# BEST AVAILABLE RETRO FIT 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 RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Table of Contents i 

# Table of Content s

**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 NO x Control Technologies

................................ ................................ ................................ ................. 3

- 1

3.1.1 Low NO x 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 NO x Star

................................ ................................ ................................ ................................ 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 NO
x Control Technology Alternatives

..................... 4

- 1

4.1.1 Natural Gas R eburn

................................ ................................ ................................ .......... 4

- 1

4.1.2 Mobotec ROFA and ROTAMIX

................................ ................................ ...................... 4

- 2

4.1.3 NO x Star

................................ ................................ ................................ ................................ .. 4

- 2

4.1.4 ECOTUBE

................................ ................................ ................................ .............................. 4

- 2

4.1.5 PowerSpan

................................ ................................ ................................ ........................... 4

- 3PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 Te**  **chnology**
**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 Perm**  **it**

**................................ ................................**  **...................... 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 RETRO FIT TECHNOLOG Y 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 NO
x Control Technology Alternatives

........................ 4

- 4

Table 5

- 1 NO x 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 NO
x Control Technologies

................................ ................................ ................................ ................................ .......... 6

- 6

Table 7

- 1 Class I Ar eas

................................ ................................ ................................ ................................ ........... 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 Vis ibility 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

- 11PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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

- 26PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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

CO 2 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

H 2 SO 4 Sulfuric Acid Mist
Hg Mercury

HHV Higher Heating Value
IWAQM Interagency Workgroup on Air Quality Modeling

LCC Lambert Conformal Conic

LNB Low NO x Burners

M MBtu Million British Thermal Unit

MWh Mega Watt Hour

HNO 3 Nitric Acid

NH 3 Ammonia

NH 4 Ammonium

NMED New Mexico Environment Department

NN Neural Network

NO 3 Nitrates

NO x Nitrogen Oxides

NPS National Park Service

NSPS New Source Performance StandardsPNM 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

SO 2 Sulfur Dioxide

SO 3 Sulfur Trioxide

SO 4 Sulfate

TAC Total Annualized Cost

TSD Technical Support Document

TSP Total Suspended Particulate

TCI Total Capital Investment

WRAP Western Regional Air PartnershipPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Introduction and Objectives 1

- 1 

# 1.0 Introduction and Objectives

The purpose of th is 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 (SO 2 ) 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 upda te focuses

on nitrogen oxide ( NO x ) pollutant emission contro ls only. Specifically, this analysis reviews and updates available NO
x 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 SO 2 and total particulate matter (TPM) emission rates of 0.15 lb/ MMBtu and 0.034 lb/ MMBtu , respectively, from the current NSR Permit 1

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

recommended best control alternative for NO
x 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 m odeling scenario

, including EPA’s Federal Implementation Plan ( FIP ) scenario representing four SCRs, and the NMED’s State Implementation Plan (SIP) scenario re pre senting four SNCRs . These modeling scenarios were updated to “adjust” these previously analyz ed and published scenarios for these new applicable

emission limitations.



## 1.1 P REVIOUS BART S UBMITTALS

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 impairm ent 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 informati on 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 . Addit ional information can be found on NMED website 2

 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.htmlPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 F inal Particulate Matter BART Analyses

 November 11, 2008

– Response to NMED Regarding H 2 SO 4 Emissions

 March 16, 2009

– Sulfate Removal Report

 October 27, 2009

– PNM Comments on the EPA Proposal Advanced Notice of Proposed Rulemaking 3

 February 11, 2011

– R evised SNCR and Rate Impact Analyses



## 1.2 SAN JUAN G ENERATING 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 vol atility 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 ar e 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 SO 2 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 state

of

- the

- art low NOx burners ( LNB ) with over fired air ( OFA ) ports on each b oiler to reduce NO
x 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 de

energized , but remain in place . T he 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

- 0598PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 wall

fired/B&W Opposed wall

fired/B&W

Steam Cycle Subcritical Subcritical Subcritical Subcritical

Draft of Boiler Forced Forced Forced Forced

Existing Emissions Controls

PM PJFF PJFF PJFF PJFF

SO 2 Wet FGD Wet FGD Wet FGD Wet FGD

NO x Low

- NO x burners

Over Fired Air Low

- NO x burners

Over Fired Air Low

- NO x burners

Over Fired Air Low

- NO x burners

Over Fired Air

Mercury Activated Carbon Injection Activated Carbon Injection Activated Carbon Injection Activated Carbon InjectionPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Basis of Analysis 2

- 1 

# 2.0 Basis of Analysis

2.1 D ESIGN B ASIS
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

de signs 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 des ign 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

- speci fic factors that had a significant effect on the SCR design basis and costs include the site congestion at SJGS, NO x 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 incl uded, because SJGS must meet a SAM limit of 2.6 x 10

- 4 lb/ MM Btu. Adding an SCR system will increase

SO 2 to SO 3 oxidation, resulting in increased sulfuric acid emissions, and based on vendor input, a sorbent injection system is required in order for SJGS t o 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 b oiler

- 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 NO
x reductions with SNCR , so the co st estimates assumed only a 25% NO
x reduction rate due to potentially high CO levels . The SNCR conceptual design and cost estimates were based on achieving a controlled NO
x emission limit of 0.23 lb/ MM Btu. For cost estimating purposes it was assumed tha t 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 RETRO FIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Basis of Analysis 2

- 2 

## 2.2 E CONOMIC D ATA

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 Technolo gy 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 NO
x 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 insta llation costs). 4

 Contracting Strategy . The capital cost for the plant modifications are ba sed on hiring an Engineer ing , Procure ment and Construct ion (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 instal led 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 c ontrol 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 s ite 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/B

02

- 001, 6 th Edition, January 2002, Section 1, Chapter 2, pg. 2

- 5.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 rea ctor 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 mat erials, 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

the n 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 SC R 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 RETRO FIT TECHNOLOGY ANALY SIS

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

 Owne rs 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

co st 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 star tup, 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 Indire ct 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 exp ense 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 equipmen t and tools.PNM San Juan Generating Station | BEST AVA ILABLE RETROFIT TECH NOLOGY 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 P erformance Tests
Performance test services are typica lly 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 D uring 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 constructio n 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 tha t 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 represent s a significant actual cost that PNM will incur with an SCR project s (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 pro jects 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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.

T he 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 facto rs 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/m 3

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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Basis of Analysis 2

- 7 

### 2.2.2.2 Electric Power Costs
Additional auxiliary power wi ll 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 g as pressure losses through the new equipment.



### 2.2.2.3 Makeup and Service Water Costs

S ervice 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 an y 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

mainten ance 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 S JGS. 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

- eligibl e coal plants for NO
x and SO 2 were outlined. The BART NO
x presumptive limits vary according to the type of coal burned and the boiler design. For all units at SJGS, the NO
x 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 th is 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 NO**  **X 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) NO x 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

- R 06

- OAR

2010

- 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 r etrofit

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 em issions reduction processes will be used as

reclamation material in the existing coal mine.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Basis of Analysis 2

- 9 

## 2.5 MODELING BASELINE CO NDITIONS
Emissions rates of pollutants are required as input data for visibility modeling. Stack outlet conditions for all the technically f easible 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.

 NO x emissions rate.

 SO 2 emissions rate.

 Filterable PM emissions rate.

 SO 3 emis sions rate.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identif ication 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, c ontrol technologies for only NO x 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 t he descriptions contained in Sections 3.1 through 3.2. In addition to adding NO x control technolog y 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

demoli shed ).



## 3.1 NO X 

## CONTROL TECHNOLOGIES
There are two appr oaches to achieving a reduction in NO
x emissions: combustion control and post

- combustion control. Combustion control methods seek to suppress NO
x formation during the combustion process by controlling the flame temperature and fuel/oxygen ratio. Combust ion
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 NO
x after its formation. The SNCR and SCR NO
x reduction technologies use either urea or ammonia as a reagent. SCR technology also uses multiple layers of reduction catalyst. Other NO
x reduction techniques were also identified, including emerging technologies.

NO x control technologies t hat 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.

 NO x Star.

 ECOTUBE.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 2  PowerSpan.

 Phenix Clean Combustion.

 e

- SCRUB.

 PerNOxide

.



### 3.1.1 Low NO x 

### Burners, Overfire Air with Neural Network

3.1.1.1 Low NO x 

### Burners

NO x , primarily in the form of NO and NO 2, is formed during combustion by two primary

mechanisms: thermal NO
x and fuel NO
x . Thermal NO
x results from the dissociation and oxidation of nitrogen in the combustion air. The rate and degree of thermal NO
x formation is dependent on oxygen availability during the combustion process and is exponentially dependent on combustion temperature. Fuel NO
x , on the other hand, results from the oxidation of nitrogen organically bound

in the fuel. This is the dominant NO
x producing mechanism in the combustion of pulverized coal, and typically accounts for 75 to 80 percent of total NO
x . All LNBs offered commercially for application to coal fired boilers control the formation and

emissions of NO
x through some form of staged combustion. The basic NO
x reduction prin ciples 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 mixi ng 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 NO
x . Any nitrogen escaping the in itial fuel

- rich region has a greater opportunity to be converted to NO
x 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 t he 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. NO
x 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 NO x control system rather than as individual burners.PNM San Juan Generating Station | BEST AVAIL ABLE RETROFIT TECHNO LOGY ANALYSIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 3 

### 3.1.1.2 Overfire Air System
OFA works by reducing the excess air i n the burner zone, thereby enhancing the combustion staging effect and further reducing NO
x 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 adde d. As with primary NO
x 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 rea ch 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 b urn. 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 hi gh 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 NO
x 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. Poo r 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 h ave 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 h eat 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 us e 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 als o supplement other NO
x 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 ret rofit or
other boiler enhancements, such as OFA addition.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 compon ents 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 NO
x 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 NO
x reductions. SNCR systems can use either ammonia or urea as the reagent. Ammonia or urea is injected into areas of the steam generator w here 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 Mult iple Injection LevelsP NM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 5 SNCR systems are capable of reducing NO
x emissions by as much as 50 to 60 percent in optimum conditions (adequate reaction time, temperature, and reagent/flue gas mixing; high

baseline NO
x conditions; multiple levels of injectors). Ammonia slip is the ammonia that does not

react with NO
x and instead “slips” past the boiler as ammonia. High levels of ammonia slip cause several negative operational impacts. First, ammonia will react with S O 3 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 achiev e 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, NO
x emissions reduction levels of 20 to 40 percent can be achieved. Potential performance is ver y 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 NO
x emissions using the same reduction mechanism as SCR systems.

Mos t 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

NO x emissions; at worst, the oxidation of ammonia can actually generate NO x . Accordingly, NO
x 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 lar ge 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 tempera ture and residence

time. To acc ommodate 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 availa ble. 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 NO
x reduction levels even under less than ideal mixing conditions. Co mputational 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

in jector lances. A re

- examination of the boiler steam piping would probably be required to achieve optimum performance.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 6 

### 3.1.3 Selective Catalytic Reduction
SCR systems are the most widely used post

- combustion NO
x control technology for achieving significant N O x emissions reduction. In SCR systems, vaporized ammonia (NH 3 ) injected into the flue gas stream acts as a reducing agent when passed over an appropriate amount of catalyst. The NO
x and ammonia reagent react to form nitrogen and water vapor. The reacti on mechanisms are very efficient, with a reagent stoichiometry of approximately 1.05 (on a NO
x 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. Ho wever, 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 s tartup.

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 lo w

- 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 de

energized hot

- side ESP sho uld 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 7 The SCR reactor is the housing for the catalyst. The reactor is basicall y 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 reacto r 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 NO
x reaction, the catalyst oxidizes a portion of the SO 2 in the flue gas to SO 3 . The oxidation of SO 2 to SO 3 could also require moderate air heater modifications, since the acid dew point temperature of the flue gas is directly related to SO 3
concentration. As the SO 3 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 ca n 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 int erfacing 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

syste m. 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 modi fication, 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 ar eas 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 potenti al concern for the air heater is the tendency for high SO 3 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 wi ll 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 SO 2 to SO 3 conversion rate. Ammonia slip must als o be minimized. Air heater basket modifications are often necessary to minimize these harmful effects.PNM San Juan Generating Station | BES T AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 8 

### 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 de scribed 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 amoun ts of reagent into the flue gas compared to conventional SNCR. This increased reagent flow has a two

- fold effect: NO
x reduction within the boiler is increased, while ammonia slip also increases. The ammonia that slips from the SNCR is

then used as the r eagent 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 NO
x reduction. As with in

- duct systems, the f lue gas velocity through the catalyst is an important factor in design. Operating in this mode allows maximum NO
x reduction within the boiler by the SNCR, while minimizing the catalyst volume requirement. While some NO
x reduction

is realized at the catal yst, the relatively small catalyst requirement of this design allows a true in

duct arrangement, with no significant ductwork changes, arrangement interference, or structural modifications. The second philosophy uses adequate catalyst volume to obtain sig nificant levels of

additional NO
x 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 t he quantity of ammonia slip, catalyst volume, and

distribution of ammonia to NO
x 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 par t of the SNCR. Therefore, even though the reaction at the catalyst requires 1 ppm of ammonia to remove 1 ppm of NO
x , 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 NO x 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 for mation 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

c oncentrations of SO 3 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 andPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technolog ies 3

- 9 lead to pluggage and corrosion. Several measures can b e 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 NO
x 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 al so 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 NO
x produced in the lower furnace to be

reduced to molecular nitro gen and oxygen. This happens because the oxygen stripped from the NO
x molecules is combined with the more active CO molecules to form CO 2 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 overal l excess air rate for the boiler of 15 to 20 percent. Reburn technology has demonstrated NO
x 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 N 2



### 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 AirPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 10 Sufficient residence time (adequat e 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 NO
x emissions from coal fired boilers by 30 to 45 percent. FLGR requires a lower natural gas input than in a

conventiona l 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 NO
x 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

- ba sed 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 NO
x removal efficiency than the basic gas rebu rn and FLGR systems. An amine

- enhanced system is capable of reducing NO
x emissions by 50 to 70 percent.



### 3.1.6 Mobotec ROFA and ROTAMIX
Mobotec provides a NO
x 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 u pper 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 C O and NO
x 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 NO
x 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 NO x 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. RO TAMIX installations have yielded up

to 60 percent NO x reduction in addition to the ROFA NO
x reduction.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Avail able 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 w ould 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.

Figu re 3

- 4 Mobotec ROFA and ROTAMIX Simplified Process Flow Diagram (Mobotec USA)



### 3.1.7 NO x 

### Star

NO x Star is the trademarked name for a NO
x 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 NO
x . The ammonia reduces NO
x through a n SNCR reaction, with the hydrocarbon minimizing the ammonia slip. This enables higher reagent injection rates for NO
x reductions than are achievable with a typical SNCR technology. The technology supplier states that the technology has the ability to ac hieve NO
x emissions of less than 0.20 lb/ MMBtu without the use of a catalyst and large SCR reactor. Although initially targeting high NO
x reductions, full

- scale demonstrations to date have been limited to nominally 50 percent NO
x reduction performance.



### 3.1.8 E COTUBE 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 airflo w and to increase the residence time for the air/fuel mixture. In principle, the OFA and SNCR processes are combined in this technology.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 12 ECOTUBE is capable of reducing NO
x , CO, and volatile organic compounds, while improving thermal efficiency, by opt imizing 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 fu el 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 exp erience 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 th e 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 NO
x , SO 2 , and Hg. This process results in the formation of nitric acid (HNO 3 )

, 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 collecti on 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 sulf ur

- 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECH NOLOGY ANALYSIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 13 The ECO system has been tested on a 1 to 2 MW s lipstream unit at FirstEnergy’s Burger
Plant and has achieved 82, 99, and 85 percent reduction for NO
x , SO 2 , 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 NO
x and

SO 2 emissions when burning coal. Th e 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 comb ustion 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 aggressiv ely commands oxygen to form CO from all sources, including such compounds as water. Nitrogen compounds that may form, such as NO
x , hydrogen cyanide, and ammonium (NH 4 ) , are forced to the molecular form (N 2 ) by the aggressive action of carbon for

oxygen. In the presence of calcium, the sulfur reacts to form calcium sulfide (CaS, a solid non

gaseous particle).PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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. T he hot flue gas, with high concentrations of CO

and H 2 and low concentrations of NO
x 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 CO 2 and H 2 to water. This prevents the formation of any new (thermal) NO
x 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 Figur e 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 fur nace 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 re powered boiler will show improved efficiency from more complete coal combustion (loss on ignition of < 1.0 percent), very low NO
x (< 0.15 lb/ MMBtu ), and control of SO 2 emissions (< 0.5 lb/ MMBtu ) with lower sulfur coals.PNM San Juan Gene rating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 t he 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 SO 2 to SO 3 and NO
x to a combination of N 2 , HNO 3 , and

NO 2 . 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

-- T he brine from a downstream wet ESP is fed into a spray dryer absorber, which forms a dry ammonium sulfate ((NH 4 ) 2 SO 4 )/ammonium nitrate (NH 4 NO 3 ) product that can be used as a fertilizer. The temperature of the flue gas is reduced in the spray dryer to an i deal 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)PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 16 According to pilot data, the vendor estimates that SO 2 and NO
x 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 comme rcialization 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 pero xide quickly evaporates in the duct and oxidizes NO to form

NO 2 , N 2 O 5 , HNO 2 , and HNO 3 . 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 concent rations 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 re sult 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 fugit ive 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Identification of All Available Retrofit Emissions Control Technologies 3

- 17 

### 3.2.1 Balanced Draft Conversion
Conversion to balanced draft operation w ould 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.

 Increas ed 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Technica l Feasibility of Additional Control Technology Alternatives 4

- 1 

# 4.0 Technical Feasibility of Additional Control Technol ogy 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 guid elines. 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 uni t. 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 age ncy. 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 INFEASIB LE ADDITIONAL NO X 

## CONTROL T ECHNOLOGY
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 o n 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 r eburn zone. However, this benefit to gas reburn would decrease the effectiveness of OFA by inhibiting the mixture of thePNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 temper ature 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 NO
x 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 NO
x limi ts.

The NO x reductions achieved at any of the SJGS units with gas reburn alone may not achieve the
presumptive NO x limits, but it could achieve enough NO
x 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 NO
x control technologies are not further evaluated, because the fact remains that natural gas reburn by

itself is not a feasib le technology at SJGS for meeting NO
x 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 be en 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 NO x 

### Star The major consideration for the NO
x Star technology is th at it currently has only one major installation in the United States and may require the installation of a single layer of in

- duct catalyst (NO
x Star Plus) to achieve the advertised levels of NO
x 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 app licable for retrofit at SJGS. In addition, the ECO system has not been pilot tested at a f acility burning a low sulfur (< 1.5 percent) subbituminous coal or in a large, commercial

- scale system. Therefore, it is considered not technically feasible for retr ofit 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 re trofit 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

- s cale installation. Therefore, t he 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 FEASIBILIT Y SUMMARY
After the completion of the screening process (S tep 2 of the BART determination), the following technologies were identified as feasible upgrades at SJGS for NO
x 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 p re vious 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 ta bles are the reasons for technical infeasibility of the eliminated control technologies.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Technical Feasibility of Additional Control Technology Alternatives 4

- 4 Table 4

- 1 Technically Feasible Additional NO
x Control Technology Alternatives

**CONTROL TECHNOLOGY TECHN**  **ICALLY**
**FEASIBLE AND**
**APPLICABLE? REASONS FOR TECHNICA**  **L 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 Gener ating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 NO
x 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 retir ement and reflect the FIP, SIP, and State

Alternative BART control scenarios

.



## 5.1 CONTROL EFFECTIVENES S

Step 3 of a BART analysis determines the control effectiveness of the additional NO
x 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

in put data for each SJGS unit.

Table 5

- 1 indicates the control effectiveness of each additional NO
x 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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

- 2 Table 5

- 1 NO x Control Effectiveness for Additional Control Technology Alternatives (Annual Average Emissions Rates)

**NO X**  **CONTROL EFFECTIVENES S** 

Unit SJGS 1 SJGS 2 SJGS 3 SJGS 4 Plant Total NO x Emissions Design Basis Heat Input Data,
MMBtu /h 3,707 3,688 5,758 5,649

NO x 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 an nual unit capacity of 8 5 percent.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 f inal evaluations also take into consideration the entire station’s controls.



## 6.1 TYPES OF IMPACT ANAL YSES

For all the additional NO
x 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 cost

effectiveness of each technology could be made. In summary, the four types of impact analyses performed consisted of the follo wing:

 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 NO
x 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 si te are summarized in Appendix C along with

i ndividual cost estimates for the technology options.



### 6.1.1 Cost of Compliance

Sar g ent & 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 in

house engineering estimates. No costs are assumed for retiring a unit.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNO LOGY ANALYSIS

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 consump tion 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 ba sis 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 NO x emissions, but t he S tate A lternative has significant environmentally beneficial impacts as compared to the F IP and the S IP scenario s , 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 CO 2 , and hazardous air pollutants (HAPs)

emissions reductions for the S tate A lternative as compared to the SIP and the FIP scenario s

. A s can be seen from the table, the State Alternative reduces the emissions of NO x 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 NO
x 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Impact Analysis and Cost

- Effectiveness of Additional Control Technology Alternativ es 6

- 3 Table 6

- 1 SJGS Pollutant Emissions, Facility Wide

**SCENARIO POLLUTANTS (TPY)** 

**NO X**  **SO 2**  **PM CO**  **CO 2**  **1 VOC**  **HG 2**  **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. CO 2 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 c ost analysis, a 30

- year service life was assumed.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Impact Analysis and Cost

- Effectiveness of Additional Control Technology Alternatives 6

- 4 In addition to the decrease in overall pollutant emissions, the S tate A lternative will significantly reduce fugitive total suspended particulate (TSP) emissions by approximately 50% from 407 tpy (2011 TRI) to 204 tpy. The se reductions result from:

 Decrease in coal ha ndling

,  F ewer TSP emissions from the pulverizer

,  R eduction in TSP from duct leaks

,  L ower emissions from the handling of CCRs (i.e., fly ash and bottom ash, spent activated carbon and scrubber gypsum), and

 D ecreased emissions from both paved and unpaved ro ads 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 S tate A lternative also ha s the

residual benefi ts 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 S tate A lternative as compared to the F IP and S IP scenarios , and the current operations (Baseline)

. In general , the S tate A lternative raw material u sage rate is estimated to be 50 percent less than current conditions or those expected under the other scenario s

.

Table 6

- 2 Raw Material Usage, Facility Wide

**RAW MATERIAL STATE ALTERNATIVE**  **(TPY) BASELINE** 
**, FIP**  **, AND**
**SI P**  **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 S tate A lternative, water usage is estimated to drop by approximately 53% to 10,161 acre

- feet/year. Concentrated

w astewater

, which includes total and suspended solids from the wastewater management process, periodic boiler cleaning wastes and other pro cess wastes

, are discharged to on

- site evaporationPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Impact Analysis and Cost

- Effectiveness of Additional Control Technology Alternatives 6

- 5 ponds under a zero discharge NPDES permit 6



### Solid Waste Disposal Benefits and a state regulated discharge permit. Under th is

scenario , the generation of wastewater will be decreased by a pproximately 50 percent from

41 million gallons/y ear (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 fl y 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 . H owever, the S tate A lternative 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 S tate A lternative

, will not require the use of a catalyst for NO
x reduction

, which would periodically result in the replacement of spent catalyst due to catalyst poisoning by a number of alkali metals and trace elements. T hese 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 remaini ng useful life of the control technology on its cost

effectiveness was considered. For this BART analysis, the remaining useful life of the controls was

defined as 3 0 years. Therefore, there was no additional life impact cost for the additional control

t echnologies.



## 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

techno logies’ 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 cos t

- effectiveness values were based

on 2013 dollars.

6 NPDES Permit N. NM0028606, issued February 2011.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 NO
x Control Technologies

**IMPACT ANALYSIS AND COST EFFECTIVENESS R**  **ESULTS OF NO X**  **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 5,5 87 51

--

Total 2,152 8,011 12,989 34,556 13, 624 1,0 49 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 Ap plication Document).

4. Cost

- effectiveness ($/ton) is defined as ratio of TAC over Expected Emission Reduction ( tpy ).

5. Expected emissio n 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 RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Impact Analysis and Cost

- Effectiveness of Add itional Control Technology Alternatives 6

- 7 

### 6.2.1 Cost

- Effectiveness Comparison

For all the additional NO
x 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 inclu ded in the

table. Cost

- Effectiveness Comparison Table 6

- 3 clearly shows that on a facility wide basis the S tate

A lternative 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 a cross 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, a ccessibility 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 RETRO FIT TECHNOLOGY ANALY SIS

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 c onducted 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 maximu m 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 compare s resulting visibility from various control technology options to th e baseline conditions. The baseline conditions and resulting visibility are i ncluded 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 CAL PUFF 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 t he EPA CALPUFF modeling information provided as part of a Freedom of Information Act (FOIA) request and described in a technical support document 8 (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 wa s 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.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 basel ine 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 th at 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 CLAS S I A REAS
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 W ILDERNESS AREAS WITH**  **IN 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 CanyonPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 distanc es, 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 2010 9 ) and the Interagency Workgroup
on Air Qualit y 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 0YLCC(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 SJGSPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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. I t 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 locat ions. 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 wit h 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 scen ario. Additionally, the BART modeling incorporated the SJGS’s new SO 2 and total particulate matter (TPM) emission rates of 0.15 lb/ MMBtu and 0.034 lb/ MMBtu , respectively, in the current NSR

Permit 10

 **Scenario 1: Baseline.** Units 1

- 4 operating only with existing air pollution control technology and new permitted SO 2 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 under stood 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 we ll as the three BART technology scenarios. Additionally, BART modeling for the State Alternative includes the TPM emission rates as discussed above and a

reduced SO 2 emission rate of 0.10 lb/MMBtu as agreed upon in the Term Sheet between EPA, NMED

and PN M . 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; NO X at

0.05 lb/ MMBtu and new permitted SO 2 and TPM emission rates of 0.15 lb/ MMBtu and 0.034 lb/ MMBtu , res pectively.

10 NSR Permit No. 0063

- M8.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impac ts 7

- 5  **Scenario 3: New Mexico Environmental Department (NMED) State Implementation Plan (SIP).**  Uni **t** s 1

- 4 operating with existing air po llution control technology and with new SNCR installation; NO X at 0.23 lb/ MMBtu and new permitted SO 2 and TPM emis sion 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; NO X at 0.23 lb/ MMBtu , new permitted TPM emission rate 0.034 lb/ MMBtu , and a reduced

SO 2 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 repor t

, three different emissions

control str ategies, and technologies beyond the baseline, have been evaluated for SJ G S. The baseline

emissions for PM , NO X , SO 2 , and sulfur acid mist ( H 2 SO 4 ) 11

As described in the June 2007 BART application, the H 2 SO 4 (or SO 4 ) were based on emissions limits from the
SJGS Air Permit. The baseline and BART control scenarios stack param eters are presented i n
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 co ntrol 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 profiles 13

For this analysis, speciation of particulate matter generally followed the same procedures/method ologies 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 (rathe r 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 speciat ion 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 der ive 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

par ticulate matter to be further broken down into various size categories, with each category impacting light extinction to varying degrees

- known as speciation.

11 H 2 SO 4 emission limit contained within the SJGS air permit is applicable to SCR technology installation.

12 SO 4 emission data was conservatively assumed to equal SO 3 . 13 http://www2.nature.nps.gov/air/permits/ect/index.cfmPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 6 As with prior modeling analyses, condensab le 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, howeve r, neither this analysis nor the EPA’s analysis assumed the remaining 80 percent of the condensable particulate matter (i.e., inorganic matter) was SO 4 (or SO 3 ) as the NPS speciation profile would suggest in lieu of having any other SO 4 emissions data. Ra ther, 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 SO 4 rate for the SCR scena rio 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 NO**  **X EMISSION** 

**RATE (LB/HR)**  **SO 2**  **EMISSION**

**RATE (LB/HR)**  **EC (LB/HR)**  **FINE PM (LB/HR)**  **COURSE**
**PM (LB/HR)**  **H 2**  **SO 4**  **(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 21.47PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 NO**  **X EMISSION** 

**RATE (LB/HR)**  **SO 2**  **EMISSION**

**RATE (LB/HR)**  **EC (LB/HR)**  **FINE PM (LB/HR)**  **COURSE**
**PM (LB/HR)**  **H 2**  **SO 4**  **(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 21.47PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNO LOGY 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 NO**  **X EMISSION** 

**RATE (LB/HR)**  **SO 2**  **EMISSION**

**RATE (LB/HR)**  **EC (LB/HR)**  **FINE PM (LB/HR)**  **COURSE**
**PM (LB/HR)**  **H 2**  **SO 4**  **(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 21.47PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 NO**  **X 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 21.47PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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

extinction 14

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 wi th the revised IMPROVE equation (“Method 8”) . The revised IMPROVE equation is used to convert measured or modeled
concentrations into extinction for each pollutant c hemical 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 betwe en 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 98 th percentile, 8 th 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 an d effects

of various controls. The 98 th 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/NRR

2010/232. National Park Service, Denve r, Colorado (http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf)PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 11 

## 7.8 MODELING R ESULTS

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 1.12PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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

technol ogy 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 0.45PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 1 3 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 0.86PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 0.40PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 15 

## 7.9 S UMMARY
During the telephone conference call s 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 w ere discussed and confirmed

. Based on the approved approach

, visibil ity modeling was conducted for the four BART scenarios.

T he 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

1 6 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, respect ively . The visibility results for the Baseline Scenario have been included for informational purposes as new SO 2 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 resul ts 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 visibility 16

As previously noted, the projected visibility impacts f or 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 d v threshold. These summary tables also illustrate th e 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
imp rovement 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 curve s

. 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 RETRO FIT TECHNOLO GY ANALYSIS

BLACK & VEATCH | Visibility Impacts 7

- 16 Table 7

- 14 Maximum Delta Dec i view 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

- 0.41PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 17 Table 7

- 15 Delta Dec i view 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 0.05PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 AlternativePNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 20 Figure 7

- 3 Average Days Compared To 0.5 d v 17

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 AlternativePNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 2 1 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 RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 22 Figure 7

- 4 Maximum Days Compared To 0.5 dv 18

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 AlternativePNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 DeciviewsPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 24 Figure 7

- 5 Average Days Compared To 1.0 d v 19

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 AlternativePNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 25 Table 7

- 19 Maximum Days Compared To 1.0 d v

**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 RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 2 6 Figure 7

- 6 Maximum Days Compared To 1.0 d v 20

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 AlternativePNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Visibility Impacts 7

- 27 

## 7.10 VISIBILITY COST EFFE CTIVENESS
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 technol ogy 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 vis ibility 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 i s 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 CO ST**  **(TAC) ($1,000) SCENARIO MAXIMUM** 
**DECIVIEW CHANGE (DV)**  **MAXIMUM**
**IMPROVEMENT**

**($ 1,000**  **/DV)**

Baseline to FIP 10 8, 820 3.09 35, 217

, 000

Baseline to SIP 2 7,248 0.95 28,682,000

Baseline to State Alternative 13, 6 24 2. 67 5, 103

, 000PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 technol ogies 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 NO
x emission rate of 0.23 lb/MMBtu 21

The recommended BART control scenario was based on an evaluation of the most cost

effective technology. This ev aluation was performed as detailed in Sections 3.0 through 6.0 of this

report. and a lower SO 2 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 SN C R optimization testing on both

units to determine if a NO
x 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 poll ution control equipment established to reduce other criteria pollutant emissions. Units 2 and 3 will be retired in

place 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 perf ormance, SO 3 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 curv e 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 th e regulatory approval and implementation project.

21 Emission rate is based on a 30

- day rolling average basis.PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 **•** NM E D 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 NO x 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 RETRO FIT TECHNOLOGY ANALY SIS

BLACK & VEATCH | Appendix A A

- 1 

# Appendix A. Term SheetPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 C ompliance 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 I ntroduction

................................ ................................ ................................ ............... 36
B101 Legal

................................ ................................ ................................ ......................... 36
B102 Authority

................................ ................................ ................................ ................... 37
B103 Annual Fee

................................ ................................ ................................ ................ 37
B104 Appeal Procedures

................................ ................................ ................................ .... 38 B105 Submi ttal 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 P ART 

### 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 permi t

. Introduction

A101

A. The term of this permit is permanent u nless 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 deli vered 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 Fede ral 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 autho rity

- 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 Mexi co 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 SI P 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. Pre

construction emission limits shall remain in effect until the n ew 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 H 2 SO 4 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 f rom 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

, 42 0 .0 Volatile Organic Compounds (VOC) 248 .0

Sulfur Dioxide (SO 2 

### ) 12,352 .0 Total Suspended Particulates (TSP) Total 3381 .0 Particulate Matter less than 10 microns (PM 10 

### ) Filterable 1

, 550 .0 Particulate Matter less than 2.5 microns (PM 2.5 

### ) Total 28 36 .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 ( H 2 

### SO 4 

### ) ( 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 Opera ting 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 P ermits

– P revention of S ignificant
D eterioration 

### (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 C F R 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, D istrict 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 list s 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) Justific ation 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 th e operation of the facility as described in this permit.



### C. A pplicable 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) SO 2 

### 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 SO 2 

### 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 SO 2 

### Control Efficiency Limit

E302 20.2.32.110.C NMAC NOx Emission Limit

E301, E302, E303, E304 20.2.31.109.C NMAC SO 2 

### Emission Limits (Plant

- Wide)

E301, E302, E303, E304 NSR No. 63

- M6 Emission Limits for NOx, SO 2 

### , 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, SO 2 

### , PM

- 10, TSP, CO, or VOC

E301, E302, E303, E304 PNM self imposed SO 2 

### Emission Limits

E301, E302, E303, E304 FIP (Scenario A) NOx, Ammonia, H 2 

### SO 4 

### and HAP Limits

E301, E302, E303, E304 SIP (Scenario B) NOx and Ammonia Limits

D. Unit s 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 10 3

. F identifies whether the boiler un it 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 identi fied as exempt act ivities 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 L ist

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
SO 2 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
SO 2 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
SO 2 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
SO 2 Scrubber
Scenario A: SCR Scenario B : SNCR

S508/E501 Unit 1 Duct
Leaks -- -- -- -- -- G ood 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 3 5,000 gpm

S518/E518 Unit 1 Fly Ash Silo

Vent W.W. Sly Oct 2008 JM3586 NA 29 1 846 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 pulverize r (Unit E20 1) 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 p er 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 pe r year).”
4 The Btu/hr value listed in Table 1 04 Includes a 6% safety factor added to nominal rated capacity of the boilers existing at the time of permit issuance.



### A105

A. Table 10 4 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 an d 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
E30 1
E30 2
E30 3
E30 4 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

E30 1
E30 2 E30 3
E30 4 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

E30 1
E30 2
E30 3
E30 4 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

E30 1
E30 3 E30 4 NOx 0.70 lb/MMBtu 3

- Hour Average, Rolled Hourly 40 CFR 60.44(a)(3) CEMS

E30 2 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 average 5

30

- boiler operating day rolling average 1 0 30 day rolling average 1 0 0063

- M4
FIP & 0063

- M 8 CEMS & Process
Records

E301
E302
E303
E304 Opacity 8 20% 6

- Minute Average 40 CFR 60.42(a)(2) ; for E302

- NSR 63M4 and Consent Decree COMS

E30 1
E30 2 E30 3
E30 4 TSP 4

(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

E30 1
E30 2
E30 3
E30 4 TSP 4

(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

E30 1 E30 2
E30 3
E30 4 PM 4,7

(Filterable) 0.015 lb/MMBtu Per Compliance Method 0063

- M4 and Consent
Decree Quarterly Testing

E301
E303
E304 PM 4

(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 PM 4

(Filterable) 0.05 lb/MMBtu Per Compliance Method 20.2.14.201.A NMAC Quarterly Testing

E302 PM 4

(Filterable) 0.05 lb/MMBtu Per Compliance Method 20.2.14.202.A NMAC Quarterly Testing

E30 1
E30 2
E30 3
E30 4 PM

- 10 4

(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

E30 1 E30 2
E30 3
E30 4 PM

- 10 4

(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

- 2.5 4

(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

- 2.5 4

(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

- 2.5 4

( Total ) 0.0 34 lb/MMBtu Per Compliance Method NSR No. 63

- M 7 Annual Testing

E30 1
E30 2
E30 3
E30 4 PM

- 2.5 4

( 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

- M 7 Annual Testing

E30 1
E30 2
E30 3 E30 4 PM

- 2.5 4

( 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

- M 7 Annual Testing

E30 1
E30 3
E30 4 PM

- 2 4

(Filterable) 0.02 lb/MMBtu Per Compliance Method 20.2.14.201.B NMAC Note 2

E30 2 PM

- 2 4

(Filterable) 0.04 lb/MMBtu Per Compliance Method 20.2.14.202.B NMAC Note 2

E30 1
E30 2
E30 3
E30 4 SO 2 90% removal Annual Average 0063

- M4 CEMS

E30 1
E30 2 E30 3
E30 4 SO 2 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
E30 1
E30 2
E30 3
E30 4 SO 2 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

E30 1
E30 2 E30 3
E30 4 SO 2 0.15 lb/MMBtu 9 30

- Day Average, Rolled Daily PNM self imposed limit, NSR 63M6R2 and FIP CEMS & Process
Records

E30 1
E30 3
E30 4 SO 2 1.2 lb/MMBtu 3

- Hour Average, Rolled Hourly 40 CFR 60.43(a)(2) CEMS

E30 1
E30 3
E30 4 SO 2 1.2 lb/MMBtu 3

- Hour Average, Rolled Hourly 20.2.31.109.B NMAC CEMS

E30 2 SO 2 Minimum 72% Control 30

- Day Average, Rolled Daily 20.2.31.110.A NMAC CEMS

E30 1
E30 2
E30 3
E30 4 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

E30 1
E30 2 E30 3
E30 4 H 2 SO 4 0.00026 lb/mmBtu hourly basis FIP

- 40 C.F.R. § 52.1628 Annual
Method 8A

E30 1
E30 2
E30 3
E30 4 Ammonia Slip 2 ppm design basis FIP

- 40 C.F.R. §
52.1628 SCR design

E30 1
E30 2 E30 3
E30 4 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 NO 2 2 PNM shall show compliance with either the PM or PM 2 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, NO
x 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 am bient indoor temperature measured at the time fuel is first fed to the boiler.
6 The seven (7) day average emission rate of SO 2 at San Juan Units E301, E302, E303, and E304 shall not exceed
0.250 lb

- SO 2 /MMBtu for each unit, calculated as a block average as measured by SO 2 CEMS located downstream of the scrubber outlet and any scrubber by

- pass return. For purposes of calculating the block average, SO 2 emissions for the first three (3) hours of a cold startup after coal is fed to the boiler shall be capped

a t 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 0.01 5 lb

PM/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 co nditions 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 a tmosphere, 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 qualit y, 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 SO 2 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 SO 2 , except for data obtained during emergency conditions. Hourly emission rates will only be determined based on valid SO 2 CEMs data for any hour where fuel is combusted in the unit. No missing hour substitute data will be used in de termining compliance with the proposed 0.15 lb/MMBtu heat input 30

- day rolling average SO 2 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 SO 2 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
SO 2 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 SO 2 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 SO 2 emissions becomes effective on September 20, 2016 if SCR is installed.
1 0 Per FIP at 40CFR52.1628 d(2), The NOx limit for each unit in the plant, expressed as nitrogen dioxide (NO 2 ), 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. Eac h 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 sha ll 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 rollin g 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 t he 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
Met hod

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
Met hod

SO 2 13,000 lb/hr 3

- Hour Average, Rolled Hourly 20.2.31.109.C NMAC CEMS

SO 2 0.55 lb/MMBtu 30

- Day Average, Rolled Daily 20.2.31.109.C NMAC CEMS & Process
Records

SO 2 0.46 lb/MMBtu Annual Average NSR No. 63

- M2 CEMS & Process Records

1 Nitrogen dioxide emissions include all oxides of nitrogen expressed as NO 2



### 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 SO 2 

### 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 e nds not later September 20, 2016.



### D. Table 106. D list s 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
E41 0 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 ar e 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 NO x emission limits shall be determined on a unit

- specific basis using data fr om NO x 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 SO 2 

### emission limits shall be determined on a unit

- specific basis using data from SO 2 

### 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 all ow 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 e missions.

(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 m ercury removal rate and procedure, then this permit will be re

opened 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 Permi t 0063M7 will be used for fees until all units under NSR 0063M8 have been modified and new pollution controls are operational.

Table 10 6

. J : Emissions (tons per year) total for annual fees use

Unit 1 

### NOx 2 

### CO 3 

### VOC 4 

### SO 2 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 1 

### NOx 2 

### CO 3 

### VOC 4 

### SO 2 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
45 5
45 5
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 SO 2 limits by scaling up 0.15 lb/MMBtu SO 2 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

- h r 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 expe cted 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 monit oring 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 Fac ility : 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 perm it 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 Im plementation 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 req uire 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 b oth 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 ammon ia 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 limit s 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 t he 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 Departme nt determine d 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 th e SIP

. As of July 6, 2012, EPA has not approved the SIP. NMED establishes the deadline d ate 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 p ollution 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 O IL AND 

### G AS 

### I NDUSTRY



### Oil and Gas Industry

– not required

A300 C ONSTRUCTION 

### I NDUSTRY



### Construction Industry

- not required

A400 P OWER 

### G ENERATION 

### I NDUSTRY



### This section has common equipment related to most Electric Service Operations (SIC

4911). 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 obtainin g 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 SO 2 

### continuous emissions monitoring systems (NOx and SO 2 

### CEMS) and for continuous opacity monit oring 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 SO 2 

### 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 CO 2 

### emissions. Recordkeeping: The permittee shall comply with the applicabl e 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. M ercury CEMS Requirement: The permittee shall install, maintain, and operate mercury CEMS in accordance with the manufacture r ’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, t he permittee shall keep records of the mercury CEMS outputs, calculations, and any CEMS maintenance activity necessary to show

accurate a nd 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 SO 2 

### , NOx, and the exhaust flow rate from each unit in full compliance with the requirements of 40 CFR Pa rts 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 opaci ty and the emissions of SO 2 

### , 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 minimizi ng 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 baghouse s assoc iated 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 excursi on 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 b aghouse 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 SO 2 

### , 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 CF R 64.7(d) for corrective actions. Each unit has CEMS for
SO 2 

### and NOx which are required under acid rain regulations and, therefore, exempt SO 2 

### 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) I n 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 appro priateness 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 s hall 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

assu rance 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 us ed 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. Monitori ng 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 Specificatio n 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

Recordkeepi ng: 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 Acti ons and Excursions

Indicator Trigger Point 1



### 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 modifica tion procedures of 20.2.70.404.B NMAC to change the CAM Plan.



### C. D uct L eak M anagement P rogram 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 min imizing 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 Expans ion 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 i dentified 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 requ irement 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 moni toring 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 inspe ctions, 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 O xidation ( LSFO ) Scrubber Operations Requirement: The boilers (E 301, 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 SO 2 

### emission limits and the SO 2 

### 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 othe rwise 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 ke eping 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. Reporti ng: 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 req uest 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 ave rage 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 kee p 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 maintain ed. 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 COM s 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, Subp art D, PNM shall install, calibrate, maintain, and operate COMs on Unit E302 per the procedures specified in 40 CFR 60 Subpart D. The COM s 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 lo cation. 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 COM s 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, Subp arts 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 SO 2 

### continuous emissions monitoring (CEMS). Monitoring: SO 2 

### continuous emissions monitorin g (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 T est 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, PM 10 

### , PM 2.5 

### , 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, PM 10 

### , and
PM 2.5 

### 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 th is 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, PM 10 

### , PM 2.5 

### ) 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 PM 10 and PM 2.5 standards

. 3 PM 10 and PM 2.5 particulate emissions include condensable particulate matter.

4 PNM shall conduct compliance testing to determine the condensable portion of actual PM 10 and PM 2.5 emissions using EPA Method 20 2 , annually . PNM will also conduct a Method 5i test at approxim ately the same time it
conducts each Method 20 2 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 maxi mum 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 oper ation. The wash sequence will automatically switch from cell to cell. (2) During plant outages, manual cleaning to remove st ubborn 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 9 6 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 pr epared 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 te sting 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, n o 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 re sults 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 t o demonstrate compliance with the emission limits identified in Table 106.A

, t he 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 Met hod 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 a t 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 co mpliance 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 accor dance 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 perf ormed. Reporting: I n accordance with Section B110 of this permit, the permittee shall report semi

annually 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 t he 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: I n 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 s hall 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 operati ng 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 exce ed 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 n o less than once each calendar quarter. Recordkeeping: In accordance with Section B109, n o 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 in dividual 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 3 5,000 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 emission s 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 PM 10 

### E702, E703, E704, E706, and
E707 Unit shall be watered as necessary to minimize emissions of TSP and PM 10



### B. Facility

- Wide Raw Material Limits Requirement: T he calendar year material processing limits in Table 406.B were calculate d 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 , t he 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 permitte e 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 annual

to

- date records of the quantities of coal, diesel fuel, and limes tone 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 min imize 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 per mit 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: Allo wable 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 o f 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 manu facturer’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 bag house used to control particulate mat t er 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.
Monit oring: 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 repo rting 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 pressur e drop, in order to achieve a minimum 99.5% control of TSP, PM 10 

### , 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 d ifferential 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 accorda nce 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 applicatio n for the proposed construction/modification/ revision and has determined that the provisions of the Act and ambient air quality standar ds 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. T he 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 p ermittee 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 st andards. 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

p ermittee shall submit additional mode ling 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 rep resentations 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 dischar ge of emissions or affect modeling results. Any such proposed change s 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 Sect ions 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. A t 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 pollutio n 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 pur suant 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. T he Department will assess an annual fee for this Facility. Th e regulation 20.2.75
NMAC set the fee amount at $1,500 through 2004 and requires it to be adjusted annually for the Co nsumer Price Index on January 1 . The current fee amount is availa ble by contacting the Department or can be found on the Department’s website. The AQB will invoice the p ermittee 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 accord ance 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. A ny person who participated in a permitting action before the Departm ent 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 not ice 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 revi ew 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

p ermitte e, the petitioner shall mail or hand

- deliver a copy of the petition to the applicant or p ermittee. 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 E nvironmental 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 t o eereports.aqb@state.nm.us . (20.2.7.110 NMAC)

C. R egularly 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 exces s emissions reporting requirements in accordance with 40 CFR 60.7(c), unless specifically exempted in the applicable subpart. NSP S 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 i n 40 CFR 63, then the facility is subject to the requirement for a Startup, Shutdown and Malfunction Pla n (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 p ermittee shall establish and implement a plan to minimize emi ssions 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 Requireme nts

B. The following monitor ing requirements shall be used to determine compliance with applicable requirements and emission limits. Any sampling, whether by portable analyzer o r 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 t o 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 p ermittee is not required to restart the unit for the sole purpose of performing the monitoring. Using electronic or written mail, the p ermittee shall notify the Department’s Compliance and Enforcement Section of a delay in emission tests prior to the dead line for accomplishing the tests. Upon recommencing operation, the p ermittee 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 P erformance 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 p ermittee 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

p ermittee shall conduct monitoring during the next period regardless of the time operated dur ing 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 r egulation 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% capa city 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 calculat e it shall be recorded to document operating conditions and shall be included with the monitorin g report

.

F. When requested by the Department, the p ermittee shall provide schedules of testing and monitoring activities. Compliance tests from previous NSR and T itle 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 appl icable 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 cond itions 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 permit t ee’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 r outine and predictable emissions during startup,

s hutdown, 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 t he 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 sch eduled. 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 fede ral 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 t he date, the start ti me, 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 whi ch 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 r eports shall be maintained on

- site unless specifically required to be submitted to the Department or EPA by another condition of this perm it or by a state

or federal regulation. Records for unmanned sites may be kept at the nearest company office.

B. The p ermittee shall notify the Department’s Complia nce 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 tha n 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 st artup date; and

(3) the date when each new or modified emission source reaches the maximum production rate at which it will operate within fi fteen (15) days after that date.

C. The p ermittee shall notify the Departm ent’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 su bstitutions 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 upd ate or correction of the permit.

D. Results of emission te sts 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. T he number of significant figures corresponding to the full accuracy inheren t 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, M S 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 re

imposed if it is deemed necessary by the Department to determine whether the source is in compliance with applicable r egulations or permit conditions. (20.2.72 NMAC Sections 210.C and 213 )

(2) Com pliance 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 condu cted 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 accidentall y 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 co ntrol, 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 conduc t 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, G eneral 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 SO 2 

### (d) Method 7E for NO X 

### (test results shall be expressed as nitroge n dioxide (NO 2 

### ) using a molecular weight of 46 lb/lb

- mol in all calculations (each ppm of NO/NO 2 

### 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) M ethod 7E or 20 for Turbines per 60.335 or 60.4400

(i) Method 29 for M etals
(j) Method 201 A for filterable PM 10 

### and PM 2.5 

### (Dry Stacks)

(k) Method 5, 5B or 5I for filterable PM 10 

### and PM 2.5 

### (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 i n 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, i f 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

Eac h performance test shall consist of three separate runs. T he arithmetic mean of results of the three runs shall be used to determine compliance wi th 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 lowe r operating rate, subject to prior approval of the Department.

(4) During emissions tests, pollutant, O 2 

### 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) T he p ermittee shall notify the Department’s Program M anager, Compliance and Enforcement Section at least thirty (30) days before the test date and allow a representative of the Departm ent 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 applicab le.

(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

com pletion 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 t he 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 conditi ons 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. E missions 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 p ermit or in the applicable requirement that establishes the limit.

B113

A. The Department may revoke this permit if the applicant or p ermittee has knowingly and willfully misrepresented a material fact in the application for the permit. Revocation will be made in writing, and an ad ministrative 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 fo r 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 on e (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 p ermittee shall notify the succeeding owner of the permit and conditions and shall noti fy the Department’s Program Manager, Permits Section of the change in ownership within fifteen (15) days of that change. (20.2.72. 2 12.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 demo lition or renovation work, the p ermittee shall determine whether 40 CFR 61 Subpart M, National Emissions Standards for Asbestos applies. If required, the p ermittee shall notify the Department’s Program Manager, Compliance and Enforcement Section using forms furnished by the Department

. Asb estos 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 permitt ed 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/sec 2



### 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 s econd T2 = absolute temperature of exhaust, replacement engine = degree F + 460 q2 = manufacturer’s potential emission rate, replacement engine, lbs/hour

The permittee shall keep record s showing that the replacement engine is at least as effective in the dispersion of air pollutants as the existing engine.

(c) T est 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

. C ompliance test (s) shall be conducted within fifteen (1 5 ) days after the unit begins operation , and records of the results shall be kept according to secti on 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 t hat 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 docum entation 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 li mits.

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 va lid 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 r egulations or permit conditions.

(e) Upon determining that emissions data developed according to B116.A.1 ( c) fail to indicate com pliance 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 e missions 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 t his 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 e ngine. Additionally, the record shall document the replacement duration in days, and the beginning and end date s 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 emission s 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 ac tual 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 b y 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 D efinitions

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 So u rces ” and “Exempt Activities” is defined as those sourc es 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 action s

.

C. “Fugitive E mission” 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 a ctivities 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 l east 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. (4 0 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, s hall 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 nitro gen dioxide and is sometimes referred to as NOx or NOx. (20.2.2 NMAC)

K. “ NOx ” see NO 2



### 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, provid ed 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 processe d, 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 t o 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 ces sation 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. "S SM " , 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 pr ocess units.

C102 Acronyms

2SLB

................................ ................................ ................................ ........ 2

- s troke l ean b urn 4SLB

................................ ................................ ................................ ........ 4

- s troke l ean b urn 4SRB

................................ ................................ ................................ ......... 4

- s troke r ich b urn 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 T hermal U nit
CAA

................................ ............................. Clean Air Act of 1970 and 1990 Amendments
CEM

................................ ................................ ................. c ontinuous e missions m onitoring cfh

................................ ................................ ................................ ........... cubic feet per hour cfm

................................ ................................ ................................ ....... cubic feet per minute
CFR

................................ ................................ ........................... Code of Federal Regulation
C I

................................ ................................ ................................ ........ compression ignition
CO

................................ ................................ ................................ ............ carbon monoxides
COMS

................................ ................................ ...... c ontinuous o pacity m onitoring s ystem 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

................................ ................................ ................................ ....................... h orsepower H 2 

### S

................................ ................................ ................................ .............. hydrogen sulfide
IC

................................ ................................ ................................ .......... i nternal c ombustion KW/hr

................................ ................................ ................................ ...... kilowatts per hour lb/hr

................................ ................................ ................................ .............. pounds per hour lb/MMBtu

................................ ............................. pounds per million British T hermal U nit

### 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

................................ ................................ ................................ .................. n ot a pplicable NAAQS

................................ ................................ . National Ambient Air Quality Standards
NESHAP

................................ . National Emission Standards for Hazardous Air Pollutants
NG

................................ ................................ ................................ ....................... n atural g as NGL

................................ ................................ ................................ ......... n atural g as l iquids 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

................................ ................................ ................. n on

- selective c atalytic r eduction
NSPS

................................ ................................ ............. New Source Performance Standard
NSR

................................ ................................ ................................ ....... New Source Re view
PEM

................................ ................................ .................. p arametric e missions m onitoring
PM

................................ particulate matter (equivalent to TSP, total suspended particulate)
PM 10



### ................................ ....................... particulate matter 10 microns and less in diameter
PM 2.5



### ................................ ..................... particulate matter 2.5 microns and less in diameter pph

................................ ................................ ................................ ................ pounds per hour

ppmv

................................ ................................ ......................... part s per million by volume
PSD

................................ ................................ ......... Prevention of Significant Deterioration
R ATA

................................ ................................ ........... Relative Accuracy Test Assessment
RICE

................................ ................................ .... reciprocating internal combustion engine

rpm

................................ ................................ ................................ .... revolutions per minute scfm

................................ ................................ ....................... standard cubic feet per minute
SI

................................ ................................ ................................ ................... spark ignition
SO 2



### ................................ ................................ ................................ .................. sulfur dioxide
S SM

................................ ................... Startup Shutdown Maintenance (see SSM definition)
TAP

................................ ................................ ................................ ........ Toxic Air Pollutant
TBD

................................ ................................ ................................ ............. to be determined
THC

................................ ................................ ................................ .......... t otal h ydrocarbons
TSP

................................ ................................ .......................... Total Suspended Particulates tpy

................................ ................................ ................................ ..................... tons per year ULSD

................................ ................................ ................................ .. ultra low sulfur diesel
USEPA

................................ ..................... United States Environmental Protection Agency
UT M

................................ ...................... Universal Transverse Mercator Coordinate system
UTMH

................................ ................................ Universal Transverse Mercator Horizontal
UTMV

................................ ................................ .... Universal Transverse Mercator Vertical
VHAP

................................ ................................ ................... volatile hazardous air pollutant
VOC

................................ ................................ .......................... volatile organic compoundsPNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALYSIS

BLACK & VEATCH | Appendix C C

- 1 

# Appendix C. Sargent & Lundy Design

, Process Description
, and Cost Estimates

# P UBLIC 

# S ERVICE OF 

# N EW 

# M EXICO



## S AN 

## J UAN 

## G ENERATING 

## S TATION 

## U NITS 

## 1, 2, 3, & 4

SNCR AND 

## SCR C OST 

## E STIMATES

Final Report

March 29, 2013

Project 11278-034

Prepared by :

55 East Monroe Street Chicago, IL 60603LEGAL 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 agr eement between S&L and Client. This Deliverable was

prepared using the degree of skill and care ordinarily exercised by e ngineers practicing under sim ilar 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) info rmation 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 accepta ble engineering practices may i nvalidate the findings of this

Deliverable.Project No. 11278-034

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SNCR AND SCR C OST E STIMATES i



### Table of Contents

1. I NTRODUCTION AND 

### B ACKGROUND 

### ......................................................................................................1

2. BART C OST 

### E STIMATING 

### .....................................................................................................................2

3. S&L’ S 

### C ONTROL 

### T ECHNOLOGY 

### C OST 

### E STIMATES 

### .............................................................................4

3.1 E MISSION U NITS AND C ONTROL S YSTEM D ESIGN P ARAMETERS ............................................................... 4

3.2 SCR C OST E STIMATE M ETHODOLOGY & A SSUMPTIONS ........................................................................... 6

3.2.1 Factors Affecting the Design: .................................................................................................. ................ 6

3.2.2 Project-Specific SCR Design Criteria and Assumptions.......................................................................... 9

3.3 SNCR C OST E STIMATE M ETHODOLOGY .................................................................................................... 11

3.3.1 Factors Affecting the SNCR Design .............................................................................................. ........ 12

3.3.2 Project-Specific SNCR Design Criteria and Assumptions..................................................................... 13

3.4 P LANT E CONOMIC A SSUMPTIONS ............................................................................................................... 15

3.5 O PERATING & M AINTENANCE C OST A SSUMPTION .................................................................................... 17

3.6 C OST E STIMATES

............................................................................................................................... ........... 18

3.6.1 SNCR Cost Estimates............................................................................................................ ................. 19

3.6.2 SCR Cost Estimates ............................................................................................................. .................. 19



### 4. S UMMARY



### ............................................................................................................................... ..............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 EstimatesProject No. 11278-034

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SNCR AND SCR C OST E STIMATES Page 1



### 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 corres ponding timeline for action intended to address pollution

control requirements for the San Juan Generating Sta tion under the Clean Air Act’s requirements for regional

haze and interstate transport for visibility.” Among othe r requirements, the agreement requires PNM to submit a

new Best Available Retrofit Technology (BART) anal ysis to the New Mexico Environment Department

(NMED). The Term Sheet requires PNM to prepare a “fiv e-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 determin ation 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 includ es 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) de velop 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 referen ced 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 co st 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.Project No. 11278-034

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information that was used for the co st 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 anal ysis for the San Juan Generating Station (SJGS), PNM

contracted S&L to update previously prepared concep tual cost estimates for both selective catalytic reduction

(SCR) and selective non-catalytic reduction (SNCR) contro l systems. In 2011, S&L prepared a conceptual

design, cost estimate, and Engineer, Procurement & Cons truction (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 a pproach 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 reduc tion (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 stat e that “[i]n order to maintain and

improve consistency, cost estimates should be based on th e Control Cost Manual, where possible.” The Control

Cost Manual describes the equipment and other directs cost s 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.Project No. 11278-034

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With respect to cost-effectiveness ev aluations, 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 Manua l, 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 proportiona l (variable costs) or partially proportional (semi-variable

costs) to some measure of productivity (e.g., exhaust g as process by the control system per unit time). Direct

costs include raw materials (reagents), utilities, waste tr eatment 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, propert y 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 th e 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 cap ital costs over the life of the investment. The annualized capital recovery

cost is a function of the Total Capital Investment (T CI), 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 equipm ent (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 fo r foundations and supports , erecting and handling

the equipment, electrical work, piping, insulation, and pain ting. Indirect installation costs include costs such as

engineering costs; construction and field expenses (i.e ., cost for construction s upervisory personnel, office

4 See, OAQPS Control Cost Manual , page 2-21.

5 Id. at page 2-5.

6 Id

.Project No. 11278-034

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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 appli cation of the analyst’s best judgment.” 8 In addition, the Control Costs

Manual specifically states that for certain control syst ems (e.g., SCR reactors and FGD units) it deviates from its

standard approach of providing study level costs and, in stead, 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 la rge or so site-specific in design that suppliers design,

fabricate, and construct each control accord ing 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 N on-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 Me xico, 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 un its for Units 1 and 2 were manufactured by Foster

Wheeler Corporation and the steam generating units fo r 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 ba ghouse 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.Project No. 11278-034

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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 aff ecting 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 emi ssion 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 ope rating 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

O 2 at Economizer
Outlet %vol (set) 3.36 2.67 3.00 2.78 v

Air H 2 O 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 o F 70 70 70 70 v

Economizer Outlet
Pressure in. w.c. +11.7 +11.4 +6.9 +7.3 v

Boiler SO 2 to SO 3 oxidation wt% SO 2 0.8 0.8 0.8 0.8 ej

Control System Design Parameters

SCR SO 2 to SO 3 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

NH 3 Slip (SCR) ppmvd @3% O 2 2 2 2 2 design

NOx Emission Limit (SNCR) lb/mmBtu 0.23 0.23 0.23 0.23 design

NH 3 Slip (SNCR) ppmvd @3% O 2 10 10 10 10 designProject No. 11278-034

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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 desi gn, project cost estimate, and technical portions of an

Engineer, Procurement, and Construction (EPC) specifica tion 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, et c.), and unit-specific balance-of-plant costs (e.g.,

economizer bypass modification, ash handling modificati on, 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 hand ling, fan capacity, and alternative reagents.

 Review ductwork and/or boiler sti ffening required to withstand the ne w 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 inte grate the SCRs into the plant’s operation.

 Estimate the quantities of materials (e.g., steel, c oncrete, 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 f actors 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 heat ers, they are in the middle of theProject No. 11278-034

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boiler outlet duct area. Because the stack s are also located adjacent to the ai r heaters, the area in which SCRs

may be installed is severely restricted.

The conceptual design study prepared for the S CR control systems concluded that, given the space

constraints, the best location for the SCRs will be a bove 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. Th e congestion also limits the options for structural steel

column placements to support the new SCR reactors a nd 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 f our 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 i ssues because it limits crane placement and the type of

structural foundations that can be added to support th e weight of the SCR. Crane placement is important

because of the need to build the ductwork over the ex isting ESPs, which means lifts spanning above the two

outside units to reach the two interior units will be re quired, where there is also limited room to assemble and

disassemble the cranes. The long spans and limited pl acement choices limit the crane selection choices to the

larger, more expensive cranes.

The tight site configuration also dictates that a more e xpensive type of deep structural foundations be used.

The very low overhead clearances and tight quarters adjacen t to the existing stacks, particularly south of the

Unit 1 stack where the adjacent fabric filter restrict s 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 installa tions, 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. 52388Project No. 11278-034

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limit of 0.05 lb/mmBtu. Thus, the SCRs must be desi gned 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, th e conceptual design study determined that the SJGS

SCRs should be designed to hold four layers of catalys t. Three layers will be installed initially, with the

fourth layer being added after approxi mately 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 th e additional pressure drop across the SCRs;

 Four layers of catalyst results in a larger S CR 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% O 2 ). SCR controls result

in increased SO 2 to SO 3 oxidation. SO 3 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 SO 3 formation across the

SCR. Ultra-low conversion catalyst will increase the si ze of the SCR reactor box and increase the weight of

the SCR. Based on vendor input from recent SCR installa tions, 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 installa tion of dry sorbent injection (DSI) for SO 3 control. Installation of

the SCR control systems significantly in creases 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 ex isting 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 pr essures in the boiler and ductwork will be close to

atmospheric pressure, will minimize or eliminate these f ugitive emissions. Because of the potential need to

address fugitive emissions, ancillary equipment costs (including fan sizing, boile r and ductwork stiffeningProject No. 11278-034

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requirements, auxiliary power requirements, and elect rical 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 conversi on would incrementally add to the size (and cost) of the

new fans and electrical system upgrades, and would requi re additional boiler and duc twork 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 a nd 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 re quirements and retrofit challenges associated with the

installation of SCR control systems at SJGS, the followi ng 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 allo w 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 incl uded 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 availa ble 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 existi ng precipitator. Reusing the existing ductwork was evaluated and found not to be acceptable due to the in crease in flue gas velocity. We also evaluatedProject No. 11278-034

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using the top hot-side precipitator as a duct, but agai n the degradation of the equipment and flue gas velocities would not support the design.

 Catalyst Layers . To achieve the required NOx emission reduc tions on a consistent basis with ultra-low
SO 2 to SO 3 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 in itially. 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 SJ GS results in increased cost s for the catalyst, as well as increased complexity and costs of the ash handling systems.

 Air Heater Modifications . Based on the temperatures expected fo r 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 opera ting 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 recirculati on 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 th e baghouses were designed to collect only a portion of the fly ash because up to 50% of the particulates fa ll 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 th e 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 w ill be cleaned using sonic horns. This system will require compressed air to operate. A separate compressor for each unit w as 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 th e economizer. This ash screen will be used to divert larger fly ash particles that can plug the SCR catal yst into the economizer ash hoppers. This may also eliminate the need for additional fly ash sy stems at the SCR inlet and outlet ductwork.Project No. 11278-034

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 SCR Catalyst Replacement . An elevator was included in the S CR cost estimate to replace spent catalyst at the end of the catalyst life.

 Dry Sorbent Injection . The SCR will increase the formation of SO 3 and SAM loading to downstream equipment. To meet the units’ existing SAM emi ssion 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 de pendent on the type of ammonia being used and whether each unit will have a separate ammonia st orage 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 fu ll load with the additional pressure loss generated by the SCR. Fan modifications include replacement of th e rotors and other fan modifications for the forced draft (FD) fans on all units, replacement of the i nduced draft (ID) fans and motors on all units, and addition of variable frequency drives to replace the ex isting fan inlet dampers. The existing electrical system of Units 1 and 2 may not be capable of ha ndling 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 we re 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 syst em and to operate the plant in a balanced draft configuration. These costs were included, along w ith 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 requi red, 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 ch aracteristics 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 alsoProject No. 11278-034

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contacted Fuel Tech, an SNCR Original Equipment Manufacturer (OEM) for preliminary equipment pricing

estimates and BOP requirements. Fuel Tech’s prelimin ary cost estimate was developed based on boiler-specific

operation information provided by S&L. Equipment co sts 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 effec tiveness 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 ava ilable 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, includi ng low urea utilization, low removal efficiency and high

ammonia slip. The SNCR equipment cost estimat e 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 ach ieve 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 revisi on 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 sp ecifications 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 temperat ure 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 rateProject No. 11278-034

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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 guara ntee. Combustion tuning will likely be required to

reduce the CO levels in the boilers. If additional re moval 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. F ugitive 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 requi rements 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 pum ps. 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 vi a 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 c onstant pressure of dilution water in response to changing flow demands. The metering modules provide fl ow 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 theProject No. 11278-034

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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 solu tion 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 determin ed 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 existi ng 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 wa ter 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 fo r 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 al so 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. SO 3 is formed in the
boiler from oxidation of sulfur in the coal. Urea that is injected in the boile r 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 SO 3 in the flue gas, the ammonia slip can react
with SO 3 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 gradua l 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 e fficiency 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 b een de-energized since the baghouse installation. This means that some of the particulate matter upon which the SO 3 and ammonia could conden se will be removed prior to the temperature window for ABS formation. Rem oving 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,Project No. 11278-034

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before knowing exactly how much gaseous SO 3 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-engin eered buildings would include alarm and detection, as well as fire extinguishers. It is anticipat ed no additional fire hydrants or a dispersion system will be required for the urea unloading area.

 Furnace Modifications . Penetrations in the boiler water wall w ill be required at the injector locations. To support the injector penetrations, water wall tub es will need to be removed and replaced with tubes curved around the penetration location, a boot and a fl ange. The injector(s) mount to the flange. In
some instances additional structural reinforcem ent may be required to support the injectors.

 Lighting and Maintenance Power System . The cost estimate was b ased 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 fo llow 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 interc onnected network of bare copper conductors and c opper ground rods. The systems would be designed to protect plant pers onnel and equipment from the hazards that can occur during power system faults and lightning strik es. The grounding system would be designed in accordance with applicable IEEE standards and w ould 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 acco mmodate both normal plant operations and extended plant shutdowns during cold weather. All urea pi ping 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 modifi cations 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 cont ractor. 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 ite ms include the SCR reactor vessel and catalystProject No. 11278-034

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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 comm odity-like materials, such as structural steel, concrete, piping, valves, cable, cable tray, and condu it. All material unit costs were estimated on the basis of S&L in-house data, vendor catalogs, and i ndustry publications. Quantities of materials were developed based on the conceptual designs and genera l arrangement drawings prepared for each control
system.

 Labor Costs . Union craft labor rates were developed fo r both projects for the Albuquerque, New Mexico area from the publication RS Means . Union rates were then incorporat ed into work crews appropriate for the activities by adding allowances for payroll taxes, wo rker’s compensation, fringe benefits, incidentals, small tools, construction equipment, and site overhead s 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 refl ects 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 & ConstructionProject No. 11278-034

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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 h as shown to be statistically likely to occur. Contingency is allowed by the Control Cost Manua l 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 cons truction 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 a nd 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 m oney, measured by the real discount rate, to be incorporated into the cost estimate. Although AF UDC 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 equipm ent and services performed) of both the SNCR and SCR projects.

12 OAQPS Control Cost Manual , page 2-5.Project No. 11278-034

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SNCR AND SCR C OST E STIMATES Page 18

3.5 Operating & Maintenance Cost Assumption

Annual O&M costs include both fixed and variable costs a nd indirect operating costs. Variable O&M costs are

items that generally vary in proportion to the plant cap acity factor. Variable costs associated with SCR and

SNCR control systems include: reagent costs (e.g., ur ea or anhydrous ammonia); catalyst replacement costs

(SCR); and auxiliary power costs associated with operati ng 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 produc tion, 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 th e SCR and SNCR cost estimates. Assumptions used to

calculate annual O&M costs are listed in each of the cost estimate work sheets, respectively.

3.6 Cost Estimates

Conceptual cost estimates were developed for the SN CR and SCR control systems based on the design criteria

and assumptions provided herein. Cost estimates prepared for the control systems in clude 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, i ndustry publications (such as Means and Richardson), and costs from other

similar projects. Cost estimates for the SJGS projects in clude the costs to install the control systems, as well as

the associated ductwork and equipment modifications ta king into account site-speci fic operating conditions and

site constraints. Cost estimates include EPC engineer ing, procurement and project services; EPC construction

management support; EPC commissioning; and an EPC f ee, as well as costs for owner’s engineering and

management. Cost estimates do not include escalation for e quipment, 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 th e 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

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SNCR AND SCR C OST E STIMATES 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 th e 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 unitProject No. 11278-034

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SNCR AND SCR C OST E STIMATES 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 need ed 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 equipmen t – 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 Un it 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 need ed 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 areaProject No. 11278-034

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SNCR AND SCR C OST E STIMATES 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 constraint s, 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 a pproach described in EPA’s Control Cost Manual, and

provides a conceptual cost estimate, or scoping-level es timate. Cost estimates prepared using default factors

provided in the Control Cost Manual are directed towa rd a study-level estimate with a nominal accuracy of

±30%. 13 Study-level estimates are generally acceptable fo r 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 estim ate 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 developmen t 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 reducti on 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

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# A TTACHMENT 

# A.
S AN 

## J UAN 

## G ENERATING 

## S TATION



## U NITS 

## 1, 2, 3, AND 

## 4

SNCR C OST 

## E STIMATESUnit 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 (excludi ng 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 ANALYSISUnit 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 31.6Unit 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 ANALYSISUnit 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 31.6Basis: S&L Cost Estimte 31803B (3/21/2012)Acct. No. Description Equipment Cost Material Cost Labor Cost Total NotesDIRECT & CONSTRUCTION INDIRECT COST11 Demolition & Relocation $0 $16,000 $16,00021 Civil Work$15,100 $15,10022 Concrete$140,100 $244,300 $384,40023 Steel$129,100 $171,800 $300,90024 Architectural27 Painting & Coating $10,000 $15,200 $25,20031-17, 31-53Mechanical Equipment $2,390,300 $0 $295,900 $2,686,20031-53-1SNCR System$1,730,300 $267,400 $1,997,70031-53-2CFD Model Study$150,000$150,00031-53-3Boiler Tuning$150,000$150,00031-17Air Compressor & Accessories $360,000 $28,500 $388,50035 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 $261,100SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,607,800 $1,067,900 $3,426,200 $7,101,900Other Direct & Construction Indirects91-1 Scaffolding$122,800 $122,80031-99 Boiler Injection Port Installation $60,000 $23,000 $393,400 $476,40091-2A Overtime: 5 - 10 hr days$449,700 $449,70091-2B Overtime: 6 - 10 hr days$125,900 $125,90091-4 Consumables$24,600 $24,60091-5 Freight on Material $54,500 $54,500SUBTOTAL $60,000 $77,500 $1,116,400 $1,253,90092TOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,667,800 $1,145,400 $4,542,600 $8,355,800Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 1Basis: S&L Cost Estimte 31803B (3/21/2012)Acct. No. Description Equipment Cost Material Cost Labor Cost Total NotesDetailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 1INDIRECT COST93-1A Owner's Engineering$167,100 2% of Acct. No. 9293-1B EPC Engineering$501,300 6% of Acct. No. 9293-2 Construction Management$167,100 2% of Acct. No. 9293-3 Startup Commissioning$83,600 1% of Acct. No. 9293-4 Owner's Cost$093-5 EPC Fee (% of Total Directs, Indirects)$1,391,20015% of Acct. Nos. 92, 93-1through 93-493TOTAL INDIRECT COST$2,310,300Total EscalationContingency95-1 Contingency on Equipment$266,800 10% of Acct. No. 9295-2 Contingency on Material$229,100 20% of Acct. No. 9295-3 Contingency on Labor$908,500 20% of Acct. No. 9295-4 Contingency on Indirect$462,100 20% of Acct. No. 9395Total Contingency$1,866,500TOTAL CONSTRUCTION COST$12,532,60097 Interest During Construction$0TOTAL PROJECT COST$12,532,600Basis: S&L Cost Estimte 31803B (3/21/2011)Acct. No. Description Equipment Cost Material Cost Labor Cost Total NotesDIRECT & CONSTRUCTION INDIRECT COST11 Demolition & Relocation $0 $16,000 $16,00021 Civil Work$15,100 $15,10022 Concrete$140,100 $244,300 $384,40023 Steel$129,100 $171,800 $300,90024 Architectural27 Painting & Coating $10,000 $15,200 $25,20031-17, 31-53Mechanical Equipment $2,390,300 $0 $295,900 $2,686,20031-53-1SNCR System$1,730,300 $267,400 $1,997,70031-53-2CFD Model Study$150,000$150,00031-53-3Boiler Tuning$150,000$150,00031-17Air Compressor & Accessories $360,000 $28,500 $388,50035 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 $261,100SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,607,800 $1,067,900 $3,426,200 $7,101,900Other Direct & Construction Indirects91-1 Scaffolding$122,800 $122,80031-99 Boiler Injection Port Installation $60,000 $23,000 $393,400 $476,40091-2A Overtime: 5 - 10 hr days$449,700 $449,70091-2B Overtime: 6 - 10 hr days$125,900 $125,90091-4 Consumables$24,600 $24,60091-5 Freight on Material $54,500 $54,500SUBTOTAL $60,000 $77,500 $1,116,400 $1,253,90092TOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,667,800 $1,145,400 $4,542,600 $8,355,800Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 2Basis: S&L Cost Estimte 31803B (3/21/2011)Acct. No. Description Equipment Cost Material Cost Labor Cost Total NotesDetailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 2INDIRECT COST93-1A Owner's Engineering$167,100 2% of Acct. No. 9293-1B EPC Engineering$501,300 6% of Acct. No. 9293-2 Construction Management$167,100 2% of Acct. No. 9293-3 Startup Commissioning$83,600 1% of Acct. No. 9293-4 Owner's Cost$093-5 EPC Fee (% of Total Directs, Indirects)$1,391,20015% of Acct. Nos. 92, 93-1through 93-493TOTAL INDIRECT COST$2,310,300Total EscalationContingency95-1 Contingency on Equipment$266,800 10% of Acct. No. 9295-2 Contingency on Material$229,100 20% of Acct. No. 9295-3 Contingency on Labor$908,500 20% of Acct. No. 9295-4 Contingency on Indirect$462,100 20% of Acct. No. 9395Total Contingency$1,866,500TOTAL CONSTRUCTION COST$12,532,60097 Interest During Construction$0TOTAL PROJECT COST$12,532,600Basis: S&L Cost Estimte 31804B (11/1/2012)Acct. No. Description Equipment Cost Material Cost Labor Cost Total NotesDIRECT & CONSTRUCTION INDIRECT COST11 Demolition & Relocation $15,000 $35,700 $50,70021 Civil Work$16,600 $16,60022 Concrete$178,800 $304,500 $483,30023 Steel$113,500 $138,800 $252,30024 Architectural27 Painting & Coating$200 $7,300 $7,50031-17, 31-53Mechanical Equipment $2,384,000 $0 $429,700 $2,813,70031-53-1SNCR System$1,724,000 $401,200 $2,125,20031-53-2CFD Model Study$150,000$150,00031-53-3Boiler Tuning$150,000$150,00031-17Air Compressor & Accessories $360,000 $28,500 $388,50035 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 $261,100SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,601,500 $1,048,600 $3,312,500 $6,962,600Other Direct & Construction Indirects91-1 Scaffolding$120,000 $120,00031-99 Boiler Injection Port Installation $48,000 $35,000 $402,200 $485,20091-2A Overtime: 5 - 10 hr days$431,300 $431,30091-2B Overtime: 6 - 10 hr days$135,400 $135,40091-4 Consumables$24,000 $24,00091-5 Freight on Material $54,200 $54,200SUBTOTAL $48,000 $89,200 $1,112,900 $1,250,10092TOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,649,500 $1,137,800 $4,425,400 $8,212,700Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 3Basis: S&L Cost Estimte 31804B (11/1/2012)Acct. No. Description Equipment Cost Material Cost Labor Cost Total NotesDetailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 3INDIRECT COST93-1A Owner's Engineering$164,300 2% of Acct. No. 9293-1B EPC Engineering$492,800 6% of Acct. No. 9293-2 Construction Management$164,300 2% of Acct. No. 9293-3 Startup Commissioning$82,100 1% of Acct. No. 9293-4 Owner's Cost$093-5 EPC Fee (% of Total Directs, Indirects)$1,367,40015% of Acct. Nos. 92, 93-1through 93-493TOTAL INDIRECT COST$2,270,900Total EscalationContingency95-1 Contingency on Equipment$265,000 10% of Acct. No. 9295-2 Contingency on Material$227,600 20% of Acct. No. 9295-3 Contingency on Labor$885,100 20% of Acct. No. 9295-4 Contingency on Indirect$454,200 20% of Acct. No. 9395Total Contingency$1,831,900TOTAL CONSTRUCTION COST$12,315,50097 Interest During Construction$0TOTAL PROJECT COST$12,315,500Basis: S&L Cost Estimte 31804B (11/1/2012)Acct. No. Description Equipment Cost Material Cost Labor Cost Total NotesDIRECT & CONSTRUCTION INDIRECT COST11 Demolition & Relocation $15,000 $35,700 $50,70021 Civil Work$16,600 $16,60022 Concrete$178,800 $304,500 $483,30023 Steel$113,500 $138,800 $252,30024 Architectural27 Painting & Coating$200 $7,300 $7,50031-17, 31-53Mechanical Equipment $2,384,000 $0 $429,700 $2,813,70031-53-1SNCR System$1,724,000 $401,200 $2,125,20031-53-2CFD Model Study$150,000$150,00031-53-3Boiler Tuning$150,000$150,00031-17Air Compressor & Accessories $360,000 $28,500 $388,50035 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 $261,100SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,601,500 $1,048,600 $3,312,500 $6,962,600Other Direct & Construction Indirects91-1 Scaffolding$120,000 $120,00031-99 Boiler Injection Port Installation $48,000 $35,000 $402,200 $485,20091-2A Overtime: 5 - 10 hr days$431,300 $431,30091-2B Overtime: 6 - 10 hr days$135,400 $135,40091-4 Consumables$24,000 $24,00091-5 Freight on Material $54,200 $54,200SUBTOTAL $48,000 $89,200 $1,112,900 $1,250,10092TOTAL DIRECT & CONSTRUCTION INDIRECT COST $2,649,500 $1,137,800 $4,425,400 $8,212,700Detailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 4Basis: S&L Cost Estimte 31804B (11/1/2012)Acct. No. Description Equipment Cost Material Cost Labor Cost Total NotesDetailed SNCR Cost Estimate Summary - San Juan Generating Station Unit 4INDIRECT COST93-1A Owner's Engineering$164,300 2% of Acct. No. 9293-1B EPC Engineering$492,800 6% of Acct. No. 9293-2 Construction Management$164,300 2% of Acct. No. 9293-3 Startup Commissioning$82,100 1% of Acct. No. 9293-4 Owner's Cost$093-5 EPC Fee (% of Total Directs, Indirects)$1,367,40015% of Acct. Nos. 92, 93-1through 93-493TOTAL INDIRECT COST$2,270,900Total EscalationContingency95-1 Contingency on Equipment$265,000 10% of Acct. No. 9295-2 Contingency on Material$227,600 20% of Acct. No. 9295-3 Contingency on Labor$885,100 20% of Acct. No. 9295-4 Contingency on Indirect$454,200 20% of Acct. No. 9395Total Contingency$1,831,900TOTAL CONSTRUCTION COST$12,315,50097 Interest During Construction$0TOTAL PROJECT COST$12,315,500Basis: S&L Cost Estimte 31807B (11/1/2011)Acct. No. Description Equipment Cost Material Cost Labor Cost Total NotesDIRECT & CONSTRUCTION INDIRECT COST11 Demolition & Relocation $15,000 $35,700 $50,70021 Civil Work $195,000 $8,400 $203,40022 Concrete$39,000 $67,600 $106,60023 Steel$024 Architectural$705,000 $519,500 $1,224,50027 Painting & Coating $1,000 $24,400 $25,40031 Mechanical Equipment$855,000 $7,200 $158,500 $1,020,70031-45Fire Protection$7,200 $3,000 $10,20031-75Pumps$60,000 $10,600 $70,60031-83Tanks$45,000 $7,900 $52,90031-93Dilution Water Treatement System $750,000 $137,000 $887,00035 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 $107,800SUBTOTAL DIRECT & CONSTRUCTION INDIRECT COST $1,197,600 $1,344,200 $2,246,200 $4,788,000Other Direct & Construction Indirects91-1 Scaffolding$90,600 $90,60031-99 Boiler Injection Port Installation$091-2A Overtime: 5 - 10 hr days$302,600 $302,60091-2B Overtime: 6 - 10 hr days$091-4 Consumables$18,100 $18,10091-5 Freight on Material $67,300 $67,300SUBTOTAL $0 $67,300 $411,300 $478,60092TOTAL DIRECT & CONSTRUCTION INDIRECT COST $1,197,600 $1,411,500 $2,657,500 $5,266,600Detailed 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 NotesDetailed SNCR Cost Estimate Summary - San Juan Generating Station Common Areas (Units 1 & 3)INDIRECT COST93-1A Owner's Engineering$105,300 2% of Acct. No. 9293-1B EPC Engineering$316,000 6% of Acct. No. 9293-2 Construction Management$105,300 2% of Acct. No. 9293-3 Startup Commissioning$52,700 1% of Acct. No. 9293-4 Owner's Cost$093-5 EPC Fee (% of Total Directs, Indirects)$876,90015% of Acct. Nos. 92, 93-1through 93-493TOTAL INDIRECT COST$1,456,200Total EscalationContingency95-1 Contingency on Equipment$119,800 10% of Acct. No. 9295-2 Contingency on Material$282,300 20% of Acct. No. 9295-3 Contingency on Labor$531,500 20% of Acct. No. 9295-4 Contingency on Indirect$291,200 20% of Acct. No. 9395Total Contingency$1,224,800TOTAL CONSTRUCTION COST$7,947,60097 Interest During Construction$0TOTAL PROJECT COST$7,947,600Project No. 11278-034

S AN J UAN G ENERATING S TATION 03/29/2013

SNCR AND SCR C OST E STIMATES Page 23



# A TTACHMENT 

# B.
S AN 

## J UAN 

## G ENERATING 

## S TATION



## U NITS 

## 1 & 2

SCR C OST 

## E STIMATESUnit 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 Ca p ital 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 bet ween 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 co ngestion 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 NH 3 Consumption lb NH3/hr 360 358
Avera g e Rea g ent Consum p tion t py 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 $/m 3 8,000 8,000 Hydrated Lime Cost $/ton 120 120
Initial Catalyst Volume m 3 604 604 Initial Catalyst Layers 3 3 Catalyst replacement cycle yrs 2 2 Flue Gas Flow acfm 2,056,400 1,999,900
Pressure Dro p 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 $/ y r $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 $8,000/m3 and using a future worth factor of 0.48 calculated as follows: FWF = i * [ 1 / (1 + i)y - 1]; where i = an assumed interest rate of 8.44% and y = 2 (i.e., replacing one layer every other year. See, Control Cost Manual, Section 4.2, Chapter 2, pg. 2-47Basis: S&L Cost Estimte 31326C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 1 NotesA-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 $2,853,700A. Total $11,544,400 $19,448,700 $33,165,800 $64,158,900B-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 $3,700B. Total $907,000 $36,900 $122,400 $1,066,300C-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 $0C. Total $875,000 $51,300 $748,300 $1,674,600Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 1A. SCR Area and Economizer BypassB. Sorbent Injection SystemC. Baghouse Ash Handling SystemBasis: S&L Cost Estimte 31326C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 1 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 1D-31 Mechanical Equipment $181,000 $0 $16,300 $197,300D-35 Piping $0 $69,600 $176,300 $245,900D. Total $181,000 $69,600 $192,600 $443,200E-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 $200,000E. Total $2,433,500 $1,580,600 $4,538,900 $8,553,000F-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 $574,000F. Total $8,819,100 $1,463,100 $6,209,400 $16,491,600G. Total$1,757,600 $1,757,60090 Subtotal $24,760,000 $22,650,200 $46,735,000 $94,145,200G. Construction Equipment SupplementD. Anhydrous AmmoniaE. ElectricalF. Balanced Draft ConversionBasis: S&L Cost Estimte 31326C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 1 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 191 Other Direct & Construction Indirect Costs91-1 Scaffolding$1,734,600 $1,734,600 2.5% of Acct. No. 90 Labor & Materials91-2A Cost Due to overtime working 5 - 10 hour days $5,276,200 $5,276,20091-2BCost Due to overtime working 7 - 12 hour days during the tie-inoutage$3,954,800 $3,954,80091-3 Per Diem$0 Not Included91-4 Consumables$346,900 $346,900 0.5% of Acct. No. 90 Labor & Materials91-5 Freight on materials $1,132,500 $1,132,500 5% of Acct. No. 90 (Material Costs)91-7 Sales Tax$0 Not Included (See, Acct. No. 96A below)91-9 Contractor G&A Expenses$0 Included in EPC Fee91-10 Contractor Profit$0 Included in EPC Fee91. Subtotal $0 $1,132,500 $11,312,500 $12,445,00092Total Direct & Construction Indirect Cost $24,760,000 $23,782,700 $58,047,500 $106,590,20093 Indirect Costs93-1 EPC Engineering, Procurement & Project Services$8,527,200 8% of Acct. No. 9293-2 EPC Construction Management Support$3,197,700 3% of Acct. No. 9293-3 EPC Startup Commissioning$1,065,900 1% of Acct. No. 9293-4 EPC Fee$17,907,200 15% of Acct. Nos. 92, 93.1, 93.2, 93.393-5 Owner's Costs$093-5-1 Owner's Engineer & Construction Management$3,777,100 By PNM93-5-2 Performance Testing$100,00093-5-3 Anhydrous Ammonia Risk Management & Training$093. Total$34,575,100Basis: S&L Cost Estimte 31326C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 1 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 194 Total Escalation95 Total Contingency$28,233,000 20% of 92 + 9396 Total Construction Cost$169,398,30096A New Mexico Gross Receipt Tax (NMGRT)$10,693,30096B Total Construction Cost with NMGRT$180,091,60097 Interest During ConstructionNot Included97A Lost Generation During Extended OutageNot Included98 TOTAL PROJECT COST$180,091,600Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 2 NotesA-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 $2,853,700A. Total $11,544,400 $19,695,300 $44,332,700 $75,572,400B-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 $6,500B. Total $907,000 $45,500 $185,500 $1,138,000C-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 $0C. Total $875,000 $48,200 $753,500 $1,676,700A. SCR Area and Economizer BypassB. Sorbent Injection SystemC. Baghouse Ash Handling SystemDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 2Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 2 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 2D-31 Mechanical Equipment $181,000 $0 $16,300 $197,300D-35 Piping $0 $106,900 $412,000 $518,900D. Total $181,000 $106,900 $428,300 $716,200E-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 $200,000E. Total $2,433,500 $1,580,600 $4,538,900 $8,553,000F-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 $574,000F. Total $8,819,100 $1,463,100 $6,209,400 $16,491,600G. Total$912,900 $912,90090 Subtotal $24,760,000 $22,939,600 $57,361,200 $105,060,800D. Anhydrous AmmoniaE. ElectricalF. Balanced Draft ConversionG. Construction Equipment SupplementBasis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 2 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 291 Other Direct & Construction Indirect Costs91-1 Scaffolding$2,007,500 $2,007,500 2.5% of Acct. No. 90 Labor & Materials91-2A Cost Due to overtime working 5 - 10 hour days $6,475,900 $6,475,90091-2BCost Due to overtime working 7 - 12 hour days during the tie-inoutage$4,854,100 $4,854,10091-3 Per Diem$0 Not Included91-4 Consumables$401,500 $401,500 0.5% of Acct. No. 90 Labor & Materials91-5 Freight on materials $1,147,000 $1,147,000 5% of Acct. No. 90 (Material Costs)91-7 Sales Tax$0 Not Included (See, Acct. No. 96A below)91-9 Contractor G&A Expenses$0 Included in EPC Fee91-10 Contractor Profit$0 Included in EPC Fee91. Subtotal $0 $1,147,000 $13,739,000 $14,886,00092Total Direct & Construction Indirect Cost $24,760,000 $24,086,600 $71,100,200 $119,946,80093 Indirect Costs93-1 EPC Engineering, Procurement & Project Services$9,595,700 8% of Acct. No. 9293-2 EPC Construction Management Support$3,598,400 3% of Acct. No. 9293-3 EPC Startup Commissioning$1,199,500 1% of Acct. No. 9293-4 EPC Fee$20,151,100 15% of Acct. Nos. 92, 93.1, 93.2, 93.393-5 Owner's Costs$093-5-1 Owner's Engineer & Construction Management$3,777,100 By PNM93-5-2 Performance Testing$100,00093-5-3 Anhydrous Ammonia Risk Management & Training$093. Total$38,421,800Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 2 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 294 Total Escalation95 Total Contingency$31,674,000 20% of 92 + 9396 Total Construction Cost$190,042,60096A New Mexico Gross Receipt Tax (NMGRT)$11,996,40096B Total Construction Cost with NMGRT$202,039,00097 Interest During ConstructionNot Included97A Lost Generation During Extended OutageNot Included98 TOTAL PROJECT COST$202,039,000Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor CostSJGS Units 1 & 2CommonNotesA-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 $164,500A. Total $650,000 $50,200 $201,000 $901,200D-21 Civil Work $0 $0 $0 $0D-22 Concrete $0 $13,800 $23,000 $36,800D-31 Mechanical Equipment $841,000 $0 $51,200 $892,200D. Total $841,000 $13,800 $74,200 $929,000F-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 $1,512,900F. Total $1,950,300 $180,400 $639,900 $2,770,60090 Subtotal $3,441,300 $244,400 $915,100 $4,600,800D. Anhydrous AmmoniaF. Balanced Draft ConversionA. SCR Area and Economizer BypassDetailed SCR Cost Estimate Summary - San Juan Generating Station Units 1 & 2 CommonBasis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor CostSJGS Units 1 & 2CommonNotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Units 1 & 2 Common91 Other Direct & Construction Indirect Costs91-1 Scaffolding$29,000 $29,000 2.5% of Acct. No. 90 Labor & Materials91-2A Cost Due to overtime working 5 - 10 hour days $103,300 $103,30091-2BCost Due to overtime working 7 - 12 hour days during the tie-inoutage$77,500 $77,50091-3 Per Diem$0 Not Included91-4 Consumables$5,800 $5,800 0.5% of Acct. No. 90 Labor & Materials91-5 Freight on materials $12,200 $12,200 5% of Acct. No. 90 (Material Costs)91-7 Sales Tax$0 Not Included (See, Acct. No. 96A below)91-9 Contractor G&A Expenses$0 Included in EPC Fee91-10 Contractor Profit$0 Included in EPC Fee91. Subtotal $0 $12,200 $215,600 $227,80092Total Direct & Construction Indirect Cost $3,441,300 $256,600 $1,130,700 $4,828,60093 Indirect Costs93-1 EPC Engineering, Procurement & Project Services$386,300 8% of Acct. No. 9293-2 EPC Construction Management Support$144,900 3% of Acct. No. 9293-3 EPC Startup Commissioning$48,300 1% of Acct. No. 9293-4 EPC Fee$811,200 15% of Acct. Nos. 92, 93.1, 93.2, 93.393-5 Owner's Costs$093-5-1 Owner's Engineer & Construction Management$0 Included in Units 1 & 2 Costs93-5-2 Performance Testing$0 Included in Units 1 & 2 Costs93-5-3 Anhydrous Ammonia Risk Management & Training$093. Total$1,390,700Basis: S&L Cost Estimate No. 31327C (10/14/2011 - 2011$)Acct. No. Description Equipment Cost Material Cost Labor CostSJGS Units 1 & 2CommonNotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Units 1 & 2 Common94 Total Escalation95 Total Contingency$1,243,800 20% of 92 + 9396 Total Construction Cost$7,463,10096A New Mexico Gross Receipt Tax (NMGRT)$471,10096B Total Construction Cost with NMGRT$7,934,20097 Interest During ConstructionNot Included97A Lost Generation During Extended OutageNot Included98 TOTAL PROJECT COST$7,934,200Project No. 11278-034

S AN J UAN G ENERATING S TATION 03/29/2013

SNCR AND SCR C OST E STIMATES Page 24



# A TTACHMENT 

# C.
S AN 

## J UAN 

## G ENERATING 

## S TATION



## U NITS 

## 3 & 4

SCR C OST 

## E STIMATESUnit 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 + Freigh t

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 Draf t 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 an d 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 an d 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 Cos t $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 bet ween 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 co ngestion 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 NH 3 Consumption lb NH3/hr 559 548
Avera g e Rea g ent Consum p tion t py 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 $/m 3 8,000 8,000 Hydrated Lime Cost $/ton 120 120
Initial Catalyst Volume m 3 938 938 Initial Catalyst Layers 3 3 Catalyst replacement cycle yrs 2 2 Flue Gas Flow acfm 3,206,400 3,191,200
Pressure Dro p 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 $/ y r $4,121,600 $4,085,300

* Catalyst replacement costs were calculated based on replacing 1 layer of catalyst (approx. 202 m 3 ) once every two years. Catalyst costs were calculated by multiplying the volume of catalyst by the installed unit cost of $8,000/m 3 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. 2-47Basis: S&L Cost Estimte 31329C (10/14/2011)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 3 NotesA-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 $4,380,100A. Total $15,836,800 $29,267,900 $62,504,500 $107,609,200B-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 $13,000B. Total $969,500 $48,200 $191,000 $1,208,700C-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 $0C. Total $810,000 $51,300 $707,400 $1,568,700Detailed SCR Cost Estimate Summary - San Juan Generating Station Unit 3A. SCR Area and Economizer BypassB. Sorbent Injection SystemC. Baghouse Ash Handling SystemBasis: S&L Cost Estimte 31329C (10/14/2011)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 3 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 3D-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 $236,600D. Total $972,000 $81,400 $251,200 $1,304,600E-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 $200,000E. Total $2,483,500 $1,459,700 $4,636,900 $8,580,100F-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 $7,500F. Total $11,978,100 $253,700 $5,565,600 $17,797,400G-61 Construction Equipment $0 $0 $912,900 $912,900G. Total $0 $0 $912,900 $912,90090 Subtotal $33,049,900 $31,162,200 $74,769,500 $138,981,600G. Construction Equipment SupplementD. Anhydrous AmmoniaE. ElectricalF. Balanced Draft ConversionBasis: S&L Cost Estimte 31329C (10/14/2011)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 3 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 391 Other Direct & Construction Indirect Costs91-1 Scaffolding$2,648,300 $2,648,300 2.5% of Acct. No. 90 Labor & Materials91-2A Cost Due to overtime working 5 - 10 hour days $8,441,200 $8,441,20091-2BCost Due to overtime working 7 - 12 hour days during the tie-inoutage$6,327,200 $6,327,20091-3 Per Diem$0 Not Included91-4 Consumables$529,700 $529,700 0.5% of Acct. No. 90 Labor & Materials91-5 Freight on materials $1,558,100 $1,558,100 5% of Acct. No. 90 (Material Costs)91-7 Sales Tax$0 Not Included (See, Acct. No. 96A below)91-9 Contractor G&A Expenses$0 Included in EPC Fee91-10 Contractor Profit$0 Included in EPC Fee91. Total $0 $1,558,100 $17,946,400 $19,504,50092 Total Direct & Construction Indirect Cost $33,049,900 $32,720,300 $92,715,900 $158,486,10093 Indirect Costs93-1 EPC Engineering, Procurement & Project Services$12,678,900 8% of Acct. No. 9293-2 EPC Construction Management Support$4,754,600 3% of Acct. No. 9293-3 EPC Startup Commissioning$1,584,900 1% of Acct. No. 9293-4 EPC Fee$26,625,700 15% of Acct. Nos. 92, 93.1, 93.2, 93.393-5 Owner's Costs$093-5-1 Owner's Engineer & Construction Management$5,668,138 By PNM93-5-2 Performance Testing$100,00093-5-3 Anhydrous Ammonia Risk Management & Training$093. Total$51,412,238Basis: S&L Cost Estimte 31329C (10/14/2011)Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 3 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 394 Total Escalation95 Total Contingency$41,979,700 20% of 92 + 9396 Total Construction Cost$251,878,03896A New Mexico Gross Receipt Tax (NMGRT)$15,899,80196B Total Construction Cost with NMGRT$267,777,83997 Interest During ConstructionNot Included98 TOTAL PROJECT COST$267,777,839Basis: S&L Cost Estimate No. 31327C 10/14/2011Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 4 NotesA-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 $4,380,100A. Total $15,836,800 $29,267,900 $47,632,300 $92,737,000B-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 $13,000B. Total $969,500 $48,200 $172,700 $1,190,400C-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 $0C. Total $810,000 $39,000 $679,200 $1,528,200A. SCR Area and Economizer BypassB. Sorbent Injection SystemC. Baghouse Ash Handling SystemDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 4Basis: S&L Cost Estimate No. 31327C 10/14/2011Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 4 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 4D-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 $444,600D. Total $972,000 $109,800 $430,800 $1,512,600E-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 $200,000E. Total $2,483,500 $1,459,700 $4,636,900 $8,580,100F-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 $7,500F. Total $11,978,100 $253,700 $5,565,600 $17,797,400G-61 Construction Equipment $1,479,800 $0 $277,800 $1,757,600G. Total $1,479,800 $0 $277,800 $1,757,60090 Subtotal $34,529,700 $31,178,300 $59,395,300 $125,103,300D. Anhydrous AmmoniaE. ElectricalF. Balanced Draft ConversionG. Construction Equipment SupplementBasis: S&L Cost Estimate No. 31327C 10/14/2011Acct. No. Description Equipment Cost Material Cost Labor Cost SJGS Unit 4 NotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Unit 491 Other Direct & Construction Indirect Costs91-1 Scaffolding$2,264,300 $2,264,300 2.5% of Acct. No. 90 Labor & Materials91-2A Cost Due to overtime working 5 - 10 hour days $6,705,500 $6,705,50091-2BCost Due to overtime working 7 - 12hourdaysduring the tie-inoutage$5,026,200 $5,026,20091-3 Per Diem$0 Not Included91-4 Consumables$452,900 $452,900 0.5% of Acct. No. 90 Labor & Materials91-5 Freight on materials $1,558,900 $1,558,900 5% of Acct. No. 90 (Material Costs)91-7 Sales Tax$0 Not Included (See, Acct. No. 96A below)91-9 Contractor G&A Expenses$0 Included in EPC Fee91-10 Contractor Profit$0 Included in EPC Fee91. Total $0 $1,558,900 $14,448,900 $16,007,80092 Total Direct & Construction Indirect Cost $34,529,700 $32,737,200 $73,844,200 $141,111,10093 Indirect Costs93-1 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, 93.1, 93.2, 93.393-5 Owner's Costs$093-5-1 Owner's Engineer & Construction Management$5,668,138 By PNM93-5-2 Performance Testing$100,00093-5-3 Anhydrous Ammonia Risk Management & Training$093. Total$46,408,13894 Total Escalation95 Total Contingency$37,503,700 20% of 92 + 9396 Total Construction Cost$225,022,93896A New Mexico Gross Receipt Tax (NMGRT)$14,204,57396B Total Construction Cost with NMGRT$239,227,51197 Interest During ConstructionNot Included98 TOTAL PROJECT COST$239,227,511Basis: S&L Cost Estimate No. 31327C 10/14/2011Acct. No. Description Equipment Cost Material Cost Labor CostSJGS Units 3 & 4CommonNotesD-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 $30,000D. Total $215,700 $580,500 $1,952,600 $2,748,80090 Subtotal $215,700 $580,500 $1,952,600 $2,748,80091 Other Direct & Construction Indirect Costs91-1 Scaffolding$63,300 $63,300 2.5% of Acct. No. 90 Labor & Materials91-2 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 Labor & Materials91-5 Freight on materials $29,000 $29,000 5% of Acct. No. 90 (Material Costs)91-7 Sales Tax$0 Not Included (See, Acct. No. 96A below)91-9 Contractor G&A Expenses$0 Included in EPC Fee91-10 Contractor Profit$0 Included in EPC Fee91. Subtotal $0 $29,000 $335,400 $364,40092 Total Direct & Construction Indirect Cost $215,700 $609,500 $2,288,000 $3,113,200D. Anhydrous AmmoniaDetailed SCR Cost Estimate Summary - San Juan Generating Station Units 3 & 4 CommonBasis: S&L Cost Estimate No. 31327C 10/14/2011Acct. No. Description Equipment Cost Material Cost Labor CostSJGS Units 3 & 4CommonNotesDetailed SCR Cost Estimate Summary - San Juan Generating Station Units 3 & 4 Common93 Indirect Costs93-1 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, 93.1, 93.2, 93.393-5 Owner's Costs$093-5-1 Owner's Engineer & Construction Management$149,069 By PNM93-5-2 Anhydrous Ammonia Risk Management & Training$093. Total$1,045,66994 Total Escalation95 Total Contingency$831,700 20% of 92 + 9396 Total Construction Cost$4,990,56996A New Mexico Gross Receipt Tax (NMGRT)$315,03096B Total Construction Cost with NMGRT$5,305,59997 Interest During ConstructionNot Included98 TOTAL PROJECT COST$5,305,599PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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 2 004 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 snow

capped 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 SO 2 

### Emission Rate

................................ ................................ ...................... 34
6.1.3 Sulfuric Acid Emission Estimates

................................ .............................. 35
6.1.3.1 Assumptions used in S ulfuric 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

Atta chment 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 Decr ee 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 98 th 

### 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 H 2 

### SO 4 

### 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 98 th



### percentile of daily maxi mum dv for 2001, 2002, and 2003) at Sixteen Class I
Areas

................................ ................................ ................................ ............... 33 Table 6

- 1. Assumptions used in Sulfuric acid (H 2 

### SO 4 

### ) 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 98 th



### 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 98 th



### 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

- Summa ry 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 Met hod 8).

................................ 48

### 6



## Chapter 1: Background and Description of San Juan Generating Station
1.1 B ACKGROUND


### As described in our proposed action Federal Register notice, EPA is proposing to disapprove a portion of the State Implementation Plan (SIP) re vision 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) an d 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 par t 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 (NO x ) and sulfur dioxide (SO 2 

### ) emission limits necessary at one source to prevent such interference. In addition, EPA is proposing sulfuric acid (H 2 

### SO 4 

### ) and ammonia (NH 3 

### ) hourly emission limits at the same source, to minimize the contribution of these co mpounds 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 t echnology (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 D ESCRIPTION OF 

### S AN 

### J UAN 

### G ENERATING 

### S TATION


### 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 mi les west of Farmington in northwest New Mexico. SJGS Units 1 and 2 have a unit capacity of 350 and 360 MW, respectively. The se units are subcritical, wall

- fired boilers that operate in a forced draft mode. SJGS Units 3 and 4 have a unit capacity of 544 M W 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 r emaining 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 t echnology

.

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

- NO x 

### burners (LNB) with overfire air (OFA) ports and a neural network (NN) system to reduce NO x 

### 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
SO 2 

### 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 SO 2 

### co ntrol

. 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 Wall

fired/Babcock &
Wilcox Opposed Wall

fired/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
NO
x Post

- consent decree baseline emission rate 0.30 lb/ MMBtu for each unit

SO 2 Presumptive BART emission rate 90% annual average control, not to exceed 0.250 lb/ MMBtu for a seven da y 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 Apri l 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 enf orceable 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 progr am of the New Mexico SIP. Specifically, the construction permit includes the NOx, SO 2 

### 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 in cludes the consent decree limits on NOx, SO 2 

### , and PM emissions and is federally enforceable. 2

1 Consent Decree in The Grand Canyon Trust and Sierra Club, Plaintiffs, The State of New Mexic o, 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 A ir Partnership (WRAP) photochemical modeling for the NOx and SO 2 

### 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 dis crepancies 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 phot ochemical 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 t he 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.

Simi larly, 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 SO 2 

### , which is much higher than the 0.15 lb/ MMBtu emission rate utilized in the WRAP‘s photo chemical 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 SO 2 

### 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 SO 2 

### 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 fr om 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 ai r 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 de veloping 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 commi tment 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 emi t 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 mu st 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; revi sed 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 sp ecific presumptive limits for SO 2 

### 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 me et 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 Eligi bility 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 ident ifying 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 mod eling 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 ye ars of modeling of 2001, 2002, and 2003.

• Visibility impacts due to emissions of SO 2 

### , NOx and primary PM emissions were calculated.

• PM emissions were modeled as PM2.5.

• Visibility was calculated using the Original IMPROVE equation and Annual Averag e 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 contribut es 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 c hange may still contribute to visibility impairment and thus be subject to
BART. The modeling of each individual source complexes‘ combined SO 2 

### , NOx, and PM emissions was completed and results of the 98 th 

### 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 SO 2 

### , NOx, and PM emissi ons 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 determinatio n. The results of this analysis (Table 3

- 1) indicated that the S an J uan G enerating S tation (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 J ia, 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_Ap r21_2007.doc )

### 12

determining an appropriate threshold for determi ning 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 impairm ent 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 th e installation of consent decree controls. Refined modeling performed by the N ew M exico Environmental Department (NM ED ) and by the E nvironmental 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 la test 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 f or 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 V erde 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

W heeler 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 Facili ty
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 0.3 2 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 B ACKGROUND AND 

### I NTRODUCTION


### 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 tha t 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 qual ity 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 curr ent, 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 10 th 

### (mean of Best 20% days) and 90 th 

### (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 10 th Percentile Deciview Impairment 90 th Percen tile Deciview Impairment
Arches 2.9 11.3
Bandelier W ilderness 4.2 12.2 Black Canyon of the Gunnison
W ilderness 2.2 10.5

Canyonlands 2.9 11.3 Capitol Reef 2.8 11.5 Grand Canyon 2.1 11.2
Great Sand Dunes N ational Monument 3.5 11.2
La Garita W ilde rness 2.2 10.5
Maroon Bells Snowmass W ilderness 0.2 9.3
Mesa Verde 3.1 11.0
Pecos W ilderness 1.2 8.6
Petrified Forest 4.5 12.5
San Pedro Parks W ilderness 2.8 11.3
West Elk W ilderness 0.2 9.3
Weminuche W ilderness 2.2 10.5
Wheeler Peak W ilderness 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 monitor 13 Minimum

Distance to SJGS (km)
Arches arch UT NPS CANY1 222
Bandelier Wild erness 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 anothe r area is used.

### 16

Visibility modeling was performed for the San Juan Generating Station and included the sixteen Class I Ar eas 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 visib ility 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. NME D 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 C ALCULATION OF 

### V ISIBILITY 

### I MPACT


### 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 deciv iews will be perceived as the same amount of visibility change, whatever the original visibility was. The defining equation is:

deciviews = 10*ln(b ext 

### / 10)

where ln is the natural logarithm, and extinction b ext 

### is the fraction of light scattere d out of a viewing path. Extinction increases with the amount of pollution (b ext 

### 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 sourc e 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: SO 2 

### , SO 4 

### , NO
x 

### , secondary organic aerosol (SOA), fine part iculate 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 SO 2 

### to particulate sulfate and NO
x 

### to particulate nitrate, at a rate dependent on mete orological conditions and background ozone concentration. These concentrations are converted to deciviews by the CALPOST post

processor in two steps.

4.2.1 IMPROVE Equation Under the original IMPROVE equation, extinction ( b ext 

### ) is estimated from the predicte d concentrations of various pollutants: 16



### b ext 

### = 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 scatteri ng , 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 ; i ts 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:

b ext 

### = 2.2 * f

s 

### (RH) * [small sulfate] + 4.8 * f L 

### (R H) * [large sulfate] + 2.4 * f

s 

### (RH) * [small nitrate] + 5.1 * f L 

### (RH) * [large nitrate] + 2.8 * [small organic mass] + 6.1 * [large organic mass] + 10 * [ elemental carbon ] + 1 * [ fine soil ] + 1.7 * f

ss 

### (RH) * [sea salt] + 0.6 * [ coarse mass ] + Rayleigh scattering (site

- specific) + 0.33 * [NO 2 

### (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/m 3



### , otherwise its fraction of the total is assumed to increase uniformly between 0 and 1 when the total i s 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 organ ic 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)
T he f s 

### , f L 

### , f ss 

### 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 molecul es 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 particul ar, 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 wors t 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 t he 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 R egional H aze R ule

.

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 I MPROVE Equation for Estimating Ambient Light Extinction Coefficients

– Final Report ( http://vista.cira.colostate.edu/improve/Publications/Gra yLit/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. For est 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

provid ed alternative calculations using the original IMPROV E 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 deciv iews 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 8 th 

### highest day, visibility impacts expressed a s 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 va lue 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 c oncentrations (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 fa ctors from the Federal Land Manag ers‘ 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 parame ter Pollutant Concentration (μg/m 3 )
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 fo r 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. Fore st 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, C olorado ( http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf )

### 20

Table 4

- 4. Natural Background Concentrations used by EP A 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 Wild erness 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/CALPU FF 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 N MED. 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 model ing 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‖ (―n o 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 sub domain 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 reli ed 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 Pro tocol 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 Cen ter 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/d ocuments/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 f rom 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 th at 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 i s 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
Work shop, May 16, 2007. ( http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/archive/200 7/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_as sessment_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 indica ted 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 pa rameters 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 sensi ble 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 u sed 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 upp er 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 observe d 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
k m and 200 k m, 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 perfor med for each unit separately. Pollution concentration predictions were then summed together to evaluate the facility

wide impacts before the post

- processing steps described here. First, POSTUTIL considers ammonia background concentrations, temperature, a nd 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 equati on.

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

a nd 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 NMED 31 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 recommendati on

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 S JGS Best Available Retrofit Technolog y 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 H 2 

### SO 4 

### 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 CA LPOST 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 simil ar 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 l ikely 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 98 th 

### p ercentile of daily maximum dv for 2001, 2002, and 2003 ) at Sixteen Class I Areas

Class I Area Distance

to SJ GS (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
N ational 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 2.9 6

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 (NH 3 

### ) and sulfuric acid (H 2 

### SO 4 

### ).

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

- rea cted ammonia) from its use in SCR or SNCR to control NO
x 

### emissions.

### 28

4.3.3 Sulfuric Acid

Sulfuric acid (H 2 

### SO 4 

### ) is formed from coal

- fired power plants from the oxidation of sulfur dioxide (SO 2 

### ) to sulfur trioxide (SO 3 

### ) and the subsequent reaction of SO 3 

### with water vapor (SO 3 

### + H 2 

### O = H 2 

### SO 4 

### ). 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 H 2 

### SO 4 

### as inorganic

pa rticulate sulfate.

We will address these two additional pollutants when estimating the impact of various control technologies on visibility improvement: ammonia (NH 3 

### ) and sulfuric acid (H 2 

### SO 4 

### ) in greater detail in the next Chapters.

### 29 

## Chapter 5: B&V Approach

5.1 B& V M ODELING 

### I NPUTS



### 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
H 2 

### SO 4



### . 32 

### Sulfuric acid due to SCR operation was calculated assuming 1% conversion of
SO 2 

### to SO 3 

### based on the economizer outlet emission of SO 2 

### . 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 H 2 

### SO 4 

### Emission Estimates

Unit 1 Unit 2 Unit 3 Unit 4 Controlled SO3 emissions (lb/hr) from boiler 33 40.5 40.3 62.9 61.7
Economizer SO 2 emissions (lb/hr) 34 5,884 5,854 9,1 40 8,967
Conversion of SO 2 to SO 3 due to SCR (%) assumed by B&V

based on economizer SO 2 emissions 35 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. Th e 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 v alues 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 Spe ciation 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 S orbent 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 Model ing 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 determin ation 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 imp roving 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 occ ur 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 ot her 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 SO 3 

### from inherent controls, and SCR with sorbent injection. 40 

### B&V assumed an SCR controlled emission rate of 0.07 lb/MMBtu for NOx. SO 2 

### and total filterable particulate (PM10) emissions were held at the post

- consent decree rates of 0.18 lb/MMBtu for SO 2 

### and 0.015 lb/MMBtu for PM10 for visibility modeling.

38 New Mexico Environment Department, Air Quality Bureau, BART Determination, Pu blic 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_Appen dixO

- 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 Generati ng 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 I nputs (lb/hr)

Unit 1 Unit 2 Unit 3 Unit 4 B&V Baseline (post

- consent decree controls)
SO 2 667.26 663.84 1036.44 1016.82
SO 4 40.5 40.3 62.9 61.7
NO
x 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
SO 2 667.26 663.84 1036.44 1016.82
SO 4 114.2 113.6 177.3 174
NO
x 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
SO 2 667.26 663.84 1036.44 1016.82
SO 4 62.61 62.29 97.22 95.39
NO
x 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 SC R w/ sorbent injection control scenario
SO 2 667.26 663.84 1036.44 1016.82
SO 4 16.09 16.01 24.99 24.52
NO
x 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., PM 8.0 

### , PM 4.25 

### , PM 1.88 

### , PM 1.25 

### , PM 0.813 

### , and PM 0.625 

### ). 41 

### These modeled species ar e grouped in POSTUTIL as to represent the appropriate visibility pollutants (e.g., PMcourse = PM 8.0 

### + PM 4.25 

### and PMfine = PM 1.88 

### + PM 1.25 

### + PM 0.813 

### + PM 0.625 

### ) and
are then scaled with the emission rates derived from the NPS spreadsheets. EC and SOA

are de rived from the PM 1.88 

### species and scaled with the emission rates derived from the NPS spreadsheets.

41 Dry Bottom PC w FGD+FF PM Spec iation 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 t he 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 H 2 

### SO 4 

### resulted in different H 2 

### SO 4 

### emi ssion rate inputs for visibility modeling.

5.2 R ESULTS OF 

### NMED VISIBILITY MODELING



### NMED presented various control scenarios‘ visibility improvement s in terms of the 98 th 

### percentile (8 th 

### highest) of the daily maximum delta deciviews from CALPUFF for each
C lass I area, averaged over 2001

– 2003 and the maximum of the 98 th 

### 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 bu t 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 98 th 

### percentile of daily maxima from 2001

– 2003

, as modeled by NMED

. NMED modelin g 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 fo r 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 l ow 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 (SO 3 

### ) 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 SO 2 

### to SO 3 

### 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 In ventory (TRI). 42



### Theses points are discussed further in the following chapter.

42 TRI data is available at http://www.epa.gov/tri/tr idata/current_data/index.html . 2009 data is considered preliminary.

### 33

Table 5

- 4. NMED Modeling Results

-- Impacts of SJGS on Visibility ( average of 98 th 

### p ercentile 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 (post

consent decree) SCR 43 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 Cap itol 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 Snowmas s 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_Respo nse_with_Attachments_0331.pdf )

44 PNM San Juan Generating Station Review of Inherent SO3 Removal Scenarios and Sorbent Injection for SO3 Removal, Black and Vea tch, 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 M ODELING 

### I NPUTS



### 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 note d the potential for greater control at rates as low as 0.03 lbs/ MMBtu

. NOx continuous emission monitor (CEM) d ata from the EPA C lean Air Markets Division show that SCR retrofits routinely result in 90% removal efficiency

. We have concluded that a NOx emi ssion 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 ou r 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 SO 2 

### Emission Rate

As previously discussed, there are no federally enforceable limits that restrict the SJGS‘s
SO 2 

### 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 Per mit No. 0063

- M6) on April 22, 2008 to incorporate some of the conditions from the consent decree that include a 90% reduction in SO 2 

### 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 th e 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 m odification that also includes the consent decree limits on NOx and SO 2 

### 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 SO 2

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/ MMB tu 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 seven

day block average.

48 New Mexico Environment Department Air Quality Bureau N SR 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 towa rds 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 v isibility 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 t hat a n 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 SO 2 

### 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 a mount of sulfuric acid produced during combustion, the rate of SO 2 

### to SO 3 

### 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 emissio ns from power plants were calculated by NPS by estimating the amount of H 2 

### SO 4 

### produced and the amount of H 2 

### SO 4 

### 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 SO 2 

### , the amount of SO 2 

### oxidized to SO 3 

### , and the amount of H 2 

### SO 4 

### lost to (or mitigated by) the air preheater and applicable control equipment, such as baghouses, and FGDs. Baseline and post

- control estimates of H 2 

### SO 4 

### 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
Re gional Haze State Implementation Plan August 17, 2010 ( http://www.nmenv.state.nm.us/aqb/reghaz/documents/FWS

- NPS_Comments

NewMexicoRegionalHazeSIP

- 17AUG2010.pdf )

51 Don Shepherd to Michael Feldman, EPA Region 6 (electronic mail) dated Nov. 1, 2010

– revis ed 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 (H 2 

### SO 4 

### ) Emissions Calculation s by
NPS. 53

EPRI Parameter EPA (revised NPS calculations) Fuel Impact Factor (SO 3 formation from

combustion) 0.00111

Coal sulfur content (%) 0.77
Coal S conversion to SO 2 0.875
Conversion of SO 2 to SO 3 from SCR catalyst

(%) 0.5

Penetration factorthrough Scrubber 54 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 SO 2 

### is estimated for three different coal types. Hardman et al. (1998) report sulfur conversion to SO 2 

### (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 c alculations relied on the value of 0.875. 55



### For coal

- fired power plants without SCR, SO 3 

### is only formed during the combustion process. The amount of SO 2 

### that is oxidized to SO 3 

### during combustion depends on coal type and the type of boiler. SO 3 

### reacts rapidly with water to form sulfuric acid. Measurements of SO 3 

### 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 SO 3 

### produ ction factor from Western bituminous coal from dry bottom boilers to be 0.00111, or 0.111% of SO 2 

### production, and NPS used this value. 56



### For coal

- fired power plants with SCR, SO 3 

### is also formed as a result of oxidation of SO 2 

### to SO 3 

### on the SCR catalyst. N MED assumed a 1% conversion of SO 2 

### to SO 3 

### across the SCR catalyst layers, whereas NPS used 0.5% conversion efficiency because low conversion catalysts are commercially available to specifically reduce H 2 

### SO 4 

### 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 Powe r 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. Althoug h 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, H 2 

### SO 4 

### rem oval 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 availab le 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 eigh t units show a range of percent removal from 0

– 69%. Before calculating the average percent removal of H 2 

### SO 4 

### observed from low

- sulfur Eastern bituminous coal, EPRI 2008 and Harrison 2005 excluded the 0% removal value because ―the data point showing 0% re moval at approximately 600 ppm SO 2 

### 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 c oals with acidic ash (e.g., bituminous) may consider adopting the low sulfur, eastern bituminous value of 0.49 for the H 2 

### SO 4 

### penetration (1

- removal), which is equivalent to 51% removal. NPS used the 0.49 value for the air preheater penetration factor sug gested for coal with low alkalinity ash.

Downstream of the air preheater, H 2 

### SO 4 

### is also reduced by PM and SO 2 

### control equipment. All SJGS Units are equipped with wet limestone scrubbers and baghouses for
SO 2 

### and PM control. NPS used the EPRI

- recommende d 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 (SO 3 

### ) in the flue gas. We hav e 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 methodo logy 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 SO 2 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 a bout 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 es timates 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.

Tab le 6

- 2. SJGS Facility

- Wide Sulfuric Acid Emission Estimates Reported emissions 59 Hourly emissions 60

TRI 2007 7 2 000 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

--- 0.8 7 lb/hr



### 6.1.3.3 Sulfuric Acid Emission Limit

EPA believe s that these estimates of H 2 

### SO 4 

### emissions are appropriate based on the use of low reactivity catalyst that will reduce the rate of SO 2 

### to SO 3 

### conversion. To e nsure these
l evels are met, EPA is proposing that emissions of H 2 

### SO 4 

### be limited to 1.06 x 10 - 4



### lb/MMBtu. Th is 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 co nversion 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 . T herefore, 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 sulf uric acid emissions by about 182 % over baseline levels. 61 

### Using this 182 % increase factor we esti mate an upper range of sulfuric acid mist emissions of 7.87 x10 - 4 

### lb/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 emiss ions over baseline levels of 182 % increase (373.99/2 05.4 ≈ 1.8 2)

### 39

same rem oval factors will apply to any additional H 2 

### SO 4 

### 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 - 5 

### lb/MMBtu for H 2 

### SO 4 

### across the three units. 62 

### This measured rate is lower than that estimated by the EPRI method of 2.71x10 - 4



### l b/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 efficie ncy 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 v ery little monitored ammonia data is available, we used t he IWAQM Phase 2 document which recommend s a default ammonia background value of 1 p art per billion (p pb ) 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 ambien t 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 historic ally 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 i n 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 rese arched 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 dis cusses 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, No vember 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 leve ls. 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 emis sions relative to SO 2 

### 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 differe nce 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 le vel 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 h ave 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 v ariety 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 em issions); 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

FProtoco l

‐ 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 Mo nitoring, ―Baseline ambient gaseous ammonia concentrations in the Four Corners area and eastern Oklahoma, USA‖, Sather, et. al.; September 25 th 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 reaso nable 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 98 th 

### perc entile 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 certai nly 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 mor e 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 m ore 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 ann ual 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 site s, 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 s ubset 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 collecte d 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 dow nwind 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 app ropriate 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 bel ieve 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 sli p 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 SO 2 

### at the SJGS units. .

6.1.5 EPA Modeling Scenarios

EPA remodeled the visibility impacts of SJGS using revised emi ssion 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 o f 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 SO 2 

### emissions lowered to the BART presumptive limit 0.15 lb SO 2 

### /MMBtu that was assumed by the WRAP states for regional visibility modeling to achieve reasonable progress towards

natur al 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 impairme nt 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) SO 2 

### 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 Uni t 4 EPA Baseline (post

- consent decree controls)
SO 2 667.26 663.84 1036.44 1016.82
SO 4 0.17 0.17 0.27 0.26
NO
x 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 Ad justed Baseline
SO 2 556.05 553.2 863.7 847.35
SO 4 0.17 0.17 0.27 0.26
NO
x 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
SO 2 667.26 663.84 1036.44 1016.82 EPA SCR control scenario
SO 2 556.05 553.2 863.7 847.35
SO 4 0.39 0.39 0.61 0.60
NO
x 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 g ram per second nominal emission rates in CALPUFF for the specific size ranges presented in the NPS speciation spreadsheets (i.e., PM 8.0 

### , PM 4.25 

### , PM 1.88 

### , PM 1.25 

### , PM 0.813 

### , and PM 0.625 

### ). These modeled species are grouped in POSTUTIL as to represent the appro priate visibility pollutants (e.g.,
PMcourse = PM 8.0 

### + PM 4.25 

### and PMfine = PM 1.88 

### + PM 1.25 

### + PM 0.813 

### + PM 0.625 

### ) and are then scaled with the emission rates derived from the NPS spreadsheets. EC and SOA are derived from the PM 1.88 

### species and scaled with t he emission rates derived from the NPS spreadsheets.

6.2 EPA V ISIBILITY 

### M ODELING 

### I MPACTS 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 improvemen ts 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 t o 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) Baselin e

EPA modeled a revised baseline scenario to incorporate the proposed lower SO 2 

### emission rate of 0.15 lb/MMBtu rather than the 0.18 lb/MMBtu included in the original post

consent decree baseline modeled by NMED. The purpose of this was to separate any vi sibility benefit from lowering the SO 2 

### emission rate from the benefit received from the operation of the SCR.

Table 6

- 4 shows the maximum of the 98 th 

### 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 SO 2 

### emission rate. Table 6

- 5 summarizes the average and maximum results of v isibility 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 98 th 

### 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 (post

consent 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 1.4 1 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 1.3 2 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 25 8 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 98 th 

### 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, i ncluding 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 indiv idual 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 visibi lity 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 concentra tion 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 applyi ng 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 improvem ent 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 expect ed at individual Class I areas from the installation of SCR.

### 47

Table 6

- 6. EPA Modeling Results

– Impacts of SJGS on Visibility ( maximum of 98 th 

### Percentile of daily maximum dv of 2001, 2002, and 2003 ) at Sixteen Class I Areas (1ppb background ammonia conc entration, 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 Canyo n 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 improvemen t

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, Met hod 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, Meth od 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 D unes 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

We minuche 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 222PNM San Juan Generating Station | BEST AVAILABLE RETRO FIT TECHNOLOGY ANALY SIS

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