typically within a 300 km (186 mile) radius of the 

source, of alternative control technologies, and to compare these to each other and to the 

impact of the baseline, or current, source configuration. There are 16 Class I areas within 

300km of the SJGS. These are listed in Table 4-1 and 4-2 and shown in Figure 4-1. The 

measured visibility impairment (in deciviews) at each Class I area is presented in Table 

4-1 as a range of the 10th (mean of Best 20% days) and 90th (mean of Worst 20% days) 

percentiles, averaged for 2007 and 2008.

Table 4-1. Measured Visibility Impairment at Class I areas (2007 – 2008 average) 12

Class I Area 10th Percentile

Deciview Impairment

90th Percentile

Deciview Impairment

Arches 2.9 11.3

Bandelier Wilderness 4.2 12.2

Black Canyon of the Gunnison 

Wilderness 2.2 10.5

Canyonlands 2.9 11.3

Capitol Reef 2.8 11.5

Grand Canyon 2.1 11.2

Great Sand Dunes National Monument 3.5 11.2

La Garita Wilderness 2.2 10.5

Maroon Bells Snowmass Wilderness 0.2 9.3

Mesa Verde 3.1 11.0

Pecos Wilderness 1.2 8.6

Petrified Forest 4.5 12.5

San Pedro Parks Wilderness 2.8 11.3

West Elk Wilderness 0.2 9.3

Weminuche Wilderness 2.2 10.5

Wheeler Peak Wilderness 1.2 8.6

 

11

 59 FR 39104, 39170 (July 6, 2005)

12

 IMPROVE monitoring network (Regional Haze Rule Summary data, Revised (new) IMPROVE 

Algorithm, http://vista.cira.colostate.edu/improve/Data/IMPROVE/summary_data.htm)
15

Figure 4-1. Map of Class I Areas within 300 km of SJGS

Table 4-2. Class I Areas in CALPUFF Modeling for SJGS

Class I Area Abbreviation State Agency IMPROVE 

monitor13

Minimum 

Distance to 

SJGS (km)

Arches arch UT NPS CANY1 222

Bandelier Wilderness band NM NPS BAND1 210

Black Canyon of the 

Gunnison Wilderness blca CO NPS WEMI1 203

Canyonlands cany UT NPS CANY1 170

Capitol Reef care UT NPS CAPI1 232

Grand Canyon grca AZ NPS GRCA2 285

Great Sand Dunes National 

Monument grsa CO NPS GRSA1 269

La Garita Wilderness laga CO USFS WEMI1 169

Maroon Bells Snowmass 

Wilderness mabe CO USFS WHRI1 271

Mesa Verde meve CO NPS MEVE1 40

Pecos Wilderness peco NM NPS WHPE1 248

Petrified Forest pefo AZ NPS PEFO1 213

San Pedro Parks Wilderness sape NM USFS SAPE1 155

Weminuche Wilderness wemi CO USFS WEMI1 98

West Elk Wilderness weel CO USFS WHRI1 216

Wheeler Peak Wilderness whpe NM USFS WHPE1 258

 

13

 For a Class I area without an IMPROVE monitor of its own, the nearest monitor in another area is used.
16

Visibility modeling was performed for the San Juan Generating Station and included the 

sixteen Class I Areas within 300 km of the facility in the modeling analysis. Although 

not officially submitted to EPA, NMED completed a NOx and PM BART determination 

for the SJGS, which EPA found to be thorough and comprehensive.14 Although EPA 

generally regards the visibility modeling analyses performed by NMED to be of high 

quality, some minor issues were noted. EPA remodeled the visibility impacts of SJGS to 

rectify these issues in order to address consistency with modeling guidance EPA has 

provided to the states. NMED and EPA modeling protocols are discussed later in this 

chapter, followed by detailed discussion of model inputs and results in the following 

chapters. 

4.2 CALCULATION OF VISIBILITY IMPACT

Under the RHR, visibility is measured in deciviews. Visibility is traditionally described 

in terms of visual range in kilometers or miles. However, the visual range scale does not 

correspond to how people perceive visibility: a given increase in visual range is perceived 

differently depending on how good the original visibility was (that is, it is not on a linear 

scale). The deciview scale is designed to address this problem. It is linear with respect to 

perceived visual changes over its entire range, analogous to the decibel scale for sound: a 

given change in deciviews will be perceived as the same amount of visibility change, 

whatever the original visibility was. The defining equation is: 

deciviews = 10*ln(bext / 10) 

where ln is the natural logarithm, and extinction bext is the fraction of light scattered out 

of a viewing path. Extinction increases with the amount of pollution (bext is in units of 

1/Mm, ―inverse megameters‖). Lower deciview values represent better visibility, more 

pristine atmospheres, and greater visual range, while increasing deciview values represent 

increasingly poor visibility. An increase of 1 deciview corresponds to about a 10% 

increase in extinction. (Deciviews are related to the more traditional visual range 

according to dv = 10*ln(391 / visual range)). An eligible BART source with a predicted 

impact of 0.5 dv or more of impairment in a Class I area ―contributes‖ to visibility 

impairment and is subject to BART.15 

Under the BART guidelines, deciviews are estimated using the CALPUFF air quality 

model. CALPUFF predicts 24-hour average pollutant concentrations based on source 

emissions and how they disperse in the atmosphere. The CALPUFF modeling includes 

source emissions of the following visibility-impairing pollutants: SO2, SO4, NOx, 

secondary organic aerosol (SOA), fine particulate matter (PMF), coarse particulate matter 

(PMC), and elemental carbon (EC). CALPUFF incorporates a semi-empirical chemical 

 

14

 New Mexico Environment Department, Air Quality Bureau, BART Determination, Public Service 

Company of New Mexico, San Juan Generating Station, Units 1-4, June 21, 2010. Available here: 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/AppxA_NM_SJGS_NOxBARTDetermination_

06212010.pdf

15

 70 FR 39104, 39121 (July 6, 2005).
17

module that simulates the conversion of SO2 to particulate sulfate and NOx to particulate 

nitrate, at a rate dependent on meteorological conditions and background ozone 

concentration. These concentrations are converted to deciviews by the CALPOST postprocessor in two steps. 

4.2.1 IMPROVE Equation

Under the original IMPROVE equation, extinction (bext) is estimated from the predicted 

concentrations of various pollutants: 16

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

+ 3 * f(RH) * [nitrate] 

+ 4 * [organic mass] 

+ 10 * [elemental carbon] 

+ 1 * [fine soil] 

+ 0.6 * [coarse mass] 

+ 10

The 10 that is added accounts for Rayleigh scattering, which is due to the interaction of 

light with molecules of air itself with no pollutants. The f(RH) is a water growth factor 

for sulfate and nitrate; its value depends on relative humidity (RH), ranging from 1 at low 

humidity to 18 at 98% humidity. 

4.2.2 Revised IMPROVE Equation

EPA used the ―revised‖ IMPROVE equation to calculate light extinction.17 The revised 

IMPROVE equation is used to convert measured or modeled concentrations into 

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

effect of relative humidity.

Revised 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)]

 

16

 Interagency Monitoring of Protected Visual Environments (IMPROVE) is a network of monitors in 

various Class I Areas, established to assess visibility impairment and its causes. The IMPROVE 

equation is used to converted monitored concentrations into extinction, a measure of visibility. See: 

http://vista.cira.colostate.edu/improve/

17

 Pitchford, M. L., W. C. Malm, B. A. Schichtel, N. Kumar, D. Lowenthal and J. L. Hand, Revised 

algorithm for estimating light extinction from IMPROVE particle speciation data, Journal of the Air & 

Waste Management Association, 57, 1326-1336, 2007.
18

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 old 1.4. Sea salt is estimated as 1.8 * [chloride] (or chlorine if chloride not available) 

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. Rayleigh scattering is due to the 

interaction of light with molecules of air itself with no pollutants.

The IMPROVE program revised the IMPROVE equation after a scientific assessment of 

its implications for regional haze planning to reduce biases in light extinction estimates 

compared to the old algorithm.18 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 worst 20% visibility days that are used to assess 

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

matching visibility measurements under high and low visibility conditions. The split 

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

IMPROVE equation has less bias, is more refined, accounts for more pollutants, 

incorporates more recent data, and is based on considerations of relevance for the 

calculations needed for assessing progress under the Regional Haze Rule. 

EPA guidance states that the use of either the IMPROVE or the revised IMPROVE

equation is acceptable provided that the same algorithm is utilized for both the base and 

future extinction calculations.19 Since EPA has redone the analysis we have been able to 

incorporate the revised IMPROVE equation, which we believe is appropriate and the 

more preferred method for analyses being conducted at this time.20, 21, 22 EPA has 

 

18

 Revised IMPROVE algorithm for Esimating Light Extinction from Particle Speciation Data, 

IMPROVE, January 2006 

(http://vista.cira.colostate.edu/improve/Publications/GrayLit/gray_literature.htm) ; Hand, J.L., Douglas, 

S.G., 2006, Review of the IMPROVE Equation for Estimating Ambient Light Extinction Coefficients –

Final Report 

(http://vista.cira.colostate.edu/improve/Publications/GrayLit/016_IMPROVEEeqReview/IMPROVEeq

Review.htm)

19

 Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals 

for Ozone, PM2.5, and Regional Haze, EPA-454/B-07-002, April 2007, EPA OAQPS; 

(http://www.epa.gov/ttn/scram/guidance/guide/final-03-pm-rh-guidance.pdf)

20

 U.S. EPA. 2006a. Additional Regional Haze Questions. U.S. Environmental Protections Agency. 

August 3. (http://www.wrapair.org/forums/iwg/documents/Q_and_A_for_Regional_Haze_8-03-

06.pdf#search=%22%22New%20IMPROVE%20equation%22%22).

21

 WRAP presentation, ―Update on IMPROVE Light Extinction Equation and Natural Conditions 

Estimates‖ Tom Moore, May 23, 2006.

22

 U.S. Forest Service, National Park Service, and U.S. Fish and Wildlife Service. 2010. Federal land 

managers‘ air quality related values work group (FLAG): phase I report—revised (2010). Natural 

Resource Report NPS/NRPC/NRR—2010/232. National Park Service, Denver, Colorado.
19

provided alternative calculations using the original IMPROVE equation for comparison 

with these visibility calculation results.

4.2.3 Deciview Impact Calculation

In the second CALPOST step this extinction is converted to deciviews, using the defining 

equation (equation 1) for deciviews. The delta deciviews (Δdv) represents the impact on 

visibility in deciviews of the source being evaluated, and is also provided by CALPUFF. 

It is the change, or ―delta‖, between deciviews with and without the source. Under the 

BART guidelines, delta deciviews is the difference between deciviews including the 

impact of the source and natural background, and deciviews of the natural background 

alone. Each modeled day and location in the Class I area will have an associated delta 

deciview. For each day, the model finds the maximum visibility impact of all locations 

(receptors) in the Class I area. From among these daily values, the BART guidelines 

recommend use of the 98th percentile, roughly equivalent to the 8th highest day, visibility 

impacts expressed as 24-hour averages of delta deciviews relative to natural background, 

as estimated using the CALPUFF air quality modeling system for comparing the base 

case and the effects of various controls. The 98th percentile is recommended rather than 

the maximum value to avoid undue influence from unusual meteorological conditions 

and conservative assumptions in the model. 

The BART guidelines recommend that impacts of sources be estimated in deciviews 

relative to natural background. NMED and EPA used background concentrations (Table 

4-3) from Table 2-1 of ―Guidance for Estimating Natural Visibility Conditions Under the 

Regional Haze Rule‖ for calculations using ―Method 6‖.

23 EPA used average 

background concentrations (Table 4-4) and relative humidity adjustment factors from the 

Federal Land Managers‘ Air Quality Related Values Work Group (FLAG) Phase I Report 

for use with the revised IMPROVE equation (―Method 8‖).24 

Table 4-3. Natural Background Concentrations used by NMED and EPA for ―Method 6‖

CALPOST parameter Pollutant Concentration (μg/m3)

BKSO4 Ammonium sulfate 0.12

BKNO3 Ammonium nitrate 0.10

BKPMC Coarse particulates 3.00

BKOC Organic carbon 0.47

BKSOIL Soil 0.50

BKEC Elemental carbon 0.02

 

23

 U.S. Environmental Protection Agency, Guidance for Estimating Natural Visibility Conditions Under 

the Regional Haze Rule, EPA-454/B-03-005, September 2003, on web page 

http://www.epa.gov/ttn/oarpg/t1/memoranda/rh_envcurhr_gd.pdf

24

 U.S. Forest Service, National Park Service, and U.S. Fish and Wildlife Service. 2010. Federal land 

managers‘ air quality related values work group (FLAG): phase I report—revised (2010). Natural 

Resource Report NPS/NRPC/NRR—2010/232. National Park Service, Denver, Colorado

(http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf)
20

Table 4-4. Natural Background Concentrations used by EPA for ―Method 8‖

Class I Area

CALPOST parameters

BKSALT BKSO4 BKNO3 BKPMC BKOC BKSOIL BKEC

Salt Ammonium 

sulfate

Ammonium 

nitrate

Coarse 

particulates

Organic 

carbon Soil Elemental carbon

Arches 0.01 0.12 0.10 2.92 0.60 0.50 0.02

Bandelier 

Wilderness 0.02 0.12 0.10 2.86 0.60 0.50 0.02

Black Canyon 

of the Gunnison 

Wilderness

0.01 0.12 0.10 2.59 0.60 0.50 0.02

Canyonlands 0.01 0.12 0.10 2.92 0.60 0.50 0.02

Capitol Reef 0.00 0.12 0.10 2.78 0.58 0.50 0.02

Grand Canyon 0.02 0.12 0.10 2.88 0.60 0.50 0.02

Great Sand 

Dunes National 

Monument

0.01 0.12 0.10 2.99 0.58 0.50 0.02

La Garita 

Wilderness 0.01 0.12 0.10 2.59 0.60 0.49 0.02

Maroon Bells 

Snowmass 

Wilderness

0.00 0.12 0.10 2.59 0.60 0.48 0.02

Mesa Verde 0.00 0.12 0.10 2.88 0.60 0.50 0.02

Pecos 

Wilderness

0.03 0.12 0.10 2.29 0.60 0.50 0.02

Petrified Forest 0.01 0.12 0.10 3.00 0.60 0.50 0.02

San Pedro 

Parks 

Wilderness

0.01 0.12 0.10 2.19 0.60 0.50 0.02

Weminuche 

Wilderness 0.00 0.12 0.10 2.12 0.60 0.50 0.02

West Elk 

Wilderness 0.00 0.12 0.10 2.12 0.60 0.50 0.02

Wheeler Peak 

Wilderness 0.00 0.12 0.10 2.29 0.60 0.50 0.02
21

4.3 CALMET/CALPUFF MODELING

4.3.1 Modeling Protocol

The contractor, Black & Veatch (B&V), was hired by PNM toconduct modeling for the 

SJGS according to modeling protocols submitted to NMED.25 NMED reviewed this 

modeling and performed additional modeling following the same general approach. This 

modeling analysis generally followed the BART protocol developed by the WRAP.26 

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, 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 New Mexico. The MM5 fields were then 

processed using CALMET (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 meteorological station 

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

(―no obs‖) mode. 

The NMED modeling protocol followed the WRAP protocol. CALMET and CALPUFF 

settings were almost all the same. One difference to note is that the modeling domain 

was but a subset of the modeling domain used by the WRAP, the New Mexico 

subdomain shown in figure 4-2 was used; all Class I Areas within 300 km of SJGS were 

included. The BART visibility modeling protocol used by B&V was revised to include 

variable background ammonia concentrations and nitrate repartitioning.27 All modeling 

relied on the same MM5 meteorological simulation data and terrain data developed and 

utilized by the WRAP. 

 

25

 Public Service Company of New Mexico San Juan Generating Station Best Available Retrofit 

Technology Analysis, Black and Veatch, June 2007 

(http://www.nmenv.state.nm.us/aqb/reghaz/documents/PNMBARTReport_AppendixO-1.pdf) and 

PNM San Juan Generating Station Refined BART Visibility Results, Black and Veatch, March 31, 

2008

26

 ―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/WRAP_RMC_BART_Protocol_Aug15_2006.pdf

27

 PNM San Juan Generating Station Refined BART Visibility Results, Black and Veatch, March 31, 2008 

(http://www.nmenv.state.nm.us/aqb/reghaz/documents/03312008Final_BART_Modeling_Response_wi

th_Attachments_0331.pdf)
22

Figure 4-2. CALMET and CALPUFF computational domain.

The protocol/modeling methodologies followed by the EPA for modeling visibility 

impacts from SJGS differs from that used by the WRAP and NMED. First, EPA used the 

EPA current approved regulatory versions of the CALPUFF (v. 5.8) modeling system 

which is composed of CALPUFF version 5.8, and CALMET version 5.8. EPA used 

CALPOST version 6.221 that was approved by the Federal Land Managers to allow for 

application of the revised IMPROVE equation (―Method 8‖).28 Some problems have 

been identified in the CALPUFF modeling system (v6.2111) since the original WRAP 

CALPUFF modeling was conducted which is also the version used by PNM‘s contractors 

and NMED.29

 

28

 U.S. Forest Service, National Park Service, and U.S. Fish and Wildlife Service. 2010. Federal land 

managers‘ air quality related values work group (FLAG): phase I report—revised (2010). Natural 

Resource Report NPS/NRPC/NRR—2010/232. National Park Service, Denver, Colorado

(http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf)

29

 ―CALPUFF: Status and Update‖ , Dennis Atkinson, Presentation at Regional/State/Local Modelers 

Workshop, May 16, 2007. 

(http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/archive/2007/presentations/Wednes

day%20-%20May%2016%202007/CALPUFF_status_update.pdf); EPA report, ―Assessment of the 

―VISTAS‖ Version of the CALPUFF Modeling System‖, EPA-454/R-08-007, August 2008 available at 

(http://www.epa.gov/ttn/scram/reports/calpuff_vistas_assessment_report_final.pdf); ―CALPUFF 

Regulatory Update‖, Roger W. Brode, Presentation at Regional/State/Local Modelers Workshop, June 
23

EPA previously performed an analysis of changes to the CALPUFF modeling system that 

were included in the CALPUFF v6.2111 model system (also referred to as the ―VISTAS 

version‖). EPA‘s review indicated that significant differences between the changes 

incorporated in the VISTAS version and the previously EPA approved version of 

CALPUFF (v5.711a) were present. EPA‘s review determined that the majority of the 

concerns were related to the new default parameters THRESHL and THRESHW for the 

threshold buoyancy energy flux over land and water, respectively. The incorporation of 

these new thresholds and other code changes had set up situations where the boundary 

layer could artificially collapse if the sensible heat flux fell below a threshold. This 

impact could occur when the boundary layer is not actually collapsing. Because we wish 

to minimize technical concerns with the CALPUFF modeling system in making a critical 

decision to install controls, we have used the CALPUFF version that has been approved 

by EPA for regulatory purposes that does not include this boundary layer collapsing 

problem or other problems identified with the VISTA‘s version of CALPUFF.

Another difference in our modeling is the option (NOOBS = 0) was selected by EPA in 

order to utilize surface and upper air station observations. For blending in meteorological 

station wind observations, NMED used a maximum radius of influence for stations of 50 

km for surface stations (RMAX1) and 100 km for aloft (RMAX2). R1 (R2) defines the 

distance from an observation at which the surface (upper air) observation and the initial 

wind field are equally weighted and is typically set to half the value of 

RMAX1(RMAX2) in order to transition from the observed value to the modeled value 

over the distance RMAX1. R1 was set at 100 km and R2 at 200 km in the WRAP and 

NMED modeling which can lead to more sudden transitions in wind fields at the distance 

of RMAX1. Per FLM and EPA‘s recommendations, EPA increased these values to 100

km and 200 km, respectively.30 Various relevant CALMET option settings are listed in 

Table 4-5. 

For visibility calculations, the pollution concentration predictions of CALPUFF are used 

in post-processing. CALPUFF modeling was performed for each unit separately. 

Pollution concentration predictions were then summed together to evaluate the facilitywide impacts before the post-processing steps described here. First, POSTUTIL 

considers ammonia background concentrations, temperature, and humidity to determine 

how much nitrate ends up as particulate ammonium nitrate; this is to reflect the 

competition between sulfate and nitrate for available ammonia and is referred to as 

―Nitrate Repartitioning.‖ Ammonia background is discussed further below. Second, 

CALPOST uses the adjusted concentrations to calculate visibility using the IMPROVE 

equation, as described above. The WRAP and B&V protocols specified visibility 

calculation ―Method 6‖ in CALPOST, which utilizes the original IMPROVE equation. 

 

10-12, 2008, available at 

(http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/archive/2008/presentations/BRODE

_CA.pdf).

30

 Memorandum from Tyler Fox (EPA OAQPS) ―Clarification on EPA-FLM Recommended Settings for 

CALMET,‖ August 31, 2009 (http://www.epa.gov/ttn/scram/CALMET%20CLARIFICATION.pdf)
24

EPA ran CALPOST using ―Method 6‖ to allow comparison with previous WRAP, B&V 

and NM modeling. EPA also calculated visibility impacts using ―Method 8,‖ which uses 

the revised IMPROVE equation to calculate visibility using the adjusted concentrations

and used this approach in doing our evaluation of visibility impacts from proposed 

reductions in NOx. 
25

Table 4-5. Selected CALMET settings for SJGS

Option Description EPA 

default

WRAP NMED31 EPA Comments on EPA options

version CALMET version 5.8, 

level

070623

6.211, 

level 

060414

6.211, 

level 

060414

5.8, level 

070623

NOOBS No Observation 

Mode

0 2 1 0 Per FLM recommendation use 

both surface and upper air 

observations

ICLOUD gridded cloud fields 0 0 0 0

IWFCOD diagnostic winds 1 1 1 1

IFRADJ Froude wind adj. 1 1 1 1

IKINE kinematic effects 0 0 0 0

IOBR O'Brien vertical wind 

adj.

0 0 0 0

ISLOPE slope flows 1 1 1 1

IEXTRP extrapolate wind to 

upper air

-4 1 1 -4

ICALM extrapolate calm to 

upper air

0 0 0 0

BIAS layer biases sfc vs. 

UA

NZ*0 NZ*0 NZ*0 -1,0,0,0,0,

0,0,0,0,0,0

IPROG gridded initial 

prognostic

0 14 14 14 Use prognostic inputs from 

MM5

RMAX1 max surface radius of 

influence

NA 50 50 100 Per FLM recommendation

RMAX2 max aloft radius of 

influence

NA 100 100 200 Per FLM recommendation

RMAX3 max over-water 

radius of influence.

NA 100 100 100

RMIN min wind radius of 

influence.

0.1 0.1 0.1 .1

RMIN2 min dist sfc winds 

extrap

4 4 4 4

TERRAD terrain radius of in 

influence

NA 10 10 10

R1 weight surface Step 1 

vs. obs

NA 100 100 50 Per FLM recommendation, 

equally weighs observation and 

prediction at midpoint of 

RMAX1

R2 weight aloft Step 1 

vs. obs

NA 200 200 100 Per FLM recommendation, 

equally weighs observation and 

prediction at midpoint of 

RMAX2

ITPROG 3D T from obs or 

prognostic

0 1 or 2 

implied

1 0

TRADKM radius of influ. for T 

interp.

500 500 500 500

IAVET spatial T averaging 1 0 1 1 Smoothing turned on (WRAP 

thought MM5 already smooth 

enough)

JWAT1 starting land use for 

T interp. over water

999 51 55 55 This area has very little "water" 

land use; may set to 999 to 

disable overwater feature

JWAT2 ending land use for T 

interp. over water

999 55 55 55

 

31

 PNM SJGS Best Available Retrofit Technology Analysis, Black and Veatch, June 2007, 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/PNMBARTReport_AppendixO-1.pdf
26

To assess the variability from the different CALMET version change we utilized the 

same criteria pollutant emission rates and the same ammonia and H2SO4 emission rates as 

documented in the B&V modeling. Table 4-6 shows the difference in visibility impacts 

due to the different CALMET version and settings used by EPA, including the inclusion 

of upper air data. CALPUFF and CALPOST were run with the same post-consent decree 

emissions rates and options as those used by B&V in their visibility modeling. 

This does show some differences between the two approaches, but overall the level of 

visibility impact from the SJGS is similar in total delta deciview with the EPA approach 

yielding a value slightly lower than the B&V modeling (17.84 dv vs. 19.86 dv for the 

cumulative average). While impacts at individual Class I areas varied, the overall 

magnitude of impact was slightly less, but similar. This information helps to support the 

conclusion that the differences due to the operation of CALMET in accordance with the 

WRAP protocol several years ago and the current regulatory approach that EPA has 

conducted in this action would not likely change the original determination by the WRAP 

and NMED of which sources screen out of BART and which are subject to a full BART 

analysis. Therefore EPA is proposing to conclude that of the BART eligible sources 

identified by NMED and the WRAP, only the SJGS units are subject to BART. 
27

Table 4-6. Impacts of SJGS on Visibility using B&V post-consent decree baseline 

emissions (average of 98th percentile of daily maximum dv for 2001, 2002, and 2003) at 

Sixteen Class I Areas

Class I Area

Distance 

to SJGS 

(km)

B&V modeling with CALMET 

6.211

EPA modeling with CALMET 

5.8

2001 2002 2003 Average 2001 2002 2003 Average

Arches 222 1.69 1.65 1.49 1.61 1.99 0.81 0.98 1.26

Bandelier Wilderness 210 1.04 1.56 1.20 1.27 1.12 1.02 0.84 1.00

Black Canyon of the 

Gunnison Wilderness 203 0.95 1.15 1.07 1.05 0.96 1.27 0.63 0.95

Canyonlands 170 2.26 1.73 1.68 1.89 2.32 1.35 1.28 1.65

Capitol Reef 232 1.81 0.82 1.05 1.23 1.64 0.48 0.72 0.95

Grand Canyon 285 0.97 0.76 0.57 0.77 0.73 0.29 0.35 0.46

Great Sand Dunes 

National Monument 269 0.63 0.71 0.64 0.66 0.87 1.28 1.04 1.06

La Garita Wilderness 169 0.86 0.94 0.90 0.9 0.95 1.64 0.82 1.14

Maroon Bells 

Snowmass 

Wilderness

271 0.54 0.56 0.51 0.54 0.61 0.58 0.31 0.50

Mesa Verde 40 3.38 3.53 3.8 3.57 2.68 3.21 2.99 2.96

Pecos Wilderness 248 1.05 1.09 1.00 1.05 0.74 1.02 0.8 0.85

Petrified Forest 213 0.82 0.60 0.53 0.65 0.52 0.38 0.42 0.44

San Pedro Parks 

Wilderness 155 1.40 2.01 1.56 1.66 1.35 1.42 1.25 1.34

Weminuche 

Wilderness 98 1.15 1.48 1.34 1.33 1.43 1.96 1.41 1.60

West Elk Wilderness 216 0.8 0.91 0.83 0.85 0.88 1.09 0.52 0.83

Wheeler Peak 

Wilderness 258 0.75 0.86 0.89 0.83 0.88 0.95 0.75 0.86

Total Delta dv 20.1 20.36 19.06 19.86 19.67 18.75 15.10 17.84

In addition to the general modeling procedures, we must address two additional 

pollutants when estimating the impact of various control technologies on visibility 

improvement: ammonia (NH3) and sulfuric acid (H2SO4). 

4.3.2 Ammonia

Ammonia is important because it is a precursor to particulate ammonium sulfate and 

ammonium nitrate, both of which degrade visibility. It is present in the atmosphere from 

both natural and anthropogenic sources. The latter may include livestock operations, 

fertilizer application associated with farming, and ammonia slip (or un-reacted ammonia) 

from its use in SCR or SNCR to control NOx emissions. 
28

4.3.3 Sulfuric Acid

Sulfuric acid (H2SO4) is formed from coal-fired power plants from the oxidation of sulfur 

dioxide (SO2) to sulfur trioxide (SO3) and the subsequent reaction of SO3 with water 

vapor (SO3 + H2O = H2SO4). Sulfuric acid (also known as sulfuric acid mist) can 

combine with ammonia to form particulate ammonium sulfate, which is an important 

contributor to visibility impairment. CALPUFF models emissions of H2SO4 as inorganic 

particulate sulfate. 

We will address these two additional pollutants when estimating the impact of various 

control technologies on visibility improvement: ammonia (NH3) and sulfuric acid 

(H2SO4) in greater detail in the next Chapters. 
29

Chapter 5: B&V Approach 

5.1 B&V MODELING INPUTS

5.1.1 Sulfuric Acid Emission Estimates

B&V estimated sulfuric acid released from combustion by using the U.S. National Park 

Service (NPS) speciation worksheet and assuming that all inorganic condensable PM is 

H2SO4.

32

 Sulfuric acid due to SCR operation was calculated assuming 1% conversion of 

SO2 to SO3 based on the economizer outlet emission of SO2. Removal efficiencies for 

the PJFF and FGD system were applied to the sulfuric acid produced by the SCR. Table 

5-1 outlines the assumptions used by B&V for the sulfuric acid calculation.

Table 5-1. Assumptions Used by B&V for H2SO4 Emission Estimates 

Unit 1 Unit 2 Unit 3 Unit 4

Controlled SO3 emissions (lb/hr) from boiler33 40.5 40.3 62.9 61.7

Economizer SO2 emissions (lb/hr)34 5,884 5,854 9,140 8,967

Conversion of SO2 to SO3 due to SCR (%) assumed by B&V 

based on economizer SO2 emissions35 1% 1% 1% 1%

% Removal by PJFF (for inherent removal scenario)36 50% 50% 50% 50%

% Removal by FGD system (for inherent removal scenario)37 40% 40% 40% 40%

5.1.2 Background Ammonia Concentration

As discussed above, in addition to emissions from the facility, the background ammonia 

concentrations must be specified for the model. The IWAQM default value for ammonia 

background in this region is 1 ppb year-round. The revised B&V modeling used 

background ammonia concentrations that vary monthly based on concentrations used for 

the PSD ambient air quality impacts analysis for the Desert Rock Energy Center. Table 

5-2 compares the IWAQM default values with the ammonia values used by B&V.

Table 5-2. Ammonia background concentration in ppb 

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

IWAQM default 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

B&V values 0.2 0.2 0.5 0.5 1.0 1.0 1.0 1.0 1.0 0.5 0.5 0.2

 

32

 From Dry Bottom PC w FGD+FF PM Speciation Profile, PM10 Speciation is from AP-42 Tables 1.1-5 

& 1.1-6 (http://www.nature.nps.gov/air/permits/ect/ectCoalFiredBoiler.cfm). All inorganic 

condensable PM was assumed to be H2SO4. 

33

 Public Service Company of New Mexico San Juan Generating Station Best Available Retrofit 

Technology Analysis, Black and Veatch, June 2007

34

 Id.

35

 Id.

36

 PNM San Juan Generating Station Review of Inherent SO3 Removal Scenarios and Sorbent Injection 

for SO3 Removal, Black and Veatch, March 16, 2009, 

(http://www.nmenv.state.nm.us/aqb/reghaz/documents/COMPLETE_Final_SO3_Removal_Report_031

609.pdf)

37

 Id.
30

5.1.3 B&V Modeling Scenarios

Although not officially submitted to us, NMED completed a NOx and PM BART 

determination for the SJGS (referred to herein as the ―NMED BART evaluation‖), which 

we have found to be thorough and comprehensive.38 In making our NOx BART 

determination for the SJGS, we drew heavily upon the NOx BART portion of that 

document, and used it to help inform our NOx BART determination for the SJGS. 

NMED concluded that, other than SCR, none of the NOx control technologies were 

capable of significantly improving the visibility at any of the 16 Class I areas, therefore, 

we did not further evaluate them. We note that SCR was capable of uniformly improving 

the visibility at all of the 16 Class I areas. 

Table 5-3 summarizes the emission inputs NMED used for visibility modeling for SJGS. 

Although NMED included a number of control scenarios in addition to SCR in their 

modeling, we focused on the SCR control scenarios as detailed above. We note that this 

modeling conducted by NMED was performed in accordance with the WRAP protocol 

and therefore did differ from the CALPUFF modeling system approach that EPA is 

utilizing in this action. As we noted in the last section, we conducted a sensitivity test to 

assess the potential changes in delta deciview that may occur due to these differences and 

concluded that the results from the two approaches give similar results that when 

weighed in a relative sense, yield the same conclusions. Therefore, EPA believes that 

even if we had redone the NMED analysis for controls other than SCR based controls, 

that our conclusion that controls utilizing SCR (or equivalent technology) and the 

proposed emission limit levels would be the only scenario that would be beneficial in 

reducing visibility impacts and being cost effective.

The modeling scenarios presented here are the B&V baseline (post consent decree) 

emissions, B&V emission inputs for the SCR control case,39 SCR with removal of SO3

from inherent controls, and SCR with sorbent injection.40 B&V assumed an SCR 

controlled emission rate of 0.07 lb/MMBtu for NOx. SO2 and total filterable particulate 

(PM10) emissions were held at the post-consent decree rates of 0.18 lb/MMBtu for SO2

and 0.015 lb/MMBtu for PM10 for visibility modeling. 

 

38

 New Mexico Environment Department, Air Quality Bureau, BART Determination, Public Service 

Company of New Mexico, San Juan Generating Station, Units 1-4, June 21, 2010. Available here: 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/AppxA_NM_SJGS_NOxBARTDetermination_0

6212010.pdf

39

 Public Service Company of New Mexico San Juan Generating Station Best Available Retrofit 

Technology Analysis, Black and Veatch, June 2007 

(http://www.nmenv.state.nm.us/aqb/reghaz/documents/PNMBARTReport_AppendixO-1.pdf) and 

PNM San Juan Generating Station Refined BART Visibility Results, Black and Veatch, March 31, 

2008 

(http://www.nmenv.state.nm.us/aqb/reghaz/documents/03312008Final_BART_Modeling_Response_wi

th_Attachments_0331.pdf)

40

 PNM San Juan Generating Station Review of Inherent SO3 Removal Scenarios and Sorbent Injection 

for SO3 Removal, Black and Veatch, March 16, 2009 

(http://www.nmenv.state.nm.us/aqb/reghaz/documents/COMPLETE_Final_SO3_Removal_Report_031

609.pdf)
31

Table 5-3. CALPUFF Modeling Emission Inputs (lb/hr)

Unit 1 Unit 2 Unit 3 Unit 4

B&V Baseline (post-consent decree controls)

SO2 667.26 663.84 1036.44 1016.82

SO4 40.5 40.3 62.9 61.7

NOx 1223.31 1217.04 1900.14 1864.17

SOA 10.1 10.1 15.7 15.4

PM fine 32 31.9 49.8 48.8

PM coarse 23.6 23.5 36.6 35.9

EC 1.0 1.0 1.6 1.6

B&V SCR control scenario

SO2 667.26 663.84 1036.44 1016.82

SO4 114.2 113.6 177.3 174

NOx 259.49 258.16 403.06 395.43

SOA 10.1 10.1 15.7 15.4

PM fine 32 31.9 49.8 48.8

PM coarse 23.6 23.5 36.6 35.9

EC 1.0 1.0 1.6 1.6

B&V SCR w/ inherent removal control scenario

SO2 667.26 663.84 1036.44 1016.82

SO4 62.61 62.29 97.22 95.39

NOx 259.49 258.16 403.06 395.43

SOA 10.1 10.1 15.7 15.4

PM fine 32 31.9 49.8 48.8

PM coarse 23.6 23.5 36.6 35.9

EC 1.0 1.0 1.6 1.6

B&V SCR w/ sorbent injection control scenario

SO2 667.26 663.84 1036.44 1016.82

SO4 16.09 16.01 24.99 24.52

NOx 259.49 258.16 403.06 395.43

SOA 10.1 10.1 15.7 15.4

PM fine 32 31.9 49.8 48.8

PM coarse 23.6 23.5 36.6 35.9

EC 1.0 1.0 1.6 1.6

Note that all particulate modeling was performed using 1 gram per second nominal 

emission rates in CALPUFF for the specific size ranges presented in the NPS speciation 

spreadsheets (i.e., PM8.0, PM4.25, PM1.88, PM1.25, PM0.813, and PM0.625). 41 These modeled 

species are grouped in POSTUTIL as to represent the appropriate visibility pollutants 

(e.g., PMcourse = PM8.0 + PM4.25 and PMfine = PM1.88 + PM1.25 + PM0.813 + PM0.625) and 

are then scaled with the emission rates derived from the NPS spreadsheets. EC and SOA 

are derived from the PM1.88 species and scaled with the emission rates derived from the 

NPS spreadsheets.

 

41

 Dry Bottom PC w FGD+FF PM Speciation Profile, PM10 Speciation is from AP-42 Tables 1.1-5 & 

1.1-6 (http://www.nature.nps.gov/air/permits/ect/ectCoalFiredBoiler.cfm)
32

Although the control technology scenarios may be the same (e.g. SCR on Units 1 – 4), 

the assumptions and control level emission rates will differ between the scenarios 

modeled by B&V previously and the final scenarios that EPA has conducted for this 

analysis. For example, based on more recent information, different assumptions and 

methodology in calculating emissions of H2SO4 resulted in different H2SO4 emission rate 

inputs for visibility modeling. 

5.2 RESULTS OF NMED VISIBILITY MODELING

NMED presented various control scenarios‘ visibility improvements in terms of the 98th

percentile (8th highest) of the daily maximum delta deciviews from CALPUFF for each

Class I area, averaged over 2001 – 2003 and the maximum of the 98th Percentile of daily 

maximum dv for 2001, 2002 and 2003. As outlined in the 1999 Regional Haze rule (64 

FR 35725, July 1, 1999), a one deciview change in visibility impairment is a small but 

perceptible change under most circumstances when viewing scenes in a Class I area. 

Table 5-4 presents the impact of SJGS on visibility at each Class I area, based on the 98th

percentile of daily maxima from 2001 – 2003, as modeled by NMED. NMED modeling 

indicates significant improvements in visibility are achieved through the use of SCR and 

sorbent injection. Based on all factors, including visibility impacts, NMED proposed to 

conclude that BART for the SJGS was SCR plus sorbent injection. 

Except for the following points, we agree with NMED‘s proposed conclusions regarding 

BART for SJGS:

NMED evaluated the visibility benefits of SCR at the SJGS based on a NOx 

emission limit of 0.07 lbs/MMBtu, but noted the potential for greater control at 

rates as low as 0.03 lbs/MMBtu. We have concluded that a NOx emission limit 

of 0.05 lbs/MMBtu is achievable for the SJGS through operation of SCR, and 

performed our visibility modeling on that basis.

NMED concluded BART for the SJGS was SCR plus sorbent injection to remove 

sulfur trioxide (SO3) in the flue gas by reaction with an alkaline material. We 

have concluded that sorbent injection is not necessary, as the SJGS burns a low 

sulfur coal, and catalysts are available with a low SO2 to SO3 conversion rate. 

Our estimates of sulfuric acid emissions from SJGS with SCR installed are 

significantly lower than those presented by NMED in their analysis, but are closer 

in magnitude to the emission rates that PNM has reported for the SJGS for EPA‘s 

annual Toxic Release Inventory (TRI).42

Theses points are discussed further in the following chapter. 

 

42

 TRI data is available at http://www.epa.gov/tri/tridata/current_data/index.html. 2009 data is considered 

preliminary.
33

Table 5-4. NMED Modeling Results -- Impacts of SJGS on Visibility (average of 98th percentile of daily maximum dv for 2001, 

2002, and 2003) at Sixteen Class I Areas 

Class I Area Distance to 

SJGS (km)

Visibility Impact ( dv) after applying: Visibility improvement over baseline ( dv)

Baseline (postconsent decree) SCR43 SCR (w/ inherent 

reductions)44

SCR (w/ 

sorbent 

injection)45

SCR

SCR (w/ 

inherent 

reductions)

SCR (w/ 

sorbent

injection)

Arches 222 1.61 1.54 1.25 0.96 0.07 0.36 0.65

Bandelier Wilderness 210 1.27 1.16 0.92 0.72 0.11 0.35 0.55

Black Canyon of the 

Gunnison Wilderness 203 1.05 0.85 0.71 0.57 0.2 0.34 0.48

Canyonlands 170 1.89 2.01 1.61 1.32 -0.12 0.28 0.57

Capitol Reef 232 1.23 1.06 0.93 0.78 0.17 0.3 0.45

Grand Canyon 285 0.77 0.63 0.54 0.46 0.14 0.23 0.31

Great Sand Dunes 

National Monument 269 0.66 0.53 0.46 0.35 0.13 0.2 0.31

La Garita Wilderness 169 0.9 0.66 0.54 0.43 0.24 0.36 0.47

Maroon Bells Snowmass 

Wilderness 271 0.54 0.39 0.33 0.26 0.15 0.21 0.28

Mesa Verde 40 3.57 5.55 4.02 2.37 -1.98 -0.45 1.2

Pecos Wilderness 248 1.05 0.92 0.77 0.60 0.13 0.28 0.45

Petrified Forest 213 0.65 0.61 0.51 0.43 0.04 0.14 0.22

San Pedro Parks 

Wilderness 155 1.66 1.87 1.46 1.09 -0.21 0.2 0.57

Weminuche Wilderness 98 1.33 1.4 0.99 0.70 -0.07 0.34 0.63

West Elk Wilderness 216 0.85 0.64 0.53 0.41 .21 0.32 0.44

Wheeler Peak 

Wilderness 258 0.83 0.67 0.58 0.47 0.16 0.25 0.36

Total Delta dv 19.86 20.49 16.15 11.92 -0.63 3.71 7.94

 

43

 PNM San Juan Generating Station Refined BART Visibility Results, Black and Veatch, March 31, 2008 

(http://www.nmenv.state.nm.us/aqb/reghaz/documents/03312008Final_BART_Modeling_Response_with_Attachments_0331.pdf)

44

 PNM San Juan Generating Station Review of Inherent SO3 Removal Scenarios and Sorbent Injection for SO3 Removal, Black and Veatch, March 16, 2009 

 (http://www.nmenv.state.nm.us/aqb/reghaz/documents/COMPLETE_Final_SO3_Removal_Report_031609.pdf

45

 Id.
34

Chapter 6: EPA approach 

6.1 EPA MODELING INPUTS

6.1.1 NOx Emission Rate

PNM assumed a controlled emission rate resulting from installation of SCR of 0.07 

lb/MMBtu. NMED evaluated the visibility benefits of SCR at the SJGS based on this 

emission limit, but noted the potential for greater control at rates as low as 0.03 

lbs/MMBtu. NOx continuous emission monitor (CEM) data from the EPA Clean Air 

Markets Division show that SCR retrofits routinely result in 90% removal efficiency. We 

have concluded that a NOx emission limit of 0.05 lbs/MMBtu on a 30-day rolling 

average for each unit is achievable at the SJGS (~83% control from baseline of 0.30), and 

performed our visibility modeling on that basis. Additional supporting information on 

the attainable efficiency of SCR is available in the cost effectiveness analysis.46 

 

6.1.2 SO2 Emission Rate

As previously discussed, there are no federally enforceable limits that restrict the SJGS‘s 

SO2 emissions to a maximum emission rate of 0.15 lbs/MMBtu or less, the rate assumed

by the WRAP in its photochemical modeling, or the 0.18 lbs/MMBtu that was used for 

modeling visibility impacts of SJGS by NMED. 

In a permit modification to the construction permit for SJGS, NMED issued a revised 

construction permit (NSR Air Quality Permit No. 0063-M6) on April 22, 2008 to 

incorporate some of the conditions from the consent decree that include a 90% reduction 

in SO2 emissions based on the annual average sulfur content in the coal combusted in the 

SJGS‘s four units and 0.250 lb/MMBtu on a 7-day block average for each unit.

47

 We 

also note that for the four SJGS units the consent decree limits of 0.30 lb/MMBtu of NOx 

on a 30-day rolling average is less restrictive than the 0.27 and 0.28 lb/MMBtu of NOx 

emission rates that were included in the WRAP‘s photochemical modeling that is being 

used for assessing daily visibility impacts. Thus the NOx permit limits are also at a 

higher level than what the WRAP modeling assumed. This permit has since been 

superceded by a further construction permit modification that also includes the consent 

decree limits on NOx and SO2 emissions and is federally enforceable.48 

However as previously discussed, EPA does not believe this permit, or other applicable 

requirements, provides the necessary emission limits and enforceable mechanisms to 

ensure the levels used in the WRAP photochemical modeling for the NOx and SO2

 

46

 Revised BART Cost Effectiveness Analysis for Selective Catalytic Reduction at the Public Service 

Company of New Mexico San Juan Generating Station Final Report, Phyllis Fox, November 2010.

47

 NOx limit of 0.30 lb/MMBtu on a 30-day rolling average for each of the four units; SO2 limit of 90% 

annual average control for each unit, with a short-term limit not to exceed 0.250 lb/MMBtu for a sevenday block average.

48

 New Mexico Environment Department Air Quality Bureau NSR Air Quality Permit No. 0063-M6R1 

was issued on September 12, 2008 and superceded Permit No. 0063-M6.
35

emissions of the SJGS units. Since other WRAP states are using levels modeled for the 

SJGS units in their demonstration of reasonable progress towards natural visibility 

conditions, any discrepancies between what was included in the WRAP photochemical 

modeling and what is presently enforceable, is a concern for this action. EPA must 

establish federally enforceable limits for pollutants that impact visibility projections 

within the WRAP photochemical modeling. 

EPA used the proposed emission rate of 0.15 lb/MMBtu, which is consistent with the 

presumptive BART limit that was assumed by the WRAP, for modeling visibility impacts 

of SJGS. EPA notes that an examination of the SJGS‘s actual emission rates based on 

emissions reported by EPA‘s Clean Air Markets Division indicates units 1, 2, 3, and 4 of 

the SJGS are already meeting these lower SO2 emission limits.49 

6.1.3 Sulfuric Acid Emission Estimates

EPA used calculations by the NPS submitted to NMED in response to the proposed 

Regional Haze SIP and later revised that differed from certain assumptions and 

methodology used by NMED for SJGS to calculate the sulfuric acid emissions.50, 51 In 

particular, the amount of sulfuric acid produced during combustion, the rate of SO2 to 

SO3 oxidation from the SCR catalyst and the amount of sulfuric acid that penetrates 

through (or is lost to) the downstream equipment differed from SJGS and NMED‘s. 

Sulfuric acid emissions from power plants were calculated by NPS by estimating the 

amount of H2SO4 produced and the amount of H2SO4 removed by control equipment 

using information from the Electric Power Research Institute (EPRI).52 These 

calculations rely on assumed values for the amount of fuel sulfur converted to SO2, the 

amount of SO2 oxidized to SO3, and the amount of H2SO4 lost to (or mitigated by) the air 

preheater and applicable control equipment, such as baghouses, and FGDs. Baseline and 

post-control estimates of H2SO4 from SJGS are based on the best current information 

available from EPRI and coal properties (Table 6-1).

6.1.3.1 Assumptions used in Sulfuric Acid Emission Calculations 

 

49

 http://camddataandmaps.epa.gov/gdm/index.cfm

50

 Comments of the National Park Service and US Fish and Wildlife Service Regarding the New Mexico 

Regional Haze State Implementation Plan August 17, 2010 

(http://www.nmenv.state.nm.us/aqb/reghaz/documents/FWS-NPS_CommentsNewMexicoRegionalHazeSIP-17AUG2010.pdf)

51

 Don Shepherd to Michael Feldman, EPA Region 6 (electronic mail) dated Nov. 1, 2010 – revised NPS 

calculations to correct for errors in penetration factors. 

52

 Electric Power Research Institute, Estimating Total Sulfuric Acid Emissions from Stationary Power 

Plants, 1016384, technical Update, March 2008. (from this point forward this document is referred to as 

EPRI 2008).
36

Table 6-1. Assumptions used in Sulfuric acid (H2SO4) Emissions Calculations by 

NPS.53

EPRI Parameter EPA (revised 

NPS 

calculations)

Fuel Impact Factor (SO3 formation from 

combustion)

0.00111

Coal sulfur content (%) 0.77

Coal S conversion to SO2 0.875

Conversion of SO2 to SO3 from SCR catalyst 

(%)

0.5

Penetration factorthrough Scrubber54 0.4

Penetration factor through Air Preheater 0.49

Penetration factor through Baghouse 0.1

The following discussion provides a brief summary of each assumption used in the 

sulfuric acid emissions calculation. 

The amount of fuel sulfur that is oxidized to SO2 is estimated for three different coal 

types. Hardman et al. (1998) report sulfur conversion to SO2 (based on AP-42) to be 0.95 

for bituminous coal, 0.875 for subbituminous coal, and 0.55 – 0.85 for lignite coal, based 

on sodium (Na) content. NPS calculations relied on the value of 0.875.55 

For coal-fired power plants without SCR, SO3 is only formed during the combustion 

process. The amount of SO2 that is oxidized to SO3 during combustion depends on coal 

type and the type of boiler. SO3 reacts rapidly with water to form sulfuric acid. 

Measurements of SO3 production show a wide range (0.00111 – 0.016) but many of the 

values reported in the EPRI 2008 document are based on single measurements. EPRI 

2008 and Harrison 2005 both report the SO3 production factor from Western bituminous 

coal from dry bottom boilers to be 0.00111, or 0.111% of SO2 production, and NPS used 

this value.56

For coal-fired power plants with SCR, SO3 is also formed as a result of oxidation of SO2

to SO3 on the SCR catalyst. NMED assumed a 1% conversion of SO2 to SO3 across the 

SCR catalyst layers, whereas NPS used 0.5% conversion efficiency because low 

conversion catalysts are commercially available to specifically reduce H2SO4 formation 

following the application of SCR.57 In a paper presented in the Proceedings of the 2006 

 

53

 Don Shepherd to Michael Feldman, EPA Region 6 (electronic mail) dated Nov. 1, 2010 – revised NPS 

calculations to correct for errors in penetration factors. 

54

 Penetration factor = 1 - Control Efficiency

55

 Hardman, R., R. Stacy, E. Dismukes. Estimating Total Sulfuric Acid Emissions from Coal-Fired Power 

Plants. Southern Company Services, Revised September 1998.

56

 Harrison, K.E., L.S. Monroe, J.E. Cichanowicz, Estimating Total Sulfuric Acid Emissions from 

Stationary Power Plants: Revision 3 (2005). Southern Company Services, October 2005. (from this 

point forward this document is referred to as Harrison 2005).

57

 Emails between Anita Lee, EPA Region 9 and Anthony C. Favale P.E., Director - SCR Products, 

Hitachi Power Systems America, Ltd. Favale: ―Catalyst development has progressed over the last few 
37

Environmental Controls Conference, written by Hitachi Power Systems America, 

American Electric Power, and Babcock-Hitachi,58 the authors state that conversion rates 

as low as 0.1% have been achieved. Although NPS and EPA recognize that the rate 

achieved may be much lower than the guarantee, to be conservative, EPA has determined 

that a 0.5% conversion rate is most appropriate for sulfuric acid estimates used in the 

visibility modeling. 

 

At SJGS, H2SO4 removal can occur in the air preheaters, scrubbers and baghouses. 

Removal efficiencies from the air preheaters are not available from EPRI 2008 and other 

references for non-Powder River Basin (PRB) Western bituminous coal, and only one 

datum point is available for PRB coal. EPRI 2008 reports penetration factors of 0.49 

(Low Sulfur Eastern Bituminous coal), 0.85 (Med-High Sulfur Eastern Bituminous coal) 

and 0.56 (PRB coal). Most data is available for low-sulfur Eastern bituminous coal: 

measurements from eight units show a range of percent removal from 0 – 69%. Before 

calculating the average percent removal of H2SO4 observed from low-sulfur Eastern 

bituminous coal, EPRI 2008 and Harrison 2005 excluded the 0% removal value because 

―the data point showing 0% removal at approximately 600 ppm SO2 is believed suspect, 

as an identical companion unit firing the same coal exhibited sulfuric acid capture of 

38%‖. Because data from other coal types was not available, EPRI 2008 and Harrison 

2005 suggested that western coals with acidic ash (e.g., bituminous) may consider 

adopting the low sulfur, eastern bituminous value of 0.49 for the H2SO4 penetration (1-

removal), which is equivalent to 51% removal. NPS used the 0.49 value for the air 

preheater penetration factor suggested for coal with low alkalinity ash. 

Downstream of the air preheater, H2SO4 is also reduced by PM and SO2 control 

equipment. All SJGS Units are equipped with wet limestone scrubbers and baghouses for 

SO2 and PM control. NPS used the EPRI-recommended penetration factors of 0.4 

through the wet scrubber and 0.1 through the baghouses. 

6.1.3.2 Comparison of Sulfuric Acid Emission Estimates

NMED concluded BART for the SJGS was SCR plus sorbent injection to remove sulfur 

trioxide (SO3) in the flue gas. We have concluded that sorbent injection is not necessary 

based on the the coal having a low sulfur content, the availability of a low reaction SCR 

catalyst and calculations performed by NPS. Sulfuric acid emissions calculated by the 

NPS using the above methodology are significantly lower than those calculated by 

NMED based on their assumptions and methodology. 

A federal law called the Emergency Planning and Community Right to Know Act 

(EPCRA) requires that facilities report information on the toxic chemicals being released 

into the environment. The law requires facilities in certain industries, which 

 

years to the point that an initial SO2 conversion rate of 0.5% can be guaranteed with 80 to 90% NOx 

reduction.‖

58

 Application and Operating Results of Low SO2 to SO3 Conversion Rate Catalyst for DeNOx 

Application at AEP Gavin Unit 1, Anthony C. Favale, P.E. Presenter 

(http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/Favale_Summary.pdf)
38

manufacture, process, or use significant amounts of toxic chemicals, to report annually on 

their releases of these chemicals. The reports contain information about the types and 

amounts of toxic chemicals that are released each year. EPA maintains this information 

in a database called the Toxics Release Inventory (TRI). Reporting sulfuric acid 

emissions are included in this requirement. SJGS reports annual estimates of emissions 

of sulfuric acid and other toxic chemicals to the TRI. Table 6-2 compares the estimated 

sulfuric acid emissions from the TRI with those used in visibility modeling. Emissions 

estimated by NMED are much higher than those submitted by SJGS to the TRI. EPA 

emission estimates include removal of sulfuric acid due to downstream equipment 

including, the air preheater, scrubbers, and baghouse. Installation of this equipment on 

all four units was not complete until spring of 2009. 

Table 6-2. SJGS Facility-Wide Sulfuric Acid Emission Estimates

Reported emissions59 Hourly emissions60

TRI 2007 72000 lb/yr 9.7 lb/hr

TRI 2008 55000 lb/yr 7.4 lb/hr

TRI 2009 35553 lb/yr 4.8 lb/hr

NMED post-consent decree baseline --- 205.4 lb/hr

EPA post-consent decree baseline --- 0.87 lb/hr

6.1.3.3 Sulfuric Acid Emission Limit

EPA believes that these estimates of H2SO4 emissions are appropriate based on the use of 

low reactivity catalyst that will reduce the rate of SO2 to SO3 conversion. To ensure these 

levels are met, EPA is proposing that emissions of H2SO4 be limited to 1.06 x 10-4

lb/MMBtu. This emission limit is based on the most current information from EPRI,

information on the sulfur content of the coal, and assuming a maximum of 0.5% SO2 to 

SO3 conversion efficiency of the SCR catalyst. These emission limits are consistent with 

that used in visibility modeling discussed in this section. 

EPA notes that there are some assumptions and uncertainty in calculations of sulfuric 

acid mist emissions. Therefore, an alternate approach based on information from PNM‘s 

TRI report and previous PNM calculations of the amount of additional sulfuric acid mist

due to addition of SCR was taken for the purposes of identifying a reasonable upper 

bound for a proposed limit. Emissions reported in the TRI are 35,553lb/yr or 2.79 x10-4

lb/MMBtu for the SJGS for 2009. Addition of the SCR is estimated by PNM to increase 

sulfuric acid emissions by about 182% over baseline levels.61 Using this 182% increase 

factor we estimate an upper range of sulfuric acid mist emissions of 7.87 x10-4lb/MMBtu

using PNM‘s TRI data. The 2009 TRI emission estimate is based on estimates of sulfuric 

acid manufactured in the boiler and subsequent removal by downstream equipment. The 

 

59

 TRI data is available at http://www.epa.gov/tri/tridata/current_data/index.html. 2009 data is considered 

preliminary.

60

 Hourly emissions calculated assuming that each unit is operating 85% of the year (7446 hr/yr)

61

 PNM previously estimated emissions of sulfuric acid for the baseline at 205.4 lb/hr and an additional 

373.99 lb/hr due to the SCR for all four units. Using this information, EPA has developed a ratio of the 

increase in sulfuric acid emissions over baseline levels of 182% increase (373.99/205.4 ≈1.82)
39

same removal factors will apply to any additional H2SO4 generated by the operation of 

SCR. 

While a direct comparison to other facilities is not possible due to differences in system 

design and operating conditions, such comparison can be informative and provide an 

expected range for emissions. Recent stack tests at the Navajo Generating Station 

showed an average emission rate of 9x10-5lb/MMBtu for H2SO4 across the three units.62 

This measured rate is lower than that estimated by the EPRI method of 2.71x10-4

lb/MMBtu.63 These units are larger (750 MW) than those at SJGS but have a similar 

design, with air preheater, wet scrubbers and hot side ESP (compared to baghouses at 

SJGS) currently installed. The smaller size of the units and the improved removal 

efficiency of the baghouses over the hotside ESP, result in a lower expected emission rate 

for the SJGS units. 

6.1.4 Background Ammonia Concentrations

Because very little monitored ammonia data is available, we used the IWAQM Phase 2

document which recommends a default ammonia background value of 1 part per billion 

(ppb) for arid regions.64 Alternative levels may be used if supported by data. B&V used 

lower background ammonia concentrations during the winter months based on 

concentrations used for the PSD ambient air quality impacts analysis for the Desert Rock 

Energy Center. EPA performed visibility modeling using both the B&V suggested 

background ammonia concentrations and the IWAQM default value. 

We note that there is some debate about what to use historically for background ammonia 

levels and concern with the sensitivity of CALPUFF modeling estimates to the 

background ammonia level. EPA and others have even collected ammonia data in both 

the close vicinity of the power plants (SJGS and Four Corners) and in other areas further 

from the SJGS and Four Corners power plants, but within the region impacted by these 

sources. The Desert Rock Energy Center used some of this data to argue for the use of 

lower ammonia levels in the winter time. EPA has further researched the ammonia data 

collected and determined that the monitoring data validates the use of a 1 ppb threshold 

for background in calculating delta deciviews at receptors in Class I areas for the SJGS 

impacts. The following discussion in this section discusses our basis for the use of 1 ppb 

as a reasonable background number for impacts of the SJGS units on surrounding Class I 

areas.

 

62

 Salt River Project Navajo Generating Station – Acid Mist Emissions Test Report by Catalyst Air 

Management, Inc. Report Number 264-001 (December 31, 2009).

63

 BART Analysis for the Navajo Generating Station Units 1 – 3, ENSR Corporation, November 2007, 

Document No.: 05830-012-300 (http://www.wrapair.org/forums/ssjf/documents/bart/2007-

11_SRP_Navajo_BART_Analysis_Report.pdf)

64

 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
40

Many analyses with CALPUFF have been conducted that highlight the sensitivity of 

CALPUFF visibility results to ammonia levels. The Colorado Department of Public 

Health and Environment (CDPHE) recently performed a sensitivity modeling analysis to 

explore the effect of the ammonia concentration input to CALPUFF on the predicted 

visibility impacts for a source with high NOx emissions relative to SO2 emissions 

(similar to the post-consent decree baseline SJGS units).65 The results of CPDHE‘s 

sensitivity modeling indicated that the largest sensitivity occurs for ammonia input values 

between 1 and 0.1 ppb. In that range, the difference in the peak visibility impacts 

predicted by CALPUFF is slightly more than a factor of 3 between ammonia 

concentration input values of 1 and 0.1 ppb. CPDHE‘s sensitivity analysis shows that the 

choice of background ammonia is important in terms of the magnitude of visibility 

impacts predicted by CALPUFF. As part of the supporting information for this action we 

also performed CALPUFF sensitivity modeling with the lower variable ammonia level in 

addition to our primary baseline with the constant 1 ppb level and confirmed some 

difference exists as well, but not necessarily as significant as in the CPDHE‘s situation.

We note that a recent report cited this CDPHE report and indicated lower ammonia levels 

should be considered for the Colorado Plateau.66 We have reviewed this material and 

consider it in making our proposal.

There are several factors to consider with selecting the appropriate ammonia background 

for estimating visibility impacts, including the length and temporal resolution of the 

ammonia data collected, if the ammonia data varies depending on location of collection 

in comparison to proximity of SJGS plumes, fluctuation of levels throughout the year, 

and importance of plume chemistry from the point of emissions that react with 

background ammonia to the downwind receptor.

The ammonia data was based on three week integrated passive ammonia samples that 

were taken at five sites in the Four Corners area from December, 2006 through 

December, 2007 (January, 2008 for two sites). The study included a variety of site types: 

a regional background site in the Four Corners area (Mesa Verde National Park); oil and 

gas development impacted sites in the Four Corners area (Navajo Lake and Southern Ute, 

the Southern Ute site was also impacted by mobile source emissions); a coal-fired power 

plant impacted site in the Four Corners area (Substation – near the Four Corners and 

SJGS power plants); and an urban site in the Four Corners area (Farmington Airport).67

Annual mean ammonia concentrations for all Four Corners area sites for the 2007 study 

ranged from 0.21 ppb to 1.5 ppb. With the Substation and Farmington airport sites 

 

65

 Supplemental BART Analysis: CALPUFF Protocol for Class I Federal Area Visibility Improvement 

Modeling Analysis (DRAFT), revised June 25, 2010, available at 

http://www.colorado.gov/airquality/documents/Draft‐ColoradoSupplementalBARTAnalysisCALPUF

FProtocol‐25June2010.pdf.

66

 ―Measurements of ambient background ammonia on the Colorado Plateai and visibility modeling 

implications‖; Dr. Ivar Tombach, and Robert Paine for the Salt River Project, September 2010.

67

 Journal article in Journal of Environmental Monitoring, ―Baseline ambient gaseous ammonia 

concentrations in the Four Corners area and eastern Oklahoma, USA‖, Sather, et. al.; September 25th

2008. (from this point forward this document is referred to as  ̳Sather 2008‘).
41

having annual mean ammonia concentrations of 1.13 ppb and 1.47 ppb respectively. This 

is substantially higher than the annual mean value of 0.21ppb at Mesa Verde, and the 

monitoring data suggests that the higher ammonia is due to the sources around 

Farmington and Substation monitors. The data at all the monitors including the more 

distant monitors is a 3 week integrated average and it is reasonable to say that the winds 

are only transporting the ammonia levels from around the SJGS and Farmington areas to 

the Mesa Verde monitor some of the time and during those periods we would expect the 

values to be much higher than the 3 week integrated value or the annual mean values. It 

is during these periods when the wind transports emissions from the SJGS and elevated 

ammonia levels to the Class I areas, such as Mesa Verde, that we are interested in for 

determining the days that are used in the 98th percentile visibility analysis of baseline 

levels. We also note that we are evaluating worst 24-hour impact periods, and not 3 week 

integrated average periods, so daily variation due to transport support a higher level than 

even the 3 week data set and certainly higher than the annual mean levels. 

We also note that while visibility is calculated at the Class I area by CALPUFF, Mesa 

Verde for example, the actual chemistry that impacts the generation of visibility 

impairment at the Class I area is actually more sensitive to the ammonia levels that 

interact with the plume when it is more highly concentrated close to the source than at the 

far downwind receptors at Class I areas. Therefore the actual ammonia concentrations at 

and around the SJGS units are much more representative of the ammonia levels that will 

impact the chemistry and generate visibility impairing molecules, such as ammonia 

nitrate and ammonia sulfate. The CALPUFF system calculates the sensitivity to the 

ammonia levels at the Class I area, but this is an artifact of the simplified chemistry 

approach utilized by CALPUFF. 

Further evaluation of the data that supported Sather 2008 indicates that the average at the 

five ammonia gathering sites (not including the Mesa Verde site) is 0.88 ppb on annual 

basis. The data also shows that the monthly maximums at the five sites ranged from 1.3 

ppb to 3.5 ppb with an annual average monthly maximum of 1.74 ppb. We also 

evaluated the average of each 3 week period data from the Substation and Farmington 

sites, which ranged from a low of 0.8 ppb to 1.75 ppb, with the average of the annual 

mean at these two sites being 1.3 ppb. This additional data highlights that annual average 

data underestimates potential levels of ammonia. It also highlights that when a subset of 

the ammonia data around the predominant amount of ammonia sources in the area of the 

emission source are evaluated that the average value monitored at the two sites did not 

drop below 0.8 ppb for any individual 3 week period that data was collected in 2007. 

From our review we conclude that the ammonia levels around the emission source are of 

greater concern for determining visibility impacts from the source due to the actual 

atmospheric chemistry that occurs than the ammonia levels at isolated downwind Class I 

areas. Since the source‘s emissions and surrounding background ammonia are 

transported together to a Class I area on a specific day, and the chemistry will be most 

reactive with the source‘s emissions near the point of emission, it seems appropriate to 

use a background level for ammonia that is representative of the area around the source. 

In this case the annual average values at the Substation and Farmington sites are above 
42

the 1 ppb levels that we have chosen to model and therefore we believe the level we 

modeled is very reasonable. 

We are proposing NOx reductions that would likely be met with the installation of SCR 

and would have associated ammonia slip (ammonia that is not fully reacted and is emitted 

to atmosphere). The ammonia slip limit may be higher than 1 ppb, but we don‘t think it 

would significantly impact visibility improvements due to the reductions in NOx and SO2

at the SJGS units. . 

6.1.5 EPA Modeling Scenarios

EPA remodeled the visibility impacts of SJGS using revised emission estimates as 

discussed above and meteorology results from the regulatory version of the CALMET 

model. Briefly, we applied the EPRI methodology to estimate the sulfuric acid released 

from combustion in the boiler for all scenarios and for operation of the SCR, assuming a 

0.5% SO2 to SO3 conversion efficiency of the SCR catalyst (compared to 1% assumed 

by B&V). EPA assumed that the SCR could achieve an emission rate of 0.05 lb 

NOx/MMBtu based on emission data from existing SCR retrofits (compared to 0.07 lb 

NOx /MMBtu assumed by B&V). EPA modeled a revised baseline, with SO2 emissions 

lowered to the BART presumptive limit 0.15 lb SO2/MMBtu that was assumed by the 

WRAP states for regional visibility modeling to achieve reasonable progress towards 

natural visibility conditions. Finally, modeling was performed utilizing both the default 

background ammonia concentration of 1ppb, as well as the monthly variable 

concentration proposed by B&V and both ―Method 6‖ and Method 8‖ to calculate 

visibility impairment from the modeled pollutant concentrations. 

EPA performed visibility modeling to evaluate the visibility benefit of additional NOx 

emission controls for each unit. The control scenarios modeled are outlined below and 

shown in Table 6-3. 

Control Scenarios:

1. Baseline – Emission rates are the same as the B&V post-consent decree 

emissions with the exception of sulfuric acid emissions. Sulfuric acid 

emissions were calculated for each unit using the EPRI method discussed 

above

2. EPA Revised Baseline or EPA Baseline – Emission rates are the same as 

B&V post-consent decree emissions with two exceptions: 1) Sulfuric acid 

emissions were calculated for each unit using the EPRI method discussed 

above; 2) SO2 emission rate of 0.15 lb/MMBtu was used rather than 0.18 

lb/MMBtu.

3. SCR – Emissions are same as EPA Baseline with the exception of NOx 

emissions. NOx emissions were lowered to 0.5 lb/MMBtu to reflect the 

control of NOx by SCR operation. 
43

Table 6-3. EPA Modeling Inputs (lb/hr)

Unit 1 Unit 2 Unit 3 Unit 4

EPA Baseline (post-consent decree controls)

SO2 667.26 663.84 1036.44 1016.82

SO4 0.17 0.17 0.27 0.26

NOx 1223.31 1217.04 1900.14 1864.17

SOA 10.1 10.1 15.7 15.4

PM fine 32 31.9 49.8 48.8

PM coarse 23.6 23.5 36.6 35.9

EC 1.0 1.0 1.6 1.6

EPA Adjusted Baseline

SO2 556.05 553.2 863.7 847.35

SO4 0.17 0.17 0.27 0.26

NOx 1223.31 1217.04 1900.14 1864.17

SOA 10.1 10.1 15.7 15.4

PM fine 32 31.9 49.8 48.8

PM coarse 23.6 23.5 36.6 35.9

EC 1.0 1.0 1.6 1.6

SO2 667.26 663.84 1036.44 1016.82

EPA SCR control scenario

SO2 556.05 553.2 863.7 847.35

SO4 0.39 0.39 0.61 0.60

NOx 185.35 184.4 287.9 282.45

SOA 10.1 10.1 15.7 15.4

PM fine 32 31.9 49.8 48.8

PM coarse 23.6 23.5 36.6 35.9

EC 1.0 1.0 1.6 1.6

All particulate modeling was performed using 1 gram per second nominal emission rates 

in CALPUFF for the specific size ranges presented in the NPS speciation spreadsheets 

(i.e., PM8.0, PM4.25, PM1.88, PM1.25, PM0.813, and PM0.625). These modeled species are

grouped in POSTUTIL as to represent the appropriate visibility pollutants (e.g., 

PMcourse = PM8.0 + PM4.25 and PMfine = PM1.88 + PM1.25 + PM0.813 + PM0.625) and are 

then scaled with the emission rates derived from the NPS spreadsheets. EC and SOA are

derived from the PM1.88 species and scaled with the emission rates derived from the NPS 

spreadsheets.

6.2 EPA VISIBILITY MODELING IMPACTS OF SJGS

We present the visibility improvement from the modeling scenarios in two ways: (1) 

deciview improvement at each Class I area, and (2) the sum of the improvements at all 

areas. Deciview improvement at each Class I area is the primary metric under the BART 

guidelines. 

The motivation for the second metric, which involves summing over Class I areas, is to 

provide a single number for comparing control scenarios to each other. There are 

multiple Class I areas, with different visibility impacts for each, but there is no 

established metric for expressing visibility impact considering all areas together in a 

single number. The overall impact can be assessed more or less intuitively, weighing the 
44

various area impacts and the number of affected Class I areas. Modeling results for each 

unit and the facility for all modeling scenarios are included in Attachment 3 to this 

document. 

6.2.1 Baseline to Revised (EPA) Baseline

EPA modeled a revised baseline scenario to incorporate the proposed lower SO2 emission 

rate of 0.15 lb/MMBtu rather than the 0.18 lb/MMBtu included in the original postconsent decree baseline modeled by NMED. The purpose of this was to separate any 

visibility benefit from lowering the SO2 emission rate from the benefit received from the 

operation of the SCR.

Table 6-4 shows the maximum of the 98th percentile of the daily maximum visibility 

impairment for the baseline scenario and the revised baseline for the 1 ppb background 

ammonia concentration modeled using ―Method 8‖ for visibility calculations. The results 

show minimal improvement in visibility due to the slightly lower SO2 emission rate. 

Table 6-5 summarizes the average and maximum results of visibility impairment at all 

Class I areas for all background ammonia and visibility calculation method combinations. 

Results of visibility modeling at each Class I area and for individual units are available in 

the attachment to this document.
45

Table 6-4. EPA Modeling Results – Impacts of SJGS on Visibility (maximum of 98th

Percentile of daily maximum dv of 2001, 2002, and 2003) at Sixteen Class I Areas (1ppb 

background ammonia concentration, Method 8)

Class I Area

Distance 

to SJGS 

(km)

Visibility Impact ( dv) 

after applying: Revised Baseline 

visibility 

improvement over 

baseline ( dv)

Baseline 

(postconsent 

decree)

Revised 

Baseline

Arches 222 3.55 3.50 0.05

Bandelier Wilderness 210 1.44 1.39 0.05

Black Canyon of the Gunnison Wilderness 203 1.44 1.41 0.03

Canyonlands 170 4.69 4.64 0.05

Capitol Reef 232 2.43 2.38 0.05

La Garita Wilderness 169 1.97 1.93 0.04

Grand Canyon 285 0.97 0.93 0.04

Great Sand Dunes National Monument 269 1.56 1.53 0.03

Mesa Verde 40 5.18 5.15 0.03

Pecos Wilderness 248 1.32 1.27 0.05

Petrified Forest 213 0.54 0.52 0.02

San Pedro Parks Wilderness 155 2.23 2.20 0.03

Maroon Bells Snowmass Wilderness 271 0.71 0.70 0.01

West Elk Wilderness 216 1.64 1.59 0.05

Weminuche Wilderness 98 2.94 2.92 0.02

Wheeler Peak Wilderness 258 1.16 1.12 0.04

Total Delta dv 33.76 33.18 0.59

Table 6-5. EPA Modeling Results -Summary of total visibility impairment at all 16 Class 

I sites.

Visibility Modeling Results Baseline Revised 

Baseline

Revised Baseline

improvement over 

baseline ( dv)

Variable Background Ammonia, Method 6, average 15.82 15.38 0.45

Variable Background Ammonia, Method 8, average 17.49 17.11 0.34

Variable Background Ammonia, Method 6, 

maximum 20.65 20.20 0.43

Variable Background Ammonia, Method 8, 

maximum 22.74 22.40 0.34

1 ppb Background Ammonia, Method 6, average 23.59 23.01 0.58

1 ppb Background Ammonia, Method 8, average 26.09 25.56 0.54

1 ppb Background Ammonia, Method 6, maximum 30.82 30.11 0.70

1 ppb Background Ammonia, Method 8, maximum 33.76 33.18 0.59
46

6.2.2 Visibility Improvement from Operation of SCR

Modeled impacts on the Class I areas of SJGS are shown in Table 6-6. The table shows 

the maximum of the 98th percentile daily delta deciview impacts from the three modeled 

years using the default background ammonia concentration of 1 ppb and Method 8 to 

calculate visibility. 

Impacts generally decline with distance from SJGS, as would be expected since the 

plume disperses as it travels, though conditions can be more or less favorable for 

transport to Class I areas in particular directions. Mesa Verde is the closest area and 

shows the highest impact, while Maroon Bells Snowmass and the Grand Canyon are the 

most distant and have low impacts. Visibility improvement due to installation of SCR is 

significant, including a 3.11 dv improvement at Canyonlands and 2.88 dv at Mesa Verde. 

Total deciview improvement at all Class I areas within 300km of the facility is 21.69 dv, 

a decrease in visibility impairment of 65% from the revised baseline. Improvements at 

individual Class I areas exceed 0.5 dv for all areas except Maroon Bells Snowmass and 

Petrified Forest. 

Table 6-7 summarizes the average and maximum results of EPA modeling of visibility 

impairment at all Class I areas for all background ammonia and visibility calculation 

method combinations. Impacts depend strongly on the background ammonia assumed, 

increasing as ammonia does. This effect is strongest in the baseline case due to the 

higher NOx emissions and the effect of available ammonia on the concentration of nitrate 

particulates. Results of visibility modeling at each Class I area and for individual units 

are available in the attachment to this document. 

Summarizing all of the EPA modeling results, the visibility improvement from applying a 

0.05 lb NOx/MMBtu (achievable with SCR or equivalent controls) is significant. The 

majority of 0.05 lb NOx/MMBtu emission limit benefits are approximately 0.5 dv or 

higher using the lower background ammonia values and ―Method 6‖. Visibility benefits

from 0.05 lb NOx/MMBtu emission limit are higher as background ammonia increases 

and/or if ―Method 8‖ is used. Despite uncertainty over background ammonia 

concentrations, several conclusions can be drawn. There would be a significant visibility 

improvement from applying SCR to SJGS. SCR improves visibility by a perceptible 

amount even for the lower ammonia scenario at many Class I areas, and by more 

noticeable amounts for the 1ppb background ammonia scenario. Large improvements in 

visibility are expected at individual Class I areas from the installation of SCR. 
47

Table 6-6. EPA Modeling Results – Impacts of SJGS on Visibility (maximum of 98th

Percentile of daily maximum dv of 2001, 2002, and 2003) at Sixteen Class I Areas (1ppb 

background ammonia concentration, Method 8)

Class I Area

Distance 

to SJGS 

(km)

Visibility Impact ( dv) 

after applying: SCR visibility 

improvement over 

revised baseline ( dv) Revised 

Baseline SCR

Arches 222 3.50 1.12 2.38

Bandelier Wilderness 210 1.39 0.48 0.91

Black Canyon of the 

Gunnison Wilderness 203 1.41 0.42 0.99

Canyonlands 170 4.64 1.53 3.11

Capitol Reef 232 2.38 0.82 1.56

La Garita Wilderness 169 1.93 0.57 1.36

Grand Canyon 285 0.93 0.33 0.60

Great Sand Dunes National 

Monument 269 1.53 0.49 1.04

Mesa Verde 40 5.15 2.27 2.88

Pecos Wilderness 248 1.27 0.47 0.80

Petrified Forest 213 0.52 0.21 0.31

San Pedro Parks Wilderness 155 2.20 0.74 1.46

Maroon Bells Snowmass 

Wilderness 271 0.70 0.28 0.42

West Elk Wilderness 216 1.59 0.45 1.14

Weminuche Wilderness 98 2.92 0.87 2.05

Wheeler Peak Wilderness 258 1.12 0.44 0.68

Total Delta dv 33.18 11.48 21.69

Table 6-7. EPA Modeling Results - Summary of total visibility impairment at all 16 

Class I sites.

Visibility Modeling Results Revised 

Baseline SCR

SCR improvement 

over revised baseline 

( dv)

Variable Background Ammonia, Method 6, average 15.38 8.02 7.35

Variable Background Ammonia, Method 8, average 17.11 8.18 8.97

Variable Background Ammonia, Method 6, maximum 20.20 9.90 10.33

Variable Background Ammonia, Method 8, maximum 22.40 10.07 12.34

1 ppb Background Ammonia, Method 6, average 23.01 8.86 14.14

1 ppb Background Ammonia, Method 8, average 25.56 9.17 16.38

1 ppb Background Ammonia, Method 6, maximum 30.11 11.05 19.06

1 ppb Background Ammonia, Method 8, maximum 33.18 11.48 21.69
48

We also evaluated the amount of improvement in the number of days that the SJGS units 

would either cause a visible impact (1 deciview or greater) and also the number of days 

they would significantly contribute to a visible impact (0.5 deciview or greater). As 

detailed in Table 6-8 below, EPA‘s proposed reductions would decrease the number of 

days that the SJGS units have a 1 deciview impact (or greater) by over 80%. EPA‘s 

proposed reductions would also decrease the number of days that the SJGS units have a 

0.5 deciview impact (or greater) by over 68%. We note that at 7 of the 16 parks within 

300 km, our proposed reductions would decrease the average number of days per year 

that the SJGS units cause a visibility impairment to zero days per year. 

Table 6-8. Average number of days per year SJGS visibility impacts exceed 1.0 and 0.5 

deciviews (1 ppb background ammonia and Method 8).

Class I Area

Distance 

to SJGS 

(km)

Average # of days/yr > 1.0 

dv

Average # of days/yr > 0.5

dv

Revised 

Baseline SCR Revised Baseline SCR

Arches 222 18 5 25 12

Bandelier Wilderness 210 12 1 33 6

Black Canyon of the 

Gunnison Wilderness 203 9 1 26 4

Canyonlands 170 28 8 42 22

Capitol Reef 232 8 2 13 5

Grand Canyon 285 3 0 6 2

Great Sand Dunes 

National Monument 269 11 1 38 3

La Garita Wilderness 169 19 0 53 6

Maroon Bells Snowmass 

Wilderness 271 2 0 9 0

Mesa Verde 40 115 43 175 105

Pecos Wilderness 248 9 0 30 4

Petrified Forest 213 1 0 6 1

San Pedro Parks 

Wilderness 155 33 4 65 17

Weminuche Wilderness 98 65 3 126 29

West Elk Wilderness 216 8 0 26 3

Wheeler Peak Wilderness 258 7 0 29 3

TOTAL Average # of 

days/yr 348 68 702 222
PNM San Juan Generating Station | BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Appendix E E-1

Appendix E. CALPUFF Modeling Speciation Information
Table 1

PC with FGD + Fabric Filter (Unit 1)

from AP-42 Table 1.1-6

(User inputs filterable emission rate in lb/hr)

Particle Cumulative Mass Fraction of PM10 Particle Emissions

Size < Stated Size < Stated Size Size Range by size

(um) FF (%) (um) (lb/hr)

10 92% 100% 10-6 9.1

6 77% 84% 6-2.5 14.5

2.5 53% 58% 2.5-1.25 13.3

1.25 31% 34% 1.25-1.0 3.6

1 25% 27% 1.0-625 6.6

0.625 14% 15% 0.625-0 8.5

CALPUFF Filterable Filterable

Particle Particle Size Fraction Emissions Extinction Emissions

Size (um) Range (um) (% of Total) (lb/hr) Coef. (g/sec)

8 10-6 16% 9.1 0.6 1.14 PMC Total

4.25 6-2.5 26% 14.5 0.6 1.83 42% Coarse >/= 2.5 micron 2.97

1.88 2.5-1.25 24% 13.3 1 1.68 58% Fine Soil </= 2.5 micron PMF Total

1.25 1.25-1 7% 3.6 1 0.46 3.85

0.813 1.6-25 12% 6.6 1 0.84

0.625 0.625-0 15% 8.5 1 0.88

1.51 10 0.19 3.7% of Fine is EC EC Total

Totals 100% 7.01 0.19

Heat Input (mmBtu/hr) Filterable PM (lb/hr)

3707 55.6

Filterable PM10 Condensible PM (lb/hr) Condesible Ratio (%) a lb/hr g/s

0.015 70.43 80 56.35 CPM IOR (SO4) 7.11

lb/mmbtu Total PM (lb/hr) 20 14.09 CPM OR (SOA) 1.78

Condensible PM 126.0

0.019

lb/mmbtu

Total PM Fine b Fine Fine EC

Fine EC % of 

Total PM Fine EC Fine EC

0.034 0.213 0.011 0.00041 1.2% 1.51 0.190

lb/mmbtu lb/ton lb/mmBtu lb/mmBtu lb/mmBtu lb/hr g/s

a Ap-42 Table 1.1-5

b

 Ap-42 Table 1.1-6
Table 2

PC with FGD + Fabric Filter (Unit 2)

from AP-42 Table 1.1-6

(User inputs filterable emission rate in lb/hr)

Particle Cumulative Mass Fraction of PM10 Particle Emissions

Size < Stated Size < Stated Size Size Range by size

(um) FF (%) (um) (lb/hr)

10 92% 100% 10-6 9.0

6 77% 84% 6-2.5 14.4

2.5 53% 58% 2.5-1.25 13.2

1.25 31% 34% 1.25-1.0 3.6

1 25% 27% 1.0-625 6.6

0.625 14% 15% 0.625-0 8.4

CALPUFF Filterable Filterable

Particle Particle Size Fraction Emissions Extinction Emissions

Size (um) Range (um) (% of Total) (lb/hr) Coef. (g/sec)

8 10-6 16% 9.0 0.6 1.14 PMC Total

4.25 6-2.5 26% 14.4 0.6 1.82 42% Coarse >/= 2.5 micron 2.96

1.88 2.5-1.25 24% 13.2 1 1.67 58% Fine Soil </= 2.5 micron PMF Total

1.25 1.25-1 7% 3.6 1 0.45 3.83

0.813 1.6-25 12% 6.6 1 0.83

0.625 0.625-0 15% 8.4 1 0.873

1.5 10 0.19 3.7% of Fine is EC EC Total

Totals 100% 6.98 0.19

Heat Input (mmBtu/hr) Filterable PM (lb/hr)

3688 55.3

Filterable PM10 Condensible PM (lb/hr) Condesible Ratio (%) a lb/hr g/s

0.015 70.07 80 56.06 CPM IOR (SO4) 7.07

lb/mmbtu Total PM (lb/hr) 20 14.01 CPM OR (SOA) 1.77

Condesible PM 125.4

0.019

lb/mmbtu

Total PM Fine b Fine Fine EC

Fine EC % of 

Total PM Fine EC Fine EC

0.034 0.213 0.011 0.00041 1.2% 1.50 0.189

lb/mmbtu lb/ton lb/mmBtu lb/mmBtu lb/mmBtu lb/hr g/s

a Ap-42 Table 1.1-5

b

 Ap-42 Table 1.1-6
Table 3

PC with FGD + Fabric Filter (Unit 3)

from AP-42 Table 1.1-6

(User inputs filterable emission rate in lb/hr)

Particle Cumulative Mass Fraction of PM10 Particle Emissions

Size < Stated Size < Stated Size Size Range by size

(um) FF (%) (um) (lb/hr)

10 92% 100% 10-6 14.1

6 77% 84% 6-2.5 22.5

2.5 53% 58% 2.5-1.25 20.7

1.25 31% 34% 1.25-1.0 5.6

1 25% 27% 1.0-625 10.3

0.625 14% 15% 0.625-0 13.1

CALPUFF Filterable Filterable

Particle Particle Size Fraction Emissions Extinction Emissions

Size (um) Range (um) (% of Total) (lb/hr) Coef. (g/sec)

8 10-6 16% 14.1 0.6 1.78 PMC Total

4.25 6-2.5 26% 22.5 0.6 2.84 42% Coarse >/= 2.5 micron 4.62

1.88 2.5-1.25 24% 20.7 1 2.60 58% Fine Soil </= 2.5 micron PMF Total

1.25 1.25-1 7% 5.6 1 0.71 5.98

0.813 1.6-25 12% 10.3 1 1.30

0.625 0.625-0 15% 13.1 1 1.36

2.34 10 0.30 3.7% of Fine is EC EC Total

Totals 100% 10.89 0.30

Heat Input (mmBtu/hr) Filterable PM (lb/hr)

5758 86.4

Filterable PM10 Condensible PM (lb/hr) Condesible Ratio (%) a lb/hr g/s

0.015 109.40 80 87.52 CPM IOR (SO4) 11.04

lb/mmbtu Total PM (lb/hr) 20 21.88 CPM OR (SOA) 2.76

Condesible PM 195.8

0.019

lb/mmbtu

Total PM Fine b Fine Fine EC

Fine EC % of 

Total PM Fine EC Fine EC

0.034 0.213 0.011 0.00041 1.2% 2.34 0.295

lb/ton lb/mmBtu lb/mmBtu lb/mmBtu lb/hr g/s

a Ap-42 Table 1.1-5

b

 Ap-42 Table 1.1-6
Table 4

PC with FGD + Fabric Filter (Unit 4)

from AP-42 Table 1.1-6

(User inputs filterable emission rate in lb/hr)

Particle Cumulative Mass Fraction of PM10 Particle Emissions

Size < Stated Size < Stated Size Size Range by size

(um) FF (%) (um) (lb/hr)

10 92% 100% 10-6 13.8

6 77% 84% 6-2.5 22.1

2.5 53% 58% 2.5-1.25 20.3

1.25 31% 34% 1.25-1.0 5.5

1 25% 27% 1.0-625 10.1

0.625 14% 15% 0.625-0 12.9

CALPUFF Filterable Filterable

Particle Particle Size Fraction Emissions Extinction Emissions

Size (um) Range (um) (% of Total) (lb/hr) Coef. (g/sec)

8 10-6 16% 13.8 0.6 1.74 PMC Total

4.25 6-2.5 26% 22.1 0.6 2.79 42% Coarse >/= 2.5 micron 4.53

1.88 2.5-1.25 24% 20.3 1 2.56 58% Fine Soil </= 2.5 micron PMF Total

1.25 1.25-1 7% 5.5 1 0.70 5.87

0.813 1.6-25 12% 10.1 1 1.28

0.625 0.625-0 15% 12.9 1 1.34

2.30 10 0.29 3.7% of Fine is EC EC Total

Totals 100% 10.69 0.29

Heat Input (mmBtu/hr) Filterable PM (lb/hr)

5649 84.7

Filterable PM10 Condensible PM (lb/hr) Condesible Ratio (%) a lb/hr g/s

0.015 107.33 80 85.86 CPM IOR (SO4) 10.83

lb/mmbtu Total PM (lb/hr) 20 21.47 CPM OR (SOA) 2.71

Condensible PM 192.1

0.019

lb/mmbtu

Total PM Fine b Fine Fine EC

Fine EC % of 

Total PM Fine EC Fine EC

0.034 0.213 0.011 0.00041 1.2% 2.30 0.290

lb/mmbtu lb/ton lb/mmBtu lb/mmBtu lb/mmBtu lb/hr g/s

a Ap-42 Table 1.1-5

b

 Ap-42 Table 1.1-6