Prepared for: Prepared by: Arizona Public Service Company AECOM Camarillo, CA 60221977 Updated April 2014 

## Environment



# Application for Prevention of Significant Deterioration Permit for the Four Corners Power Plant SCR Retrofit ProjectPrepared for: Prepared by: Arizona Public Service Company AECOM Camarillo, CA 60221977 Updated April 2014 

## Environment



# Application for Prevention of Significant Deterioration Permit for the Four Corners Power Plant SCR Retrofit Project

Submitted to:

U.S. Environmental Prot ection Agency Region 9

75 Hawthorne Street
San Francisco, CA 94105

______________________________________________________________ Prepared By Robert R. Hall

______________________________________________________________ Reviewed By Sara J. Head, QEP, and Ellen DietrichAECOM Environment

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# Contents

1.0 Introduction ...................................................................................................................... 1-1

1.1 Application Overview .......................................................................................................... . 1-1

1.2 Environmental Impac t Review ............................................................................................. 1-1

1.3 Document Ov erview ............................................................................................................ 1-2

1.4 Applicant In formation ......................................................................................................... .. 1-3

1.5 Responsible Official Certification ......................................................................................... 1-4



## 2.0 Project Description ......................................................................................................... 2 -1

2.1 Project Ov erview .............................................................................................................. .... 2-1

2.2 Process Desc ripti ons .......................................................................................................... . 2-1
2.2.1 SCR System .......................................................................................................... 2-1
2.2.2 Dry Sorbent Inject ion System ............................................................................... 2-5

2.3 Constructi on Schedul e......................................................................................................... 2-8

2.4 Operating Schedul e ............................................................................................................ . 2-8

2.5 Standard Industrial Cla ssification C ode .............................................................................. 2-8



## 3.0 Regulatory Setting .......................................................................................................... 3 -1

3.1 PSD Permitting Authority ..................................................................................................... 3-1

3.2 National Ambient Air Quality Standards .............................................................................. 3-1

3.3 Major New Source Review Applicability .............................................................................. 3-3

3.4 PSD Require ment s .............................................................................................................. 3-6
3.4.1 Best Available Control Te chnology Requir ements .............................................. 3-6
3.4.2 Air Quality Impact Analysis ................................................................................... 3-7
3.4.3 Source Impact Analysis ........................................................................................ 3-7
3.4.4 Additional Impact Analyses .................................................................................. 3-9
3.4.5 PSD Class I Area Analysis ................................................................................... 3-9

3.5 Tribal New Source Review ................................................................................................ 3-10

3.6 Greenhouse Gas (GHG) Tailo ring Rule ............................................................................ 3-11

3.7 Title V – Major Source Operating Pe rmit .......................................................................... 3-11

3.8 Compliance Assurance Monitoring ................................................................................... 3-12

3.9 Regional Haze Rule and Guidelines for Best Available Retrofit Technology Determinat ions ................................................................................................................ ... 3-12AECOM Environment

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### 3.10 Other Applicable or Potentially Applicable Regul ations ................................................... 3-13
3.10.1 New Source Performance St andards – 40 CF R 60 .......................................... 3-13
3.10.2 National Emissions Standards for Hazardous Air Pollutants – 40 CFR 63 ...... 3-14
3.10.3 Clean Air Interstate Rule (CAIR) / Cross-State Air Pollution Rule (CSAPR) .... 3-15
3.10.4 Acid Rain Prov isions ........................................................................................... 3-15
3.10.5 Risk Management Program ................................................................................ 3-15



## 4.0 Control Technology Review ........................................................................................... 4-1

4.1 Technical Approac h ............................................................................................................ . 4-1
4.1.1 Best Available Control Te chnology Defini tion ...................................................... 4-1
4.1.2 Previous BACT Dete rminations ........................................................................... 4-2

4.2 Four Corners SCR Retrofit Proj ect BACT Deter minations ................................................. 4-3
4.2.1 STEP 1 – Available Sulfuric Acid Mis t Emission Control Al ternatives ................ 4-3
4.2.2 STEP 2 – Eliminate Technically Infeasible Options ............................................ 4-4
4.2.3 STEP 3 – Rank Remaining Technologi es by Control Ef fectivene ss .................. 4-9
4.2.4 STEP 4 – Evaluate Most Effective Co ntrols and Document Result s ................ 4-10
4.2.5 STEP 5 – Select the Best Ava ilable Control Te chnology .................................. 4-15



## 5.0 Project Emission Summary ........................................................................................... 5-1

5.1 Coal Fired Boilers ............................................................................................................ .... 5-1
5.1.1 Baseline Actual Emissions ................................................................................... 5-1
5.1.2 Future Project ed Emissi ons.................................................................................. 5-1

5.2 New Emission Sources ........................................................................................................ 5 -2

5.3 PSD Applic ability ............................................................................................................. ..... 5-2



## 6.0 Endangered Species Act Impact Analysis ................................................................... 6-1

7.0 References .................................................................................................................... ... 7-1AECOM Environment

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# List of Appendices

Appendix A Emission Calculations

Appendix B RBLC Clearinghouse Data

Appendix C Units 4 & 5 – Indirect Heat Exchanger H 2 

### SO 4 

### CAM Plan

Appendix D H 2 

### SO 4 

### Source Test Report



# List of Figures

Figure 1-1 Four Corners Power Pl ant Locati on .................................................................................. 1-5
Figure 2-1 SCR System Simplified Sc hematic Draw ing ..................................................................... 2-2
Figure 2-2 Typical Dry Sorbent Injectio n Process Schem atic ............................................................ 2-6
Figure 2-3 Location of Proposed Reagent Silos and Delivery Truck Routes .................................... 2-7
Figure 4-1 FCPP Air Pollution Control Equipm ent Block Flow Diagram .......................................... 4-17
Figure 6-1 Deposition Area for th e ESA Analys is .............................................................................. 6-2



# List of Tables

Table 3-1 National Ambient Air Q uality Standar ds ............................................................................ 3-2

Table 3-2 PSD Significant Emissi ons Threshol ds ............................................................................. 3-4

Table 3-3 Four Corners Unit 4 and Unit 5 SCR Re trofit Project PSD Applicability .......................... 3-5

Table 3-4 Allowable PSD Increments and Significant Impact Levels (μg/m 3 

### ) .................................. 3-8

Table 3-5 Comparison of Project Emissions to Tribal Minor NSR Thresholds ............................... 3-10

Table 4-1 Ranking of Technically Feasible H 2 

### SO 4 

### Mist Control Te chnologies ................................ 4-9

Table 4-2 Detailed Overall H 2 

### SO 4 

### Mist Emission Co ntrol Da ta....................................................... 4-10

Table 4-3 Wet ESP Capital Cost for One Unit ................................................................................ 4-12

Table 4-4 Wet ESP Annual Costs and Cost Effect iveness ............................................................. 4-13

Table 5-1 Baseline Emission Summary for Units 4 and 5 ................................................................. 5-3

Table 5-1 Projected Future Emission Calcul ation for Units 4 and 5 ................................................. 5-4AECOM Environment

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# 1.0 Introduction

1.1 Application Overview
Arizona Public Service Company (APS) operates the Four Corners Power Plant (FCPP), a privately owned and operated coal-fired power plant located on the Navajo Nation, about 25 miles west of Farmington, New Mexico (see Figure 1-1). The facility consists of five power generating units, with a total capacity of approximately 2,100 megawatts (MW). On August 24, 2012, the United States Environmental Protection Agency (EPA) promulgated a source-specific Federal Implementation Plan (FIP) requiring the FCPP to achieve emissions r eductions required by the Clean Air Act's (CAA) Best Available Retrofit Technology (BART) provision (77 FR 51620). In order to comply with EPA’s sourcespecific FIP, APS retired Units 1, 2, and 3 on Januar y 2, 2014. Units 4 and 5, with a total capacity of approximately 1,500 MW, will continue to operate with NOx emissions limited to 0.098 lb/MMBtu, based on a rolling average of 30 su ccessive boiler operating days.

Construction of the Selective Catalytic Reduction (SCR) system (Project or SCR Retrofit Project) to reduce NOx emissions to the required limit is expec ted to start in mid-2015 with operation planned by July 2018. For particulate matter (PM) emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBtu and has retained the existing 20 percent opacity limit in the facility’s current permit. EPA is also requiring FCPP to comply with a 20 percent opacity limit on its coal and material handling operations.

This Prevention of Significant Deterioration (PSD) permit applicat ion is being submitted to address emissions increases related to the installation of SCR systems at FCPP, for the FCPP SCR Retrofit Project. The SCR Retrofit Project requires a PS D permit due to significant emission increases for sulfuric acid (H 2 

### SO 4 

### ) mist. Although this Project is located on the Navajo Nation, the Navajo Nation does not have PSD authority, and hence this application is being submit ted to the EPA in Region 9.


## 1.2 Environmental Impact Review
In 2013, APS executed a lease amendment (Lease Amendment No. 3) with the Navajo Nation to extend the life of the FCPP an additional 25 years, from 2016 to 2041. The proposed FCPP lease amendment and rights-of-way (ROWs) renewals are expected to require certain federal actions, including:

 Approval from Bureau of Indian Affairs (BIA) of Lease Am endment No. 3 for the FCPP site, which has been signed by the Navajo Nation after Navajo Nation Council approval, pursuant to 25 United States Code (USC) § 415.

 Issuance by BIA of renewed ROWs for existing facilities, pursuant to 25 USC § 323, for the FCPP including all associated switchyards and anc illary facilities, a 500 kilovolt (kV) transmission line and the Moenkopi Switchyard, and two 345-kV transmission lines. All facilities except 34 miles of the 500-kV transmission line, which crosses Hopi tribal land, are located on the Navajo Nation.AECOM Environment

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### As connected actions related to the proposed FCPP lease amendment approval and renewed ROW grant actions, BHP Navajo Coal Company (BNCC) pr oposes to develop a new permit area, called the Pinabete Permit, which is located adjacent to the FCPP on the Navajo Nation. The new Pinabete Permit area would, in conjunction with the mining of any reserves remaining within the existing Navajo Mine Permit area (Federal SMCRA Permit NM0003F), suppl y low-sulfur coal to t he FCPP at a rate of approximately 5.8 million tons per year. Development of the Pinabete Permit area and associated coal reserves would use surface mining methods and, based on current projected customer needs, would supply coal to FCPP for up to 25 years beginning in 2016.

In accordance with the National Environmental Policy Act (NEPA), 42 U.S.C. 4231–4347; the Council on Environmental Quality’s (CEQ) regulations for implementing NEPA, 40 CFR Parts 1500 through 1508; and the Department of the Interior’s (DOI) NE PA regulations, 43 CFR Part 46, the Office of Surface Mining Reclamation and Enforcement (OSM ), Western Region (WR), Denver, Colorado, is preparing an Environmental Impact Statement (EIS) to analyze the effects of the related proposed federal undertakings. The Draft EIS was issued in March 2014 (Office of Surface Mining Reclamation and Enforcement, 2014). The Record of Decision for the EIS is scheduled for the first quarter of 2015.

APS’s proposed action analyzed in the EIS includes ceas ing operations of Units 1, 2 and 3, installing SCR systems on the two remaining operating units (4 and 5), and continuing operations of the transmission lines and ancillary facilities. The EIS also analyzes the effects of full implementation of the proposed Pinabete Permit and continued operatio ns of transmission lines associated with the FCPP that are operated by Public Service Company of New Mexico (PNM).

OSM and the proponents are engaging in Section 7 consultation under the Endangered Species Act (ESA) concurrent with the EIS process. One of the many parts of the Section 7 process for this Project includes the preparation of an ecological risk assessment (ERA) to evaluate the potential effects to federally listed species and their habitats from FCPP stack emissions that are deposited on the landscape. Increased emissions of H 2 

### SO 4 

### mist predicted to occur once SCRs are installed is part of the ERA for species identified for this analys is. The ERA for this Project has been completed and submitted to OSM in October 2013.

Associated with the EIS process, OS M is leading the effort to comply with Section 106 of the National Historic Preservation Act (NHPA), which requires th at the lead federal agency take into account the effects of its undertakings on historic properties. Because the Section 106 process coincides with the EIS process, public involvement for Section 106 c oordination will be conc urrent with the public comment periods for the EIS. There are no known elig ible historic buildings or other structures that would be affected by the installation of SCR Syst ems on Units 4 and 5, based on existing available information. APS is working with OSM and the approp riate historic preservation officers to develop a Programmatic Agreement that will establish a formal process for fu ture consultation and compliance, and to resolve how to address potential adverse effect s on eligible historic properties as appropriate.



## 1.3 Document Overview
This PSD application addresses the permitting requi rements of the federally mandated program for PSD review (40 CFR 52.21) for a major modification to an existing major source. Section 2 provides an overview of the proposed Project and the processe s covered by this PSD application. Section 3 discusses the regulatory setting for the Project. Se ction 4 presents the emissions anticipated from theAECOM Environment

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### operation of the facility. Secti on 5 provides the control technology evaluation for those pollutants subject to PSD review. Section 6 presents a discussion of the potential impacts to endandered species. Finally, Section 7 includes the regulatory and technical citations used in the document.

Attached to this application are several appendices as listed below:

 Appendix A – Emission Calculations

 Appendix B – EPA RACT/BAC T/LAER Clearinghouse Data

 Appendix C – Units 4 & 5 – Indirect Heat Exchanger – H 2 

### SO 4 

### CAM Plan

 Appendix D – H 2 

### SO 4 

### Source Test Report



## 1.4 Applicant Information
Listed below are the applicant's primary points of contact and the address and phone number where they can be reached.

Name: Arizona Public Service Company Four Corners Electric Power Station

Address: PO Box 35 Fruitland, NM 87416-0355

Location: End of San Juan County Road 6675 Fruitland, NM

Contacts: David C. Bloomfield, Plant Manager APS (505) 598-8405 david.bloomfield@aps.com

Mark Hajduk, Environmental Contact APS PO Box 53999, MS 9303, Phoenix, AZ 85072-3999 400 N 5 th 

### Street, MS 9303, Phoenix, AZ 85004 (602) 250-3394 Mark.Hajduk@aps.com

In addition to the APS contacts provided above, an environmental consultant familiar with the preparation of this application who can be contacted related to quest ions on this application includes:

Sara Head, Permitting Lead AECOM (805) 233-3995 sara.head@aecom.comAECOM Environment

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### Figure 1-1 Four Corners Power Plant LocationAECOM Environment

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# 2.0 Project Description

2.1 Project Overview
This FCPP SCR Retrofit Project involves the installa tion of emissions control technology at an existing coal-fired power plant. In order to limit NOx emissions from Units 4 and 5, APS is planning to install SCR on both units. The use of SCR tends to oxidize some SO 2 

### to SO 3 

### which results in increased sulfuric acid (H 2 

### SO 4 

### ) mist, PM 10 

### , and PM 2.5 

### emissions. In order to minimize H 2 

### SO 4 

### , PM 10 

### , and PM 2.5 

### emission increases, APS proposes to install a dry so rbent injection (DSI) system using lime as the sorbent. The Project will be subject to PSD rules only for H 2 

### SO 4 

### . Emission reductions from the shutdown of Units 1, 2, and 3 will allow t he Project to net out of PSD review for PM 10 

### and PM 2.5 

### emissions.

New and affected emission sources associat ed with the Project are listed below:

 Units 1, 2, and 3 were permanently retired on January 2, 2014;

 Units 4 and 5 will be modified by adding new emission controls. SCR will be added to control NOx emissions and dry sorbent injection will be added to control H 2 

### SO 4 

### emissions;

 Truck traffic will increase due to the delivery of reagent for the dry sorbent injection system resulting in increased fugitive em issions from paved plant roads;

 Truck traffic will increase due to the delive ry of urea pellets, 29% aqueous ammonia, or anhydrous ammonia for the SCR system resulting in increased fugitive emissions from paved plant roads;

 A new pneumatic dry sorbent truck unloading sy stem and silo will be installed; and

 A new pneumatic urea pellet tru ck unloading system and silo may be installed if this reagent option is selected for the SCR system or a new ammonia truck unloading station and storage tank will be installed if either the aqueous or anhydrous ammonia option is selected for the SCR system.

These Project components are described in more deta il below. Note, emission reductions associated with decreased truck traffic and material handling relat ed to the shutdown of Units 1, 2, and 3 have not been quantified.



## 2.2 Process Descriptions
2.2.1 SCR System
2.2.1.1 SCR Equipment Description SCR systems are the most widely used post-combustion control tech nology for achieving significant reductions in NOx emissions. In SCR systems, vaporized ammonia injected into the flue gas stream acts as a reducing agent, achieving low NOx em ission depending upon the amount of catalyst. The NOx and ammonia reagent react to form nitrogen and water vapor. The reaction mechanisms areAECOM Environment

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### very efficient, with a reagent stoichiometry of appr oximately 1.05 (on a NOx reduction basis) with low ammonia slip (unreacted ammonia emissions).

SCR converts nitrogen oxides to nitrogen and water by the following reactions:

4NO + 4NH 3 

### +O 2 

###  4N 2 

### + 6H 2 

### O (1)

6NO + 4NH 3 

###  5N 2 

### + 6H 2 

### O (2)

2NO 2 

### + 4NH 3 

### + O 2 

###  3N 2 

### + 6H 2 

### O (3)

6NO 2 

### + 8NH 3 

###  7N 2 

### + 12H 2 

### O (4)

NO + NO 2 

### + 2NH 3 

###  2N 2 

### + 3H 2 

### O (5)

The reactions take place on the surface of a catalyst . The function of the catalyst is to effectively lower the activation energy of the NOX deco mposition reaction. Vanadium pentoxide (V 2 

### O 5 

### ) is the main active ingredient in an SCR catalyst. It is also responsible for the unwanted conversion of SO 2 

### to SO 3 

### . Thus, efforts to reduce the SO 2 

### to SO 3 

### conversion can counteract efforts to increase NOx reduction. A simplified schematic drawing of a typical SCR system is illustrated in Figure 2-1

.

Figure 2-1 SCR System Simplified Schematic Drawing (Courtesy of the Babcock and Wilcox Company)AECOM Environment

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### The SCR reactor is the housing for the catalyst. The reactor is basically a widened section of duct work modified by the addition of gas flow distribu tion devices, catalyst, catalyst support structures, access doors, and soot blowers. An ammonia injectio n grid is located upstream of the SCR reactor, and the system can be designed with or without a flue gas bypass. The S CR reactor is typically elevated above and behind the air preheater and upstr eam of emissions control equipment; gas flow direction through the reactor is typically vertically dow nward for coal fired applicat ions. In a “high dust” SCR arrangement, the reactor is located between the outlet of the economizer and the inlet of the air preheater. The high dust system is typically the most economical and preferred a rrangement, where physically possible.

The SCR reaction occurs within the temperature rang e of 550° to 850° F; the extremes are highly dependent on the fuel quality. The practical minimu m operating temperature (MOT) is often between 600° and 650°F, depending on chemistry. Units 4 and 5 at Four Corners will likely require an economizer bypass to raise temperatures during star t-ups and allow the SCR systems to come on-line sooner so that they can make the required 30-day ro lling average NOx emission limit. To increase the probability of meeting the 30-day rolling average NOx emission limit, Units 4 and 5 may at times be operated at the Minimum Ammonia Injection Temperature (MAIT). MAIT is typically 50° to 60°F less than the MOT. This operation strategy would allow NOx to be controlled at a lower temperature, but runs the risk of catalyst fouling. The unit must ru n above the MOT for at least twice as long as it operates below the MOT to eliminat e fouling that accumulated. Th ere must be a high probability that the Unit will be able to complete the startup bef ore deciding to operate below the MOT. This could also impair the ability for the air preheater to remove SO 3 

### . The oxidation of SO 2 

### to SO 3 

### could also require moderate air preheater 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 preheater gas outlet temperature or the addition of some flue gas treatment system to remove the SO 3 

### . The ammonia reagent for the SCR systems can be supplied by anhydrous ammonia, aqueous ammonia, or by conversion of urea to ammonia. Si nce the ammonia is vaporized prior to contact with the catalyst, the selection of ammonia type does no t influence the catalyst performance. However, the selection of ammonia type does affect all ot her subsystem components, including reagent storage, vaporization, injection control, and balance-of-pl ant requirements. This permit application addresses all three reagents as APS has not made a fi nal decision on the SCR reagent to be used.

SCR systems have a variety of interfacing syst em requirements to s upport operations. These requirements predominately relate to draft, auxiliary power, soot blowing steam, gas temperature, controls, ductwork, reactor footprint, and air preheat er. The SCR system will affect the boiler draft system. Depending on arrangement and performance requirements, draft losses can range from 6 to 12 inches of water gauge pressure. This can be co mpensated for by modifying the draft system with the addition of ID booster fans. If necessary, ductwork and/or boiler box reinforcement need to be considered. In conjunction with the fan modifica tion, the upgrade of the auxiliary power system might be necessary. Auxiliary power modifications ma y also be necessary for ammonia supply system requirements.AECOM Environment

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### The major impact of the SCR system can be seen at the air preheater, where there are two areas of concern. One concern is the fo rmation and deposition of ammonium bisulfate on the air preheater surface. This accumulation will cause an increase in the pressure drop of the air preheater. The other potential danger for the air preheater is high concentrations of SO 3 

### in the flue gas. If the acid dew point has been increased to more than the exhaust te mperature, a significant amount of acid gases will condense in the air preheater and lead to plugging and corrosion. Several provisions can be made to avoid or correct this situation. Most impor tant is the right composition of the catalyst to minimize SO 2 

### to SO 3 

### conversion rate while maintaining the NOx conversion rate and the proper temperature control of the flue gas entering the reactor.

2.2.1.2 Reagent Type, Storage and Transport Description The reagent for the SCR system has not been finally selected at this time, but will be urea pellets, 29% aqueous ammonia, or anhydrous ammonia. This PSD application provides emissions calculations for all three reagents. Project emissi ons are based on the worst-case emissions from any of these three options. The Draft EIS that was prepared assessed each of these options as alternatives.

Urea Pellet Option If urea pellets are selected for th is Project, the pellets will be received by truck and pneumatically conveyed to a storage silo. The air emission sources associated with the use of urea pellets will be truck travel on paved roads and a vent on the silo which will have a baghouse for emission control. If urea is used, a catalytic system will be us ed to convert urea pellets to ammonia.

Urea delivery trucks will each travel 0.36 miles/round trip on paved roads. Approximately, 874 trucks per year will be required to meet the SCR demand which is expected to be approximately 17,500 tons per year (tpy). Each truck will weigh approx imately 32 tons when filled and 12 tons when empty.

The urea silo will be approximately14 feet diameter and be 30 feet tall, including urea transport equipment beneath the silo.

Aqueous Ammonia Option If 29% aqueous ammonia is selected for this Projec t, it will be received by truck and pumped to a pressurized storage tank. There will not be emi ssions from the pressurized tank. The only air emission sources will be truck travel on paved roads.

Aqueous ammonia delivery trucks will each travel 0.36 mile s/round trip on paved roads. Approximately, 1,504 trucks per year will be r equired to meet the SCR aqueous ammonia demand which is expected to be approximately 33,800 tpy. Each truck will weigh approximately 34.5 tons when filled and 12 tons when empty.

Anhydrous Ammonia Option If anhydrous ammonia is selected for this Proj ect, it will be received by truck and pumped to a pressurized storage tank. There will not be emi ssions from the pressurized tank. The only air emission sources will be truck travel on paved roads.AECOM Environment

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### Aqueous ammonia delivery trucks will each travel 0.36 mile s/round trip on paved roads. Approximately, 643 trucks per y ear will be required to meet the SCR anhydrous ammonia demand which is expected to be approximately 9,970 tpy. Each truck will weigh approx imately 27.5 tons when filled and 12 tons when empty.



## 2.2.2 Dry Sorbent Injection System
2.2.2.1 DSI Equipment Description
Dry sorbent injection, either before or after the air preheater, of hydrated lime or a sodium based reagent (Trona or sodium bicarbonate) has been show n to be effective for acid gas control.

Performance is affected by the follo wing factors (Sewell and Dickerman 2012):

 Reagent Properties

 Reactivity

 Surface area

 Porosity

 Flue Gas properties

 Temperature

 Moisture

 Other competing acid gases

 Injection System Configuration

 Type of particulate control

 In flight residence time

 Reagent mixing

 Injection location

For the FCPP SCR Retrofit Project, the preferred so rbent is hydrated lime. If a sodium based reagent is used, sorbent consumption woul d be high due to reaction with SO 2 

### . APS has a lime-based wet scrubber to control SO 2 

### and does not need DSI for SO 2 

### control. Another reason for not using sodium is the possible occurrence of sodium bisulfate form ation with adverse impacts on the air preheater. Lime will enable APS to continue to sell ash which would not be po ssible with the use of a sodium based reagent. Milling is typically used to maximize th e performance of sodium based sorbents, but is not needed for the lime-based DSI system proposed by APS.

Reactions of hydrated lime and ac id gases are based on gas solid contact. Surface area and pore volume are very important for high performance. Optimized hydrated lime with high surface area and high porosity are available to control H 2 

### SO 4 

### mist emissions.

A typical dry sorbent injection system is shown Figure 2-2

.AECOM Environment

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### Figure 2-2 Typical Dry Sorbent Injection Process Schematic (Source: Dry Sorbent Injection for Acid Gas Control, Babcock & Wilcox Power Generation Group Paper No. PS-451)

2.2.2.2 Reagent Storage and Transport Description The DSI process proposed by APS will use hydrat ed lime. Lime will be received by truck and pneumatically conveyed to a storage silo. The air e mission sources associated with the use of lime will be truck travel on paved roads and a vent on the silo which will have a baghouse for emissions control.

Lime delivery trucks will each trav el 0.85 miles/round trip on paved roads. Approximately, 900 trucks per year delivering 10,800 tpy of hydrated lime are expected to be required. Each truck will weigh approximately 24 tons when filled and 12 tons when empty.

The lime silo will be approximately 14 feet di ameter and 80 feet tall, including lime transport equipment beneath the silo.

Figure 2-3 shows the location of the proposed silo(s) a nd the routes that have been assumed for the delivery trucks.AECOM Environment

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### Figure 2-3 Location of Proposed Reagent Silos and Delivery Truck RoutesAECOM Environment

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## 2.3 Construction Schedule
In order to meet regulatory requirements, constr uction of the FCPP SCR Retrofit Project to reduce NOx emissions must start by mid-2015 with operation planned by July 2018. This PSD permit application is being submitted now to ensure that adequate time is available for final engineering and equipment procurement to be completed in order to meet this schedule.


## 2.4 Operating Schedule
Units 4 and 5 at the FCPP are currently permitted to operate 24 hours per day, 7 days per week. No changes to this permitted operating schedule are proposed as a result of this Project.

APS proposes to operate the SCR systems at all times when Units 4 and 5 are operating except during times when the units are below the optimal tem perature range for SCR system operation, such as during startup of the units.

APS will operate the DSI system at the injection rate needed to meet the permitted emission limits.



## 2.5 Standard Industrial Classification Code
The United States government has devised a method for grouping all business activities according to their participation in the national commerce system. The system is based on clas sifying activities into "major groups" defined by the general character of a business operation. For example, electric gas and sanitary services are defined as a major group. Each major group is given a unique two-digit number for identification. Electr ic Services (Fossil fuel power generation) has been assigned major group code “49”. To provide more detailed identifi cation of a particular operation, an additional twodigit code is appended to the major group code. In the case of Four Corners the applicable Standard Industrial Classification (SIC) code is 4911.

The SIC Code system is widely used although the United States government replaced it with the North American Industrial Classification System (NAICS) in 1997. This system's organization is similar to the SIC codes. Under th is system, this facility would be classified under 221112, Fossil fuel electric power generation.AECOM Environment 3-1

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# 3.0 Regulatory Setting

This section presents a review of the air qualit y regulatory requirements applicable or potentially applicable to the construction and operation of the Project.



## 3.1 PSD Permitting Authority
The Four Corners Power Plant is located on the Navajo Nation within the State of New Mexico. As a federally recognized tribe, the Navajo Nation is considered sovereign and is not subject to the regulations of the State of New Mexico. The Nation is subject to federal (U .S.) regulations as are individual states. While the FCPP is not subject to regulation by the Navajo Nation, it developed a voluntary compliance agreement with the Navajo Nation Environmental Protection Agency (NNEPA), which issued the Title V Operating Permit. The Navajo Nation has been delegated authority under the CAA by the EPA to issue Title V Operating Permit s, but they have not been delegated authority to issue PSD permits. Because PSD authority has no t been delegated, the PSD permit will be issued by EPA. Although the FCPP is located in New Mexico, most of the Navajo Nation is located in Arizona and hence PSD permitting of the Project falls under the jurisdiction of EPA Region 9 (see http://www.epa.gov/region9/air /maps/images/AIR1100040_7gnew.gif).



## 3.2 National Ambient Air Quality Standards
The CAA gives EPA the authority to es tablish the minimum level of air quality that all areas within the U.S. are required to achieve. EPA has developed standards to protect the public health and welfare, through primary and secondary National Ambient Air Quality Standards (NAAQS), respectively. The NAAQS are presented in Table 3-1 . In the context of permitting for the FCPP SCR Retr ofit Project, a compliance demonstration for the NAAQS is required fo r only those regulated pollutants that will have a significant net emissions increase and for which ther e are NAAQS. As shown in Section 3.3, the net changes in emissions resulting from the Project w ill be significant only for sulfuric acid (H 2 

### SO 4 

### ) mist. There are no NAAQS for this pollutant.

The area in which a project is located affects whic h regulatory standards are applicable. One of the basic goals of federal, state, and tribal air quality regulations is to ensure that ambient air quality complies with the NAAQS. To this end, the EPA has classified all regions of the country as “attainment,” “non-attainment,” or “unclassifiable” areas based on their compliance with the ambient air quality standards. An area is cla ssified as in attainment if the am bient air quality concentration for a specific pollutant, as measured by a monitor (o r, as applicable, modeling) using defined reference methods, is below the standard concentration leve l for a specified set of averaging periods.

The Four Corners facility is located in San Juan County, NM which has been designated by the EPA as “attainment” or “unclassifiable” for all crit eria pollutants/NAAQS for which EPA has issued a designation.AECOM Environment 3-2

60221977-460 April 2014 

### Table 3-1 National Ambient Air Quality Standards

Pollutant Primary Standards Secondary Standards

Averaging Time Level Averaging Time Level

Carbon Monoxide (CO) 8-hour (1) 

### 9 ppm (10 μg/m 3 

### ) None 1-hour (1) 

### 35 ppm (40 μg/m 3 

### )
Ozone (O 3 

### ) 8-hour (2) 

### 0.075 ppm (147 μg/m 3 

### ) Same as Primary

Nitrogen Dioxide (NO 2 

### ) Annual (Arithmetic Average) 53 ppb (3) 

### (100 μg/m 3 

### ) Same as Primary

1-hour (4) 

### 100 ppb (188 μg/m 3 

### ) None
Respirable Particulate Matter (PM 10 

### ) 24-hour (5) 

### 150 μg/m 3 

### Same as Primary

Fine Particulate Matter (PM 2.5 

### ) Annual (6) 

### (Arithmetic Average) 12.0 μg/m 3 

### Annual (6) 

### 15.0 μg/m 3



### 24-hour (7) 

### 35 μg/m 3 

### Same as Primary

Sulfur Dioxide (SO 2 

### ) Annual (Arithmetic Average) 0.03 ppm 3-hour (1) 

### 0.5 ppm

24-hour (1) 

### 0.14 ppm
1-hour 75 ppb (8) 

### None

Lead (Pb) Rolling 3-Month Average 0.15 μg/m 3 

### Same as Primary
Calendar Quarter Average 1.5 μg/m 3 

### Same as Primary

1. Not to be exceeded more than once per year. 2. To attain this standard, the 3-year average of the fourth-highest daily maximum 8-hour average ozone concentrations measured at each monitor within an area over each year must not exceed 0.075 ppm (effective 5/27/2008).

3. The official level of the annual NO 2 

### standard is 0.053 ppm, equal to 53 ppb, which is shown here for the purpose of clearer comparison to the 1-hour standard 4. To attain this standard, the 3-year average of the 98th percentile of the daily maximum 1-hour average at each monitor within an area must not exceed 100 ppb (effective January 22, 2010). 5. Not to be exceeded more than once per year on average over 3 years. 6. The form of the annual primary and secondary stand ards is the annual mean, averaged over 3 years.



### 7. To attain this standard, the 3-year average of the 98th percentile of 24-hour concentrations at each populationoriented monitor within an area must not exceed 35 μg/m 3



### . 

### 8. Final rule signed 6/2/2010 and became effective on 8/23/2010. To attain this standard, the 3-year average of the 99th percentile of the daily maximum 1-hour average at each monitor within an area must not exceed 75 ppb.AECOM Environment 3-3

60221977-460 April 2014 

## 3.3 Major New Source Review Applicability
The major New Source Review (NSR) permitting program generally requires a stationary source to obtain a permit and undertake other obligations prior to construction of any project at an industrial facility if the proposed project would result in air emissions above certain annual tonnage threshold levels. The NSR program is comprised of two elements: non-attainment NSR (NNSR) and PSD. The NNSR program may apply to new construction or modifications that result in emission increases of a particular pollutant for which the area is cla ssified as non-attainment. The PSD program applies to significant increases of thos e pollutants for which the area is classified as attainment or unclassifiable. The PSD program only regulates emi ssions from major stationary sources of regulated air pollutants.

Because the FCPP is located in an attainment ar ea, the project must be evaluated to determine whether it involves a major modification that will result in a significant net emissions increase and be subject to PSD permitting requirements. A majo r modification is defined as a physical change or change in the method of operation at a major source that results in both a significant emissions increase and a significant net emissi ons increase of a NSR-regulated pollutant. The PSD significant emission thresholds are identified in Table 3-2

.
The PSD applicability analysis for the Four Cor ners SCR Retrofit Project is summarized in Table 3-3

. Project emission increases will be significant for PM 10 

### , PM 2.5 

### and H 2 

### SO 4 

### . Therefore, a netting analysis that accounts for contemporaneous emission increases and decreases is required for emissions of these pollutants. In accordance with PSD rules, the contemporaneous period begins 5 years prior to the start of construction and ends when the proj ect begins operating. Based on the planned SCR construction start date, which is mid-2015, the contemporaneous period begins in mid-2010. The end of the contemporaneous period is July 2018 when the SCR will be placed in operation.

The creditable emission changes in this time per iod are a new auxiliary boiler and the shutdown of Units 1, 2, and 3. Contemporaneous projects are only shown for the pollutants which are significant due to the Project alone, and the rest of the pollu tants are shown as NA ( not applicable) since the netting step is not required. After netting, Projec t emission increases will be significant only for H 2 

### SO 4 

### mist as shown in Table 3-3 . Additional details on the emissions are presented in Section 5 and Appendix A, and an H 2 

### SO 4 

### Source Test Report is provided in Appendix D.AECOM Environment 3-4

60221977-460 April 2014 

### Table 3-2 PSD Significant Emissions Thresholds

Pollutant Emissions Threshold (tons per year [tpy])
Nitrogen Oxides (NOx) 40
Sulfur Dioxide (SO 2 

### ) 40
Particulate Matter (PM) Filterable 25

PM 10 

### 15

PM 2.5 

### 10
Volatile Organic Compounds (VOCs) 40

CO 100

H 2 

### SO 4 

### 7

Fluorides 3

Total Reduced Sulfur 10
Lead (Pb) 0.60
Greenhouse Gases as Carbon Dioxide equivalents (CO 2 

### e) 75,000
Source: 40 CFR § 52.21.AECOM Environment3-560221977-460April 2014Table 3-3 Four Corners Unit 4 and Unit 5 SCR Retrofit Project PSD ApplicabilityEmission SourceDescriptionNOx(tpy)SO2(tpy)PM(tpy)PM10(tpy)PM2.5(tpy)CO(tpy)VOC(tpy)H2SO4(tpy)Lead(tpy)GHG CO2e(tpy)Unit 4 and 5 Baseline Emissions24,0298,373644.2801.3550.01,4445.78714.10.11510,058,133Unit 4 and 5 Projected FutureEmissions(a)4,7838,403646.51,134.4842.51,4495.808250.60.11510,094,124Unit 4 and Unit 5 Emission Change-19,24730.02.3333.1292.45.20.021236.54.11E-0435,992New DSI Sorbent Truck Traffic0.00.00.0950.0190.0050.00.00.00.00.0SCR Reagent Truck Traffic0.00.00.0870.0170.0040.00.00.00.00.0New DSI Sorbent Material Handling0.00.00.0860.0860.0860.00.00.00.00.0New SCR Reagent Material Handling0.00.00.2140.2140.2140.00.00.00.00.0Total Project Emission Change-19,247 30.0 2.79 333.5 292.8 5.2 0.021 236.5 4.11E-04 35,992Major Source Threshold100 100 100 100 100 100 100 100 100 100,000PSD Threshold for Significant NetEmission Rate40 40 25 15 10 100 40 7 0.6 75,000PSD Netting RequiredNo No No Yes Yes No No Yes No NoContemporaneous Projects -Auxiliary BoilerNANANA0.960.96NANA0.0NANAContemporaneous Projects -Shutdown of Units 1, 2, and 3NANANA-551.5-421.8NANA-3.1NANATotal PSD Emission Change-19,247 30.0 2.79 -217.0 -128.15.2 0.021 233.4 4.11E-04 35,992PSD ApplicableNo No No No No No No Yes No No(a)40 CFR 52.21(b)(41)(ii) In determining projected actual emissions under paragraph (b)(41) the operator shall exclude, in calculating any increase in emissions that results from theparticular project, that portion of the unit's emissions following the project that an existingunit could have accommodated during the consecutive 24-month period used to establish thebaseline actual emissions under paragraph (b)(48) of this section and that are also unrelated to the particular project, including any increased utilization due to product demand growth.See details in Table A-3.NA = Not Applicable (contemporaneous projects only included for those pollutants which required a netting analysis).AECOM Environment 3-6

60221977-460 April 2014 

## 3.4 PSD Requirements
The following sections provide a summary of the appl ication requirements for projects subject to PSD.



## 3.4.1 Best Available Control Technology Requirements
The requirements for Best Available Control Te chnology (BACT) were promulgated within the framework of PSD in the 1977 CAA Amendments. Guidelines for the evaluation of BACT can be found in EPA's Air Pollution Control Cost Manual (2002) and in the New Source Review Workshop Manual (1990). These guidelines were drafted by EP A as a framework or tool for the BACT process. More recently, EPA has published guida nce on BACT for greenhouse gas emissions (http://www.epa.gov/nsr/ghgpermitting.html).

The regulatory definition of BACT for affected sources is:

[A]n emissions limitation (including a vi sible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under 42 U.S.C 7401 to7671q (Clean Air Act), which would be emitted from a proposed major stationary source or major modification which the Ad ministrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for that source or modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel co mbustion techniques for control of such pollutant. ... If the Administrator determines that technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, or operational standard, or combi nation of design, equipment, work practice, or operational standard, may be prescribed instead to satisfy the requirement for the application of best available control technology. [40 CFR §52.21(b)(12)]

Although BACT is typically an emissi on limit, BACT can also be a wo rk practice standard in certain circumstances, typically if an emission limit is no t feasible. One example is the specification of a particular control device in lieu of an emission li mit. BACT limits are det ermined by the “permitting authority” (in this instance EPA Region 9) based on a case-by-case analysis that takes into account site-specific characteristics, including energy, environmental, and economic costs. BACT does not require a redefinition of the proposed source or the use of unproven technology. BACT is not necessarily the lowest emission level ever seen, bu t the lowest level achievable by the applicant for the particular proposed source at issue under worst-case foreseeable conditions.

A BACT limit must be achievable, which means in the context of a BACT assessment, an emission limit that the source can meet on a continual basis over each averaging period for the lifetime of the facility. BACT limits should be set at levels the source can meet under all reasonable foreseeable worst-case conditions. A permitting authority dete rmines what is achievable for a source, exercising its technical judgment on a case-by-case basis.

In addition to being achievable, a control technology must be available to be considered in a BACT determination. To be available, a control technology must be demonstrated in practice. This means that the technology has progressed beyond th e conceptual stage and beyond the research andAECOM Environment 3-7

60221977-460 April 2014 

### development or pilot testing phase. The technol ogy must have been demonstrated successfully on full-scale operations for a sufficient time to be cons idered proven. BACT does not require an applicant to employ technologies that are not proven to work; theoretical, experimental, or developing technologies are not considered available under BACT. Technologies with questionable or dubious reliability are likewise not considered available under BACT, and the applicant is not required to use or consider them. Moreover, vendor sales literature abo ut what a technology might be able to achieve in some limited situation is not relevant to a BACT determination.

Finally, BACT is determined on a pol lutant-by-pollutant basis. When es tablishing BACT for individual pollutants, however, a permitting authority must also consider possible interactions among the pollutants as well as other collateral environmental impacts of particular technologies, such as water usage or the creation of a waste stream. A BACT ana lysis for the Project is presented in Section 4.



## 3.4.2 Air Quality Impact Analysis
In accordance with requirements of 40 CFR 52.21(m) (1)(b), an application must contain an analysis of existing ambient air quality data in the area to be af fected by the proposed project if the project would result in a net significant emissions increase. The analysis of existing air quality can use air monitoring data from either a state-operated or private network, or by a pre-cons truction monitoring program that is specifically designed to collect data in the vicinity of the proposed source. The requirement for onsite air quality monitoring is based on the im pact levels provided in 40 CFR 52.21(i)(5).

The Project is only subject to PSD for H 2 

### SO 4 

### mist emissions. Since there are no ambient air quality standards for this pollutant, an analysis of existing air quality is no t required for the proposed Project.



## 3.4.3 Source Impact Analysis
A source impact analysis must be performed for a proposed project subject to PSD review for each pollutant for which the net increase in emissions ex ceeds the significant emission rate to demonstrate that the project will not cause or contribute to a violation of NAAQS or PSD increment. PSD Increments are established for PM 10 

### , PM 2.5 

### , SO 2 

### , and NO 2 

### for two types of areas, Class I and Class II. Class I areas are those in which the least amount of incremental adverse impact can occur. Class I areas are federally mandated and include specific National Parks, National Forests and Wilderness Areas. Class II areas are all ot her areas not designated as Class I areas. The PSD increments are shown in Table 3-4

. The PSD regulations specifically provide for the us e of atmospheric dispersion modeling in performing impact analyses, estimating baseline and future air quality levels , and determining compliance with NAAQS and allowable PSD increments. Designated EPA models, identified in 40 CFR 51, Appendix W, must normally be used in performing air quality analyses. Guidance for the use and application of dispersion models is presented in the EPA Gu ideline on Air Quality Models (EPA 2005a).

These guidelines allow for a stepped approach, wher e progressively more comprehensive modeling is required depending on the source impacts. The source impact analysis for criteria pollutants may be limited to only the new or modified sources if a net increase in impact due to the new or modified source is below the significant impact le vels (SILs), which are also presented in Table 3-4 . If impacts are greater than the SILs, a cumulative increment al analysis of all PSD consuming sources isAECOM Environment 3-8

60221977-460 April 2014 

### required. The cumulative incremental air quality im pacts to baseline air qualit y from all PSD sources significantly impacting an area are limi ted to the PSD increments listed in Table 3-4

. The proposed Project is subject to PSD only for H 2 

### SO 4 

### . Since there are no PSD increments or significant impact levels for H 2 

### SO 4 

### , these requirements do not apply to the proposed Project, and an increment analysis is not needed.

Table 3-4 Allowable PSD Increments and Significant Impact Levels (μg/m 3 

### )

Pollutant Averaging Time PSD Increments a 

### Significant Impact Levels a



### Class I Class II Class I b 

### Class II

PM 10 

### Annual Arithmetic Mean 4 17 0.2 1

24-hour Maximum 8 30 0.3 5

PM 2.5 

### Annual Arithmetic Mean 1 4 0.06 0.3

24-hour Maximum 2 9 0.07 1.2

SO 2 

### Annual Arithmetic Mean 2 20 0.08 1

24-hour Maximum 5 91 0.2 5

3-hour Maximum 25 512 1 25

1-hour Maximum NA NA NA 7.8c

CO 8-hour Maximum NA NA NA 500

1-hour Maximum NA NA NA 2,000

NO 2 

### Annual Arithmetic Mean 2.5 25 0.1 1

1-hour Maximum NA NA NA 7.5c
NA = Not applicable, i.e., no increment or SIL exists for this pollutant or averaging period a. Short-term increments use the second-highest modeled concentration at any receptor and the Significant Impact Levels use the highest modeled concentration at any receptor. b. Class I SILs for PM2.5 come from the October 20, 2010 Federal Register Final Rule (40 CFR part 51.166). Class I SILs for all other pollutants come from EPA’s proposed values from the July 23, 1996 Federal Register (these values have not yet been promulgated, but they are still routinely used). c. 1-hour SILs for SO 2 

### and NO 2 

### are interim values specifie d by EPA (EPA 2010a and 2010b). Sources: 40CFR50; 40CFR52.21, 40CFR51.165AECOM Environment 3-9

60221977-460 April 2014 

## 3.4.4 Additional Impact Analyses
The additional impact analyses c onsist of three elements:
1. Growth 2. Soils and Vegetation Impacts
3. Visibility Impairment
The growth analysis projects ai r pollutant emissions associated with industrial, commercial, and residential growth in direct support of the new source. Residential growth includes housing for employees entering the region while industrial and commercial growth includes new sources providing goods and services to the new employees and to the proposed source.

The analysis of impacts on soils and vegetation in the source’s impact area compares the total air quality impacts to concentrations known to cause harmful effects to the resident plant and animal species.

The visibility impairment analysis addresses impacts that occur with in the impact area of the proposed new source, beginning with an initial screening for possible impairment and, if warranted, a more indepth analysis with computer modeling.

The Project will not have any ne t additional impacts. Rather than causing growth in the area, the Project will likely cause a decrease in employ ment and support services in the area due to the retirement of FCPP Units 1, 2 and 3, and the associated reduction in support staff for operation of those units. Other than temporary installation of the SCR and ancillary systems, there will be very little change in the operational support needed to run Units 4 and 5. Therefore, APS does not expect increases in air pollution impac ts due to growth of emissi ons related to the Project.

Accounting for the shutdown of Units, 1, 2, and 3, the Project will result in the following actual emission changes:

 NOx – 34,000 tpy decrease

 SO 2 

### – 3,100 tpy decrease

 PM – 650 tpy decrease

 PM 10 

### – 217 tpy decrease

 PM 2.5 

### – 128 tpy decrease

Any effects on soils, vegetation, or visibi lity due to the potential 233 tpy increase in H 2 

### SO 4 

### mist emissions will be more than offset by the actual emission decreases noted above.



## 3.4.5 PSD Class I Area Analysis
In addition to the analysis of PSD Class I Increment compliance, the PSD Class I analysis must also address impacts to special attributes of a Class I area that deterioration of air quality may adversely affect. Such attributes are referred to as Air Qu ality Related Values and are specified by the Federal Land Manager (FLM) of the respective Class I area . These analyses generally include visibility impacts, such as plume blight or contribution to regional haze, and impacts from acid deposition.AECOM Environment 3-10

60221977-460 April 2014 

### These analyses are not required fo r this Project because the emissi ons of all pollutants except H 2 

### SO 4 

### mist will significantly decre ase with the shutdown of Units 1, 2, and 3, and the distance to the nearest Class I area is more than 50 kilometers (km). Based on the FLAG 2010 guidance, this Project screens out of visibility and acidic depositi on analyses due to the emissions decreases.



## 3.5 Tribal New Source Review
EPA approved the Tribal Minor NSR Program on Augu st 31, 2011 (40 CFR Part 49). This program established a preconstruction permitting program for mi nor modifications at ex isting major sources, and establishes a minor source per mitting mechanism for major sources seeking a synthetic minor permit. The Tribal Minor NSR Program is triggered if the potential to emit (PTE) due to a modification is less than the major NSR thresholds, but above the minor NSR thresholds. If the increase in regulated emissions exceeds the minor NSR signifi cance thresholds, the program identifies the requirements for air permitting, including a regulator y analysis, air quality impact analysis, and control equipment review.

With respect to air quality, new and existing industria l sources are classified as either major or minor sources based on their potential to emit air contam inants. The FCPP is considered to be an existing major stationary source as its potential emissions exceed 100 tons per year for several regulated air pollutants.

As discussed above (see Table 3-3 ), this Project triggers major NSR/PSD requirements for H 2 

### SO 4 

### mist. There will be a huge (>19,000 tpy) reduction of NOx emissions related to this Project, and hence NOx emissions are not subject to this permi tting. However, net emission changes of other pollutant emissions which are below the major modifi cation significant emissi ons levels are compared in Table 3-5 below to the Tribal Minor NSR thresholds to determine if any permit modification is needed from the Navajo Nation EPA as a result of this Project. As shown in this table, the remaining pollutants are below the applicable thresholds and hence Tribal Minor NSR does not apply to this Project.

Table 3-5 Comparison of Project Emissions to Tribal Minor NSR Thresholds

Emissions a 

### (tpy)

NOx CO SO 2 

### PM 10 

### PM 2.5 

### VOC

FCPP SCR Retrofit Project -19,247 5.2 30.0 333.5 292.8 0.20

Contemporaneous Projects Auxiliary Boiler NA NA 0.05 0.96 0.96 NA

Unit 1-3 Shutdown NA NA -3,110 -551.5 -421.8 NA

Net Emissions Changes NA NA -3,080 -217.0 -128.1 NA

Tribal Minor NSR Thresholds 10 10 10 5 3 5

Exceeds Threshold No No No No No No

a. See details in Appendix A, Table A-7.AECOM Environment 3-11

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## 3.6 Greenhouse Gas (GHG) Tailoring Rule
On May 13, 2010 EPA issued the greenhouse gas (GHG) permitting rule officially known as “Prevention of Significant Deteri oration and Title V Greenhouse Gas Tailoring Rule” (or in short form, GHG Tailoring Rule) to regulate the six GHG polluta nts codified at 40 CFR Parts 51, 52, 70 and 71. Beginning January 2, 2011, GHGs are regulated Ne w Source Review (NSR) pollutants under the PSD major source permitting program when they are emit ted by new sources or modifications. Beginning July 1, 2011, any source which has a potential to emit GHG in amount greater than 100,000 tpy of carbon dioxide equivalent (CO 2 

### e) will be considered a major source and any modification in amounts greater than 75,000 tpy of CO 2 

### e is required to undergo PSD permitting.

For a facility subject to the GHG Tailoring Rule, the six covered GHG pollutants are:

 Carbon dioxide (CO 2 

### ),

 Nitrous oxide (N 2 

### O),

 Methane (CH 4 

### ),

 Hydrofluorocarbons (HFCs),

 Perfluorocarbons (PFCs), and

 Sulfur hexafluoride (SF 6 

### ).

Only the first three of these six pollutants are co mbustion source related and will be emitted by the boilers at FCPP. The primary GHG of concern for this project is CO 2 

### , as the emission rates of CH 4 

### and N 2 

### O are many orders of magnitude less than CO 2 

### . As shown in Table 3-3, FCPP is a major source of GHGs. However, the increase in GHGs associated with this Project is estimated to be 35,992 tpy of CO 2 

### e (not including the reduction from Units 1, 2 and 3), which would not be considered a major modi fication because the emission increase is less than 75,000 tpy. Therefore, this Project is not subjec t to PSD permitting for GHG emissions. The increase in CO 2 

### e emissions from Units 4 and 5 is attributable to occasional/periodic increased fuel use due to the SCR power requirement and economizer bypass.



## 3.7 Title V – Major Source Operating Permit
40 CFR 70 establishes the federal Title V operat ing permit program. The Navajo Nation has incorporated the provisions of the federal program in to the Navajo Nation Regulations at 4 NNR 11-2H. The major source thresholds with respect to the Navajo Nation Title V operat ing permit program for sources in attainment areas are the respective thre sholds of each PSD regulated pollutant, 10 tpy of a single hazardous air pollutant (HAP), or 25 tpy of any combination of HAP.

The FCPP has a Title V operating permit (No. NN-RO P-05-07). APS is renewing the Title V permit to reflect current operations and regulatory requirement s. After the PSD permit is issued for the SCR Retrofit Project, APS will amend the FCPP’s Title V operating permit within the required timeframes.AECOM Environment 3-12

60221977-460 April 2014 

## 3.8 Compliance Assurance Monitoring
On October 27, 1997, EPA promulgated the Compli ance Assurance Monitoring (CAM) Rule, 40 CFR Part 64, which addresses monitoring for certain emis sion units at major sources, thereby assuring that facility owners and operators conduct effective monito ring of their air pollution control equipment. In order to be subject to CAM, the following criteria must be met:

 The unit is subject to an emi ssions limitation or standard fo r the pollutant of concern;

 An “active” control device is used to ac hieve compliance with the emission limit; and

 The emission unit’s pre-control potential-to-e mit (PTE) is greater than the applicable major source threshold.

The CAM rule does not apply to emissions units/pollu tants that are subject to Sections 111 (NSPS) or 112 (NESHAP) of the CAA issued after November 15, 1990; the Acid Rain program or emissions trading programs. However, the increased H 2 

### SO 4 

### mist will be subject to an emission standard, controlled with an active control device, and pre- control PTE will be greater than the applicable major source threshold. A new CAM plan for H 2 

### SO 4 

### mist will satisfy the CAM rule requirements. The proposed CAM plan for H 2 

### SO 4 

### mist is included in Appendix C.


## 3.9 Regional Haze Rule and Guidel ines for Best Available Retrofit Technology Determinations
On July 6, 2005, the EPA finalized amendments to the July 1999 Regional Haze Rule. These amendments apply to the provisions of the Regional Ha ze Rule that require emission controls known as best available retrofit technology, or BART, for indu strial facilities emitting air pollutants that reduce visibility by causing or contri buting to regional haze (EPA 2005b).

The pollutants that reduc e visibility include PM 2.5 

### , and compounds which contribute to PM 2.5 

### formation, such as NOx, SOx, and under cert ain conditions, VOCs, and ammonia.

The BART requirements of the Regional Haze Rule apply to facilities built between 1962 and 1977 that have the potential to emit more than 250 tpy of vi sibility-impairing pollution. Those facilities fall into 26 categories, including utility and industrial boilers , and large industrial plants such as pulp mills, refineries and smelters. Many of these facilities pr eviously have not been previously been subject to federal pollution control requir ements for these pollutants.

Under the 1999 Regional Haze Rule, states are requir ed to set periodic goals for improving visibility in the 156 natural areas. As states work to r each these goals, they must develop regional haze implementation plans that contain enforceable m easures and strategies for reducing visibilityimpairing pollution. The amendments include guidelines, known as BART guidelines, for states to use in determining which facilities must install controls and the type of controls the facilities must use (EPA 2005b).AECOM Environment 3-13

60221977-460 April 2014 

### States must consider a number of factors when det ermining what facilities will be covered by BART including:

 the cost of the controls;

 the impact of controls on energy usage or any non-air quality environmental impacts;

 the remaining useful life of the equipment to be controlled;

 any existing pollution controls already in place; and

 visibility improvement that would re sult from controlling the emissions.

As discussed in Section 1, EPA promulgated a s ource-specific FIP requiring the FCPP to achieve emissions reductions required by the CAA’s BAR T provisions. EPA requires FCPP to reduce emissions of NOx and set emi ssion limits for PM. For NO X 

### emissions, EPA is requiring FCPP to meet a plant-wide emission limit of 0.11 lb/MMBtu on a rolling 30-day heat input-weighted average. This limit represents an 80 percent reduction from the current NO X 

### emission rate. EPA also finalized an alternative emission control strat egy that gives the owners of FCPP the option to close Units 1-3 and install controls on Units 4 and 5 to each meet an emission limit of 0.098 lb/MMBtu, based on a rolling average of 30 successive boiler operating days. For PM, EPA is requiring Units 4 and 5 at FCPP to meet an emission limit of 0.015 lb/MMBtu, and retai ned the existing 20 percent opacity limit. EPA is also requiring FCPP to comply with a 20 percent opacity limit on its coal and material handling operations.

In order to comply with EPA’s BART determination, APS has shut do wn Units 1-3 and will install SCR on Units 4 and 5.



## 3.10 Other Applicable or Potent ially Applicable Regulations

3.10.1 New Source Performance Standards – 40 CFR 60

The potential applicability of New Source Perform ance Standards (NSPS) is presented in the following subsections. Note, although there is some applic ability of these standards to the FCPP (e.g., associated with the recently permitted auxiliary boi ler), the proposed Project does not trigger any new or change any current NSPS requirements for this facility.

3.10.1.1 NSPS Subpart A – General Provisions Certain provisions of 40 CFR Part 60 Subpart A apply to the owner or operator of any stationary source subject to a NSPS. T he proposed modifications to Units 4 and 5 increase maximum hourly emissions of PM 10 

### , PM 2.5 

### , and H 2 

### SO 4 

### , but do not affect NSPS app licability because these pollutants are not regulated by the potentially applicable NSPS. Therefore, no provisions of Subpart A apply to this Project.

3.10.1.2 NSPS Subparts D, Da or Db – Sta ndards of Performance for Electric Utility Steam Generating Units

NSPS Subparts D, Da, or Db apply to new or modified Electric Utility Steam Generating Units (e.g., boilers) depending on the installation or modification date, relative cost of the modification, size of theAECOM Environment 3-14

60221977-460 April 2014 

### unit, and fuels burned. The SCR installation at FCPP does not qualify as a modification under any of these provisions, and hence FCPP is not subject to these S ubparts for this Project. .

3.10.1.3 NSPS Subpart OOO – Standards of Pe rformance for Nonmetallic Mineral Processing Plants Subpart OOO applies to certain activities at nonmetallic mineral processing plants. The sorbent for the dry sorbent injection system that will be used to control H 2 

### SO 4 

### mist will be lime. Lime is not classified as a nonmetallic mineral per the definitions in Subpart OOO. Therefore, the requirements of Subpart OOO will not apply to th e FCPP SCR Retrofit Project.



## 3.10.2 National Emissions Standards for Hazardous Air Pollutants – 40 CFR 63

National Emissions Standards for Ha zardous Air Pollutants (NESHAP) are reflected in a requirement for Maximum Achievable Control Technology (MAC T) standards, determined by EPA through an analysis of the best controlled sources in a category an d the cost of more stringent available controls. A source emitting more than 10 tpy of a single HAP or 25 tpy of a combination of HAPs is defined as a major source. Smaller sources are classified as area sources and must secure MACT approval prior to construction. If a MACT standard has not ye t been promulgated for the source category, the applicant must secure case-by-case MACT approval (Subpart B).

3.10.2.1 NESHAP Subpart A, General Provisions All affected sources are subject to the general provisions of Part 63 NESHAP Subpart A unless specifically excluded by the source-specific NESHAP . Similar to the NSPS, Subpart A of Part 63 requires initial notification and performance testi ng, recordkeeping, monitoring, provides reference methods, and mandates general control device requ irements for all other subparts as applicable. APS will comply with the S ubpart A provisions as needed to comply with Subpart UUUUU as discussed below.

3.10.2.2 NESHAP Subpart UUUUU, Electric Utility Steam Generating Units A MACT standard (Subpart UUUUU) for the oil- and coal -fired electric utility steam generating unit source category was finalized by EPA on February 2012. Units 4 and 5 are subject to Subpart UUUUU. The regulatory requirements include emission limits for mercury, par ticulate matter (as a surrogate for non-mercury metals), and hydrogen chlori de (HCl). In addition, the rule includes work practice standards to limit the emissions of or ganic air toxics, including dioxins and furans. Compliance with Subpart UUUUU is required by Apri l 2015. However, EPA may grant a one year extension on a case-by-case basis if more time is needed to install controls. APS will comply with Subpart UUUUU.

3.10.2.3 NESHAP Subpart B, 112(g) Case-by-Case MACT Section 112(g) of the 1990 Clean Air Act Amendm ents (codified at 40 CFR 63 Subpart B, Requirements for Control Technology Determinations for Major Sources in Accordance with Clean Air Act Sections), is known as the ca se-by-case MACT. Case-by-case MACT is not applicable to Units 4 and 5 because EPA has promulgated an applicable MACT standard for this source category.AECOM Environment 3-15

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## 3.10.3 Clean Air Interstate Rule (CAIR) / Cross-State Air Pollution Rule (CSAPR)
In May 2005, EPA promulgated CAIR to reduce the impact of upwind sources on out-of-state downwind PM 2.5 

### , and ozone in non-attainment areas. CAIR required upwind states to revise their state rules to include measures to reduce NOx and SO 2 

### emissions. CAIR was designed to rectify ozone and PM 2.5 

### non-attainment and thus regulate SO 2 

### and NOx via annual emission caps for each pollutant and NOx via an ozone season emissions cap. A court invalidated CAIR on July 11, 2008, but left it in effect until EPA could issue a substitute rule. EPA subsequently prom ulgated CSAPR, which was vacated by a court. In its opinion, the c ourt directed EPA to continue to enforce CAIR until the agency could finalize a replacement rule. Important ly, these interstate transport rules only apply to specific states generally located in the eastern U.S. Accordingly, the Four Corners Power Plant would not be subject to either CSAP R’s or CAIR’s requirements.



## 3.10.4 Acid Rain Provisions
Units 4 and 5 are subject to the Acid Rain Program pursuant to Title IV of the CAA Amendments of 1990. Both units are in compliance with the Acid Rain rules and will continue to be in compliance after the Project is installed.



## 3.10.5 Risk Management Program
The project may utilize anhydrous ammonia or aqueou s ammonia with greater than 19% ammonia in the selective catalytic reduction system. If anhy drous ammonia or aqueous ammonia with greater than 19% ammonia is used to control NOx emissi ons from Units 4 and 5, the storage amount of anhydrous or aqueous ammonia will require a Risk Management Plan (RMP) in accordance with EPA rules. Three elements comprise the RMP:

 Hazard Assessment;

 Prevention Program; and

 Emergency Response Program.

An approved RMP must be in place prior to exc eeding the threshold storage amount of anhydrous ammonia or aqueous ammonia with greater than 19% ammonia (10,000 lb) at the FCPP.AECOM Environment 4-1

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# 4.0 Control Technology Review

4.1 Technical Approach
APS is proposing to install SCR controls on Units 4 and 5 to reduce NOx e missions by approximately 19,200 tpy. The addition of SCR systems at FCPP wi ll result in a significant emission increase of H 2 

### SO 4 

### mist. Net emission increases for all other po llutants will be less than the PSD significant emission rates.

The FCPP is located in an area that is either atta inment or unclassified for all pollutants. Because the Project will result in signif icant emission increases of H 2 

### SO 4 

### mist, the project will be subject to PSD for this pollutant, and a Best Available Control Technolog y (BACT) analysis is required for this pollutant.

The only modified or new stationary sources which require BACT for H 2 

### SO 4 

### mist : 

### are:

 Units 4 and 5 consisting of two 7,411 MMBtu/hr 1 

### pulverized coal fired boilers with emissions controlled by SCR, dry sorbent injecti on (DSI) system, baghouses and lime-based wet scrubbers;


## 4.1.1 Best Available Control Technology Definition
The Federal regulations require that applicants for a PSD pre-construction permit conduct a BACT analysis for all regulated pollutants emitted in significant quantities from major stationary sources to demonstrate compliance with the control technology requirements of the PSD regulations in 40 CFR Part 52 Section 21.
According to 40 CFR §52.21(b)(12), BACT is defined as:

“Best available control technology means an emi ssions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under the Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a ca se-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application of producti on processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall applic ation of best available control technology result in emissions of any pollutant which would ex ceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61. If the Ad ministrator determines that technological or economic limitations on the application of meas urement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combination t hereof, may be prescribed instead to satisfy the

1 

### This heat input rate was used by EPA in its final BART rule, and represents a ranking higher than 99% over the

hours in the baseline period. In the future, the maximum 24-hour total heat input for Units 4 and 5 is not expected to exceed 14,822 MMBtu/hr.AECOM Environment 4-2

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### requirement for the application of best available c ontrol technology. Such standard shall, to the degree possible, set forth the emissions reduction achievable by implementation of such design, equipment, work practice or operation, and shall provide for compliance by means which achieve equivalent results.”

EPA recommends a “top down” approach to the BACT analysis. The process begins with the identification of the alternative control technologies available for the source category based upon a review of: (1) those technologies required by previ ous BACT determinations made by the EPA or the various state agencies; and (2) those technologies applied in practice to the same category or a similar source category by means of technology transfe r. The available control technologies are then evaluated to determine whether they are technically feasible for the given application. Those control technologies found to be technically infeasible are eliminated from further c onsideration, while the remaining control technologies are ranked by their pe rformance levels, from th e highest to the lowest performance level. The technically feasible cont rol technologies are then evaluated on the basis of the associated economic, energy and non-air qualit y environmental impacts. If an alternative technology, starting with the highest performance leve l, is eliminated based on any of these criteria, the control technology with the next highest perform ance level is evaluated until a control technology qualifies as BACT. All evaluated control technologi es must at least be capable of meeting the new source performance standard for the pollutant in question.

According to EPA guidance, BACT may be achieved by one or a combination of the following: (1) a change in the raw material processes; (2) a process modification; and/or (3) an add-on control device.

In summary, the “top-down” BACT process consists of five steps as follows:

STEP 1 - Identify all available control options with practical potential for application to the specific emission unit for the r egulated pollutant under evaluation;
STEP 2 - Eliminate technically infeasib le or unavailable technology options;
STEP 3 - Rank remaining control technologies by control effectiveness;

STEP 4 - Evaluate most effectiv e controls and document results; if top option is not selected as BACT, evaluate next most effective control option; and

STEP 5 - Select BACT, which will be the most effective practical option not rejected based on energy, non-air quality environmental, and economic impacts.

The "top-down" approach was used in this analysis to evaluate available pollution controls for the FCPP SCR Retrofit Project.



## 4.1.2 Previous BACT Determinations
Federal and State data sources were reviewed to determine the control technologies that have been applied to coal-fired boilers and other relevant sources around the country. The review focused on the types of air pollution control technologies us ed in these applications, the design and performance of each air pollution control technology, and the incentive for implementing the preferred control

measures.AECOM Environment 4-3

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### The review considered the following databases:

 EPA’s RACT/BACT/LAER Clearinghouse which is a national database of recently approved PSD permits; and

 Permits issued for similar projects in the Southwest;

Each of these databases has certain limitations t hat hinder either identif ying the control devices currently employed at the power plants or determini ng the performance levels actually achieved in practice by the control devices. The info rmation found in the EPA’s RACT/BACT/LAER Clearinghouse (RBLC) is provided in Appendix B. Note that some of these projects have been cancelled and others are not yet operating; henc e, some of the emission rates have not been demonstrated as achievable in practice. The results of this review were used, in part, to identify available emission control technologies (STEP 1 in th e BACT process), eliminate technically infeasible options (STEP 2), and to rank the remaining c ontrol technologies based on control effectiveness (STEP 3).



## 4.2 Four Corners SCR Retrofit Project BACT Determinations

As noted above, H 2 

### SO 4 

### mist emissions from the existing Units 4 and 5 pulverized coal-fired boilers are the only sources which require BACT for this Project.

Gaseous sulfur oxides from coal comb ustion are primarily sulfur dioxide (SO 2 

### ), with a much lower quantity of sulfur trioxide (SO 3 

### ) and gaseous sulfates. These compounds form as the organic and pyritic sulfur in the coal are ox idized during the combustion process. On average, about 95 percent of the sulfur present in coal will be emitted as gaseous sulfur oxides , whereas somewhat less will be emitted when subbituminous coal is fired. The more alkaline nature of the ash in some subbituminous coals causes some of the sulfur to react in the fur nace to form various sulfate salts that are retained in the boiler or in the flyash (EPA 1998).

During the combustion process approximately 0. 1% to 1% of the fuel sulfur (S) or SO 2 

### may be oxidized to form SO 3 

### . With the addition of SCR, additional SO 3 

### will be formed because the catalyst will oxidize some of the SO 2 

### to SO 3 

### . As the flue gas is cooled, SO 3 

### reacts with water to form H 2 

### SO 4 

### . At temperatures below the acid dew point, H 2 

### SO 4 

### will condense to form liquid H 2 

### SO 4 

### (sulfuric acid mist). On Units 4 and 5, some of the H 2 

### SO 4 

### will be removed from the flue gas by the air preheater, the fabric filter, and the wet scrubber.



## 4.2.1 STEP 1 – Available Sulfuric Acid Mist Emission Control Alternatives
Based on a review of available information, the following control alternatives were identified as potentially available:

 Fuel switching;  Semi-dry scrubbing;

 Fuel washing;  Wet electrostatic precipitation;

 Fuel processing;  Low and ultra-low oxidation SCR catalyst; and

 Ammonia injection  Dry sorbent injection.AECOM Environment 4-4

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## 4.2.2 STEP 2 – Eliminate Technically Infeasible Options
4.2.2.1 Fuel Switching In general, switching to a lower sulfur coal is a pote ntial option to reduce sulfuric acid mist emissions because emissions tend to be proportional to the sulfur content of the coal. However, the FCPP is a mine-mouth plant that burns low sulfur coal with a typical sulfur content of approximately 0.78% and a heating value of 8,776 Btu/lb. Only Powder River Ba sin coal has lower sulfur content on a lb/MMBtu basis. Switching to Powder River Basin coal is not technically feasible due to the lack of railroad access at the power plant. There would also be considerable increased emissions of several pollutants associated with the transport of the coal from Wyoming to Arizona. In addition, there would be concerns about the reliability of deliveries and the continued availability of low-sulfur Powder River Basin coal.

The FCPP is an existing mine-mouth plant that was designed and developed to burn coal from the Navajo Mine located on the Navajo Nation. The sour ce of the coal for the FCPP is a specific reserve of coal from the Navajo Mine sufficient to satisf y the plant’s fuel requirements through July 2031. Pursuant to the FCPP co-owners’ pl ant lease with the Navajo Nation , the primary fuel at the plant shall be coal, thereby precluding natural gas as an energy source. 2 

### And under the FCPP co-owners’ 25-year coal supply agreem ent with Navajo Transitional Energy Company, LLC, a limited liability company formed under the laws of the Navajo Nation (“NTEC”), the exclusive source of such coal shall be the Navajo Mine. The FCPP’s use of this particular coal supply from the Navajo Mine is an inherent aspect of the plant, and it would be inconsistent with the proj ect’s scope to evaluate coal from alternative sources in the BACT analysis. 3



### Because the FCPP is an existing plant fueled fr om coal derived from an adjacent mine, a consideration of alternative coal supplies would redefine the source, and ther efore, may be eliminated from further consideration under STEP 1 of the BACT analysis. 4



### Furthermore, to burn low-sulfur Powder River Basi n coal, the FCPP co-owners would have to arrange for coal to be transported from mines over 600 hundred miles away. As noted above, such transportation would result in a considerable increas e in emissions of several pollutants. Moreover, there are no rail lines running from these Wyoming mines across the Navajo Nation reservation to the

2 

### See EPA Office of Air and Radiation, PSD and Title V Permitting Guidance for Greenhouse Gases at 27 (Mar. 2011) (“[W]hen a [PSD permit] applicant proposes to cons truct a coal-fired steam electric generating unit, EPA continues to believe that permitting authorities can show in most cases that the option of using natural gas as a primary fuel would fundamentally redefine a coal-fired electric generating unit.” (citing In re Old Dominion Electric Cooperative , 3 E.A.D. 779, 793-94 (EPA Administrator 1992))).

3 

### See In re Prairie State Generating Co. , 13 E.A.D. 1, 28 (EAB 2006) (finding that “consideration of low-sulfur

coal, because it necessarily involves a fuel source other than the co-located mine, would require Prairie State to redefine the fundamental purpose or basic design of its proposed Facility and that, therefore, low-sulfur coal could appropriately be rejected from further BACT analys is at step 1 of the top-down BACT review method.”).

4 

### Id. See also EPA Office of Air Quality Planning and Standards, New Source Review Workshop Manual at B.13 (Oct. 1990) (Draft) [hereinafter “NSR Workshop Manual ”] (“Historically, EPA has not considered the BACT requirement as a means to redefine the design of the so urce when considering available control alternatives.”); In re Old Dominion Electric Cooperative , 3 E.A.D. at 793 n. 38 (“Traditionally, EPA does not require a PSD [permit] applicant to change the fundamental scope of its project.”).AECOM Environment 4-5

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### FCPP. The construction of such lines would no t be economically feasible and would require the consent of the Navajo Nation.

Transporting the coal to the FCPP by truck would be physically impossible given the excessively large number of trucks that would need to travel to the FCPP each day. The FCPP burns an average of 18,000 tons of coal per day. Assu ming conservatively that each truck can transport 50 tons of coal per day, approximately 360 truckloads of coal would need to be delivered to the FCPP each day. 5 

### That would equal one truckload ever y four minutes, resulting in a steady stream of trucks from the Powder River Basin mines to the FCPP. Not only would this be physically impossible, the additional pollutants that would result from transporting th e coal by truck would be detrimental to the environment. Furthermore, changing the coal source from the Navajo Mine would require changes in the design of the FCPP’s existing facilities for receiving coal. Su ch redesign of the source is not required under STEP 1 of the BACT analysis. 6



### Moreover, the use of alternative coal supplies at the FCPP would be inconsistent with the business objectives of the FCPP co-owners and would advers ely affect the Navajo Nation given NTEC’s ownership of the Navajo Mine and the socioeconomic benefits expected to accrue to the Navajo Nation as a result of coal sales to the FCPP co-owners. Neither wind nor solar power would provide these economic benefits. Moreover, the FCPP is intended to serve as a base load plant and, therefore, neither wind, which is undependable and incons istent, nor solar, which is intermittent, would be an acceptable substitute for reliable coal-fired generation.

For all of the foregoing reasons, alternative fuels, including low-sulfur coal from the Powder River Basin, are excluded from BACT consideratio n as a control alternative at the FCPP.

4.2.2.2 Fuel Washing
As noted in EPA’s New Source Review Manual, a tec hnology is not technically feasible if it is not commercially available. 7 

### “In general, a commercially avail able control option will be presumed applicable if it has been or is soon to be deployed (e .g. is specified in a permit) on the same or a similar source type.” 8 

### Coal washing is not a commercially av ailable technology for the coal used by the FCPP. To date, coal washing to remove su lfur from western coals has not been required as BACT. In addition, no coal washing plant has been built to remove sulfur from western coals. Therefore, coal washing is not an available te chnology for the FCPP and is rejected as being technically infeasible under ST EP 2 of the BACT review.

Coal washing, or beneficiation, is a pre-combustion method that has been used to reduce impurities in the coal, such as ash and sulfur. In general, coal washing is accomplished by separating and

5 

### The number of trucks would increase to 720 if each truck could carry only 25 tons due to the long distance (over

600 miles) traveled; in other words, one truck from the mines to the FCPP every two minutes.

6 

### See Sierra Club v. EPA , 499 F.3d 653, 655-57 (7th Cir. 2007) (finding that the “significant modifications” that

would be required to reconfigure a mine-mouth plant to one that burned coal obtained from a distance “would constitute a redesign” that may be rejected under STEP 1 of the top-down BACT review process.

7 

### See NSR Workshop Manual at B.17-B.21.

8 

### Id. at B.18.AECOM Environment 4-6

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### removing inorganic impurities from organic coal particles. While washing may be effective in removing rock inclusions from coal, including some sulfur-bearing pyrites, a significant amount of coal may also be lost in the washing process. In additi on, the removal of sulfur from coal by washing is limited because it only affects sulfur-bearing pyrites and does not affect organic sulfur. Although data are limited, the coal used by the FCPP contains only approximately 40% or less pyritic sulfur. Therefore, even if coal washing were technically f easible, which it is not, the process would reduce fuel sulfur by less than 40% forcing its eliminati on as a control technology under the BACT analysis. 9



### Moreover, there are significant adverse environmen tal, energy, and economic impacts associated with coal washing. With respect to environmental impacts, an inherent consequenc e of coal washing (in addition to the use of scarce water supplies in a des ert environment) is the generation of wastewater and solid waste streams. In respect to energy im pacts, the mine would need to process significantly more coal to make up for the significant amount of coal that would be lost in the washing process and discarded with the waste, and heat content would be lo st due to the addition of water to the coal from the washing process. Finally, as for economi cs, substantial costs would be associated with constructing and operating t he coal washing facility. 10



### Coal washing as a strategy to reduce SO 3 

### emissions is not considered a technically feasible H 2 

### SO 4 

### mist control option and, therefore, is properly eliminated under STEP 2 of the BACT analysis.

4.2.2.3 Fuel Processing
Research on pre-combustion coal processing tec hniques such as Evergreen Energy’s K-Fuel® process has been conducted over the last 30 years. In general, the goal is to develop a process to upgrade low grade subbituminous coal and lignite into low moisture products. The K-Fuel® process uses heat and pressure to remove approximately 30% of the moisture from lower-rank subbituminous and lignite coals containing 20% to 30% moisture. This moisture removal improves the heating value, reduces transportation costs, increases boiler effi ciency and may reduce emissions on a lb per MMBtu basis. To date, the production of processed fuel s has been limited to a demonstration plant that began operation in Gillette, Wyoming in 2005. Alth ough designed to be a commercial plant, the plant experienced design and operating problems and was idled in March 2008. In January 2012, Evergreen Energy declared bankruptcy. Stock in t he company is currently traded Over the Counter at $0.01 per share.

Pre-combustion fuel processing is not applicable to the FCPP becau se it is a-mine mouth plant and the fuel from the associated mine contains only 11 % to 13% moisture. In addition, pre-combustion fuel processing is not a commercially available technology. Therefore, processed fuels are not considered a technically feasible H 2 

### SO 4 

### mist control option for the FCPP.

9 

### Coal washing has never been commercially applied to remove sulfur from western coal. Therefore, the

expected performance is not known and might be much lower than 40%, thus not resulting in materially lower overall H 2 

### SO 4 

### emission reductions.

10 

### See In re Prairie State Generating Co. , 13 E.A.D. 1, 42 (EAB 2006) (finding that “any benefits of coal washing

are outweighed by coal washing’s cost, energy, and environmental impacts.”).AECOM Environment 4-7

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### 4.2.2.4 Ammonia Injection Ammonia-based systems designed for H 2 

### SO 4 

### control typically involve ammonia injection into the flue gas upstream of a cold-side el ectrostatic precipitator. Ammonia will react with SO 3 

### in the flue gas to form ammonia salts, main ly ammonium sulfate [(NH 4 

### ) 2 

### SO 4 

### ] and ammonium bisulfate [NH 4 

### HSO 4 

### ]. Ammonia salt formation is dependent upon flue gas te mperature and reagent stoichiometric ratios. Flue gas temperatures at the inlet to a cold-side elec trostatic precipitator are typically in the range of 300°F to 350°F, which will promote the formation of ammonium bisulfate. Ammonium bisulfate tends to make fly ash more cohesive, which can promot e fly ash capture in a cold-side electrostatic precipitator.

Ammonia injection for SO 3 

### differs significantly from the use of ammonia for SCR. When used for SCR, ammonia is injected afte r the economizer where the flue gas temperature is approximately 650 °F. After reacting with NOx, amm onia slip from the SCR is limited to approximately 10 ppmv. For control of SO 3 

### , ammonia is injected at high concentrations (up to 5,000 ppm) prior to the final control device which is typically a cold-side EPS as described above. Ammonium sulfate is a sticky substance that can adhere to duct walls and dow nstream equipment and cause significant plugging and blockage issues but can promote fly ash capture in a cold-side electrostatic precipitator. Although ammonia injection has been successfully used for SO 3 

### control on coal-fired units equipped with coldside electrostatic precipitators, an ammonia injectio n system would not have a practical application on a unit equipped with a fabric filter, such as the FCPP, due to plugging and blockage issues associated with the sticky properties of ammoni um bisulfate. In ad dition, even if techni cally feasible, ammonia injection is not expected to achieve lower emissions than dry sorbent injection. Based on technical feasibility issues and performance, ammonia inject ion is eliminated from further consideration.

4.2.2.5 Semi-Dry Flue Gas Desulfurization Control Systems Spray Dryer Absorber Spray dryer absorbers are designed and used to remove SO 2 

### from coal-fired combustion gases. These devices also promote the removal of H 2 

### SO 4 

### mist. Semi-dry scrubbing using a spray dryer absorber involves the introduction of hydrated lime sl urry into a reaction tower where it reacts with SO 2 

### in the flue gas to form calcium sulfite solids. Unlike wet flue gas desulfurization (FGD) systems that produce a slurry by-product that is collected separately from the fly as h, spray dryer absorber FGD systems produce a dry by-product that must be re moved with the fly ash in the particulate control equipment. Therefore, a spray dryer absorber sy stem must be located upstream of the unit’s particulate control device. On existing units equi pped with a fabric filter and wet scrubber, retrofitting the unit with spray dryer absorber FGD includes not only the redundant FGD control system but would also require fabric filter modifications. For the FCPP, a spray dryer absorber FGD system would require complete redesign and reconstruction of the ex isting air polluti on control system. Therefore, a semi-dry FGD system would be consider ed as not technically feasible H 2 

### SO 4 

### mist control technology for FCPP.

Even if a spray dryer absorber FGD system is cons idered to be technically feasible, it does not offer any performance advantage over other technol ogies. Data from EPA’s RACT/BACT/LAER Clearinghouse, presented in A ppendix B, show that H 2 

### SO 4 

### mist emission limits for projects using this option are generally in the 0.0040 lb/MMBtu to 0.0075 lb/MMBtu range. The onl y project with both a spray dryer absorber FGD system and a wet FGD is the Duke Cliffside Unit 6 project which has a H 2 

### SO 4 

### mist emission limit set at 0.0050 lb/MMBtu.AECOM Environment 4-8

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### Based on technical feasibility issues and perfo rmance, a spray dryer absorber FGD system is eliminated from further consideration.

SBS InjectionTM Technology The reagent used for SBS injection is sodium carbonate. In contrast to a spray dryer absorber, which uses a slurry and dry sorbent injection, SBS injection uses a clear solution. 11,12 

### The use of clear solution eliminates problems associated with handlin g slurries, such as nozzle plugging and erosion. Dual fluid nozzles are used to produce small droplets quickly form dry particles in the 1 to 10 micron range which are smaller than the 15 to 50 micr on particles used for dry injection of sodium compounds or hydrated lime. Although the use of a sodium-based reagent woul d likely force APS to stop selling fly ash, SBS injection is considered to be technically feasible.

4.2.2.6 Low and Ultra-Low Oxidation SCR Design
As discussed in Section 2.2.1, NOx reduction in the SCR controls comes at the cost of SO 2 

### oxidation. Low conversi on catalysts contain less vanadium pentoxide (V 2 

### O 5 

### ) and therefore achieve lower SO 2 

### oxidation at the expense of less NOx re duction. Suppliers have improved the low oxidation catalyst by using materials such as molybdenum and tungsten that reduce NOx while minimizing SO 2 

### conversion, but they are not as effective as V 2 

### O 5 

### for NOx control and SO 2 

### oxidation is not completely mitigated.
Catalyst vendors typically recommend a 2+1 (two in itial layers plus one future layer) configuration on a coal-fired power plant. However, due to t he high ash content at FCPP (typically 23% ash and 8,880 Btu/lb), a 3+1 design is needed to accommodate a larger pitch to reduce pluggage. Some vendors have noted that lignite ash would be easier to handle than Four Corners ash because the larger particles would be easier to remove on a la rge particle ash screen. Due to the large cross sectional area that will be needed to maintain the required NOx reduction, the velocity is reduced and the flow spread out, creating pluggage and maldistr ibution issues. Maldistribution of flow will decrease the expected life of the catalyst because areas that ar e subject to higher flow will deactivate at a faster rate and the total NOx reduction potential will decrease. Areas with significant pluggage (most likely outside walls and above structur al supports) will physically degrade due to the corrosivity of the ash. The FCPP has one of the most severe ash conditions in the country for SCR service. The high ash quantity, abrasiveness, and lo w alkalinity are all factor s that adversely affect SCR performance.
In order to limit NOx emissions to 0.098 lb/MMBtu, the FCPP will require 4 cata lyst layers (3+1) with a 3-year catalyst replacement schedule. A lo w oxidation catalyst will be used to limit SO 2 

### oxidation to 1% (0.25% per layer). With a high alkaline we stern subbituminous coal ash, a lower conversion rate might be possible, but Four Corner’s as h is not high alkaline. High alkaline western subbituminous coal ash contains 20 – 30% CaO pl us MgO while Four Corner’s ash only contains about 4% CaO plus MgO.

11 

### http://urs-processtechnologies.com/wp-content/uploads/2013/02/SBS-brochure-2_2013.pdf

12 

### http://codandevelopment.com/core/articles/Ultra-HighSO3Removal2008.pdfAECOM Environment 4-9

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### Limiting SO 2 

### oxidation to 0.5% might be technically feasib le if the catalyst replacement schedule is reduced from every 3 years to every 2 years. For this analysis, limiting SO 2 

### oxidation to 0.5% is assumed to be technically feasible.
4.2.2.7 Dry Sorbent Injection DSI systems involve the injection of sodium- or calcium-based sorbents in the duct work from the boiler either: (1) before the SCR system, (2) after t he SCR system but before the air preheater, or (3) after the air preheater. DSI systems consist of a st orage silo, compressors or blowers to transport the sorbent to the duct, and associated piping. The use of a sodium based reagent (either Trona or SBS) would probably force APS to stop selling fly ash. However, DSI using either a sodium or calciumbased sorbent is technically feasible.


## 4.2.3 STEP 3 – Rank Remaining Technologies by Control Effectiveness
The remaining technologies and their potential control effectiveness are listed in 

## Table 4

‐ 1 below. Details on the overall control efficiency, which in cludes the effects of t he existing air preheater, fabric filter, and wet FGD system are shown in Table 4-2. The potential performance of the available emission control technologies is disc ussed further in Sections 4.2.1.4 and 4.2.1.5.



## Table 4

- 

## 1 Ranking of Technically Feasible H 2 

## SO 4 

## Mist Control Technologies

Control Technology Reduction from Baseline Emissions (a) 

### Emissions (lb/MMBtu) Emissions (ppmvd corrected to 3% O 2 

### )
Wet Electrostatic Precipitation 87% 0.00100 (b) 

### 0.3 (b)



### Dry Sorbent Injection or SBS 42% 0.00435 1.5

Ultra-Low Oxidation (0.5%) SCR Catalyst 39% 0.00461 1.6

Low Oxidation (1% oxidation) SCR Ca talyst (Baseline) 0% 0.00751 2.6

(a) Baseline emissions account for the use of a low oxidation catalyst. (b) This emission may not be achievable. It is used in th is BACT analysis to determine if it might be BACT, if achievable.AECOM Environment 4-10

60221977-460 April 2014 

## Table 4

- 

## 2 Detailed Overall H 2 

## SO 4 

## Mist Emission Control Data

Parameter Control Option Control Option SCR at 0.5% Oxidation Dry Sorbent Injection Wet ESP Units

Boiler Heat Input 14,822 14,822 14,822 MMBtu/hr

Fuel S 0.78% 0.78% 0.78% wt % Fuel heating Value 8,776 8,776 8,776 Btu/lb

Oxidation of Fuel S to SO 3 

### 0.294% 0.294% 0.294%

SO 3 

### at Boiler Outlet 96.96 96.96 96.96 lb/hr

Oxidation of SO 2 

### to SO 3 

### by SCR 0.50% 1.00% 1.00%

SO 3 

### added by SCR 164.67 329.34 329.34 lb/hr

SO 3 

### at SCR outlet 261.63 426.30 426.30 lb/hr Removal by Air Preheater 50% 50% 50% Removal by Baghouse and Wet Scrubber 57.39% 57.39% 57.39%

SO 3 

### Emissions 55.74 90.82 90.82 lb/hr

H 2 

### SO 4 

### Emissions 68.28 111.26 111.26 lb/hr

H 2 

### SO 4 

### Emissions before Control 0.00461 0.00751 0.00751 lb/MMBtu

Add on Control H 2 

### SO 4 

### Efficiency, % 0% 42% 87%

H 2 

### SO 4 

### Emissions after control 0.00461 0.00435 0.00100 lb/MMBtu

H 2 

### SO 4 

### Emissions after control 1.6 1.5 0.3 ppmvd corrected to 3% O 2 

### H 2 

### SO 4 

### Emissions after control 68.3 64.5 14.8 lb/hr



### Overall H 2 

### SO 4 

### control efficiency (SCR outlet to stack) 78.70% 87.64% 97.16%



## 4.2.4 STEP 4 – Evaluate Most Effective Controls and Document Results
4.2.4.1 Wet Electrostatic Precipitation
Wet electrostatic precipitation has been proposed on a very limited number of new coal-fired boilers as one technology capable of achieving emission cont rol objectives and capturing sulfuric acid mist emissions. Wet electrostatic prec ipitation has been demonstrated as an effective control technology for sulfuric acid mist emissions from industrial applications with rela tively low flue gas flow rates and high acid mist concentrations, such as sulfuric acid plants. However, until recently, the technology has not been applied to the utility i ndustry because of the high gas fl ow volumes and low acid mist concentrations associated with utility flue gas as well as the high cost of th e corrosion resistant alloys that are required.AECOM Environment 4-11

60221977-460 April 2014 

### In a utility application, such as Four Corners Units 4 and 5, the wet electrostatic precipitator would be located downstream of the wet flue gas scrubber to remove micron-sized H 2 

### SO 4 

### aerosols from the flue gas stream as a condensable particulate. Elec trostatic precipitation consists of three steps: (1) charging the particles to be collected via a high-voltage electric discharge; (2) collecting the particles on the surface of an oppositely charged collection electrode surface; and (3) cleaning the surface of the collecting electrode. In a wet electr ostatic precipitation system, the collecting electrodes are typically cleaned with a liquid wash. Particulate ma ss loading, particle size distribution, particulate electrical resistivity, and prec ipitator voltage and current will influence performance. The wet cleaning mechanism can also affect the nature of the particles that can be captured and the performance efficiencies that can be achieved.

Wet electrostatic precipitation has been proposed to c ontrol sulfuric acid mist emissions from boilers firing a high-sulfur bituminous coal and equipped wi th SCR and wet flue gas desulfurization. This combination of coal and control equipment results in a relatively high concentration of sulfuric acid in the flue gas. The lower sulfur coals fired at FCPP generate relatively low sulfuric acid mist flue gas concentrations compared to high sulfur coal plants.

For the purpose of this BACT analysis , it is assumed that wet electr ostatic precipitation might limit H 2 

### SO 4 

### mist emissions to 0.0010 lb/MMBtu. Although 0.0010 lb/MMBtu is used as an assumption in this BACT analysis, this emission ra te might not be achievable. The tw o permit limits identified in this analysis, see Appendix B, are the Prairie State, Illi nois project at 0.0050 lb/MMBtu and the Elm Road, Wisconsin project at 0.0100 lb/ MMBtu, both with permi t limits much higher than 0.0010 lb/MMBtu. The wet ESP system would be located downstream of the wet flue gas desulfurization system on each unit. Based on the assumption that wet electrostatic precipitation can reduce H 2 

### SO 4 

### mist emissions from 0.00751 lb/MMBtu to 0.0010 lb/MMBtu, the emission reduction based on maximum potential emissions would be 211 tpy per unit or 422 tpy total for Units 4 and 5.

Estimated capital and annual costs for the wet el ectrostatic precipitation option are presented in Tables 4-3 and 4-4 , respectively. As shown in Table 4-3, the APS estimated cost for adding a wet ESP to the existing FCPP emission control train is $206 million per unit or $412 million total for Units 4 and 5. The APS estimated annualized cost for the wet ESP option, as shown in Table 4-4, is $37.5 million per unit or $75 million total for Units 4 and 5. The total reduction in H 2 

### SO 4 

### acid mist emissions, based on maximum potential emissions, is 411.4 tpy. Therefore, the overall cost effectiveness is $178,000 per ton of H 2 

### SO 4 

### acid mist emissions controlled.

Based on the excessively high cost effectiveness, wet electrostatic precipitation is not BACT for H 2 

### SO 4 

### mist emissions at the FCPP.AECOM Environment 4-12

60221977-460 April 2014 

## Table 4

- 

## 3 Wet ESP Capital Cost for One Unit (a)



### Cost Item $ Remarks/Cost Basis

CAPITAL COST
Direct Costs
Purchased e q ui p ment costs WESP system includes casing, electrical t th bl & h t $41,208,000 En g ineerin g estimate Ash handling system $1,888,000 En g ineerin g estimate Booster fans $2,467,000 En g ineerin g estimate Electrical system upgrades $2,467,000 En g ineerin g estimate Ductwork $5,664,000 En g ineerin g estimate Subtotal capital cost (CC) $53,694,000 Instrumentation and controls $2,685,000 (CC) x 5.0% Freight $2,416,000 ( CC ) x 4.5% Taxes $5,369,000 ( CC ) x 10.0% Total purchased equipment cost (PEC) $64,164,000
Direct installation costs Foundation & supports $12,833,000 ( PEC ) x 20.0% Handling & erection $32,082,000 ( PEC ) x 50.0% Electrical $6,416,000 ( PEC ) x 10.0% Piping $3,208,000 ( PEC ) x 5.0% Insulation $1,283,000 ( PEC ) x 2.0% Painting $642,000 ( PEC ) x 1.0% Demolition $642,000 ( PEC ) x 1.0% Relocation $642,000 ( PEC ) x 1.0% Total direct installation costs (DIC) $57,748,000 Total direct costs (DC) = (PEC) + (DIC) $121,912,000
Indirect Costs Engineering $12,191,000 ( DC ) x 10.0% Construction management $6,096,000 ( DC ) x 5.0% Start-up and spare parts $1,829,000 ( DC ) x 1.5% Performance test $100,000 En g ineerin g estimate Contingencies $24,382,000 ( DC ) x 20.0% Total indirect costs (IC) $44,598,000 Construction Difficulty Costs (DIFF) $28,874,000 Engineering estimate from Allowance for Funds Used During Construction (AFDC) $11,239,000 [(DC) + (IC)] x 4.50%, 3 years (project time length x 1/2) Total miscellaneous costs (MISC) = (DIFF) + (AFDC) $40,113,000
Total Capital Investment (TCI) = (DC)+(IC)+(MISC) $206,623,000

(a) Capital costs are based on data developed by Black & VeatchAECOM Environment 4-13

60221977-460 April 2014 

## Table 4

- 

## 4 Wet ESP Annual Costs and Cost Effectiveness

Cost Item $ Remarks/Cost Basis

ANNUAL COST

Direct Annual Costs

Fixed annual costs

Maintenance materials and labor $3,657,000 (DC) x 3.0%

Operating labor $73,000 1 FTE and 72,800 $/year Estimated man p ower Total fixed annual costs $3

, 730

, 000 Variable annual costs Operating hours 8,760 hours/year Reagent [Mg(OH)2] $74,000 80 lb/hr and 210.00 $/ton Auxiliary power $1,472,000 2,800 kW and 0.06 $/kWh ID fan power $2,208,000 4,200 kW and 0.06 $/kWh
Service water $0 350 gpm and 0.002 $/kgal Total variable annual costs $3,754,000

Total direct annual costs (DAC) $7,484,000

Indirect Annual CostsOverhead $2,238,000 60% of O&M and superTaxes, Insurance, and Administration $8,265,000 4% of total installed cost Capital Recovery $19,504,000 7.0%, 20 years, 0.0944 Total Indirect annual costs (IDAC) $30

, 007

, 000

Total Annual Cost ( TAC ) = ( DAC ) + ( IDAC ) $37
, 491 , 000

Potential sulfuric acid mist emissions before 243.7 tpy Potential sulfuric acid mist emissions after control 32.5 tpy
Sulfuric acid mist emission reduction 211.2 tpy

Cost effectiveness $178,000 per ton of emissions controlled
(a) EPA Air Pollution Control Cost Manual , Sixth Edition, Section 4, Page 2-44 . EPA/452/B-002-001. January 2002.AECOM Environment 4-14

60221977-460 April 2014 

### 4.2.4.2 Dry Sorbent Injection or SBS Injection Dry sorbent injection (DSI) systems involve the inje ction of sodium- or calcium-based sorbents in the duct work from the boiler either: (1) before the SCR system, (2) after the SCR system but before the air preheater, or (3) after the air preheater. DSI sy stems consist of a storage silo, compressors or blowers to transport the sorbent to the duct, and a ssociated piping. SBS inje ction is similar except that sodium bicarbonate is used and it is injected as a solution in water.

Flue gas properties, reagent properties, and injection system design all affect the performance of a DSI system. Important flue gas properties incl ude the concentration of acid gas species (SO 3 

### , SO 2 

### , and hydrochloric acid (HCl)) and temper ature. Both sodium and calcium sorbents tend to first capture SO 3 

### , then HCl, followed by SO 2 

### . However, even when control of SO 3 

### is the primary objective, HCl and SO 2 

### may consume much of the reagent depending upon the selected reagent, pollutant concentrations and temperature. Sodium reagents have high SO 3 

### reactivity, but they also readily react with both HCl and SO 2 

### . For power plants with existing wet FGD systems, such as the FCPP, reaction of sodium compounds with SO 2 

### is an undesirable and expensive secondary effect. For SO 3 

### control, injection of hydrated lime at a relati vely low temperature can minimize the collection of SO 2 

### . The porosity of the reagent affects its reactivity and utilization. Injection at higher temperatures and milling of the sorbent to a very small particle size can increase porosity. So rbacal® SP is specially prepared hydrated lime with high surface area and porosity.

Key injection system considerations are reagent distribution, gas residence time, and the type of particulate control. DSI systems require intimate and uniform contact with the acid gases in the flue gas. If some of the flue gas does not contact the reagent, performance will be adversely affected. Computerized fluid dynamic modeling and static mixi ng have been effective to insure good mixing of the sorbent and the flue gas. In general, baghouses provide added gas-solid contact compared to an electrostatic precipitator and better acid gas emission control.

APS has discussed DSI and SBS with equipment and chemical vendors to determine the effectiveness and to estimate the quantities of sorbent required. The discussions focused on available sorbents, sorbent injection points (befor e or after the air preheater), required sorbent quantities and H 2 

### SO 4 

### mist emission control performance. Based on these discussions, APS has determined that SBS or DSI can reduce H 2 

### SO 4 

### mist emissions by 42% and H 2 

### SO 4 

### mist emissions can be limited to 0.00435 lb/MMBtu, which is equivalent to 1.5 ppmvd corrected to 3% O 2 

### . Vendors expressed concerns and doubts about guaranteeing emissions below 1.5 ppmvd corrected to 3% O 2 

### due to uncertainties about achieving this low concent ration and demonstrating performance at FCPP. Although some facilities have shown emis sions below 1.5 ppmvd corrected to 3% O 2, 

### the commercial guarantees have been 1.5 ppmvd corrected to 3% O 2 

### and higher.

For the FCPP, hydrated lime is the best reagent choice for several reasons. The use of a sodiumbased reagent would increase the sodium content of the fly ash, which would probably prevent the FCPP from continuing to sell fly ash. Currently, th e FCCP sells more than 1,000,000 million tons of fly ash per year. The net cost of not selling fly ash would be approximately $4 million/year. In addition, not selling fly ash presents adverse environmental impacts because instead of being reused, the fly ash would have to be landfilled. Also, sodium co mpounds are very soluble in water and can create landfill leachate problems.AECOM Environment 4-15

60221977-460 April 2014 

### For the FCPP, a lime-based DSI system is the preferred H 2 

### SO 4 

### mist emission control option. Achievable H 2 

### SO 4 

### emissions are based on stack test results fo r the effect of combustion, the use of a low oxidation SCR catalyst with up to 4 layers, remova l by the air preheater, removal by the fabric filter and wet scrubber, and increased removal by DSI as prev iously shown in Table 4-2. A low oxidation catalyst can be used in the SCR system to limit oxid ation to 1%. The air preheater will remove 50% of the H 2 

### SO 4 

### mist entering the unit and the fabric filter and wet scrubber system will provide 57.39% control. The addition of DSI will provide 42% addition al control resulting in an overall control efficiency of approximately 88%. Removal by the air preheater is based on test data for the current configuration of Units 4 and 5 at FCPP, and the e ffect of the increased operating temperature required for the SCR. The control efficiency for the fabric filter and wet scrubber system is also based on test data for current operations. APS discussed DS I and SBS control options with equipment and chemical vendors to determine the effectiveness of these systems and to estimate the quantities of sorbent required. The discussions focused on avail able sorbents, sorbent injection points (before or after the air preheater), required sorbent quantities and H 2 

### SO 4 

### mist emission control performance. Based on these discussions, APS has dete rmined that DSI or SBS can reduce H 2 

### SO 4 

### mist emissions by 42% and H 2 

### SO 4 

### mist emissions can be limited to 0.00435 lb/MMBtu, which is equivalent to 1.5 ppmvd corrected to 3% O 2 

### . There are no unacceptable energy, economic, or non-air quality environmental impacts associated with using hydrated lime for dry sorbent injection.

4.2.4.3 Ultra- Low Oxidation SCR Catalyst It may be possible to limit oxidation of SO 2 

### to SO 3 

### by the SCR catalyst to 0.5% by replacing the catalyst every 2 years instead of every 3 years. Without DSI or SBS, this option would limit H 2 

### SO 4 

### mist emissions to 1.6 ppmvd corrected to 3% O 2 

### . Based on APS’s discussion with DSI and SBS vendors, available performance guarantees would not be affected by the lower pre-control emissions associated with an ultra-low oxidation SCR catalyst. Therefore, an ultra-low oxidation catalyst does not offer an emission performance advantage when compar ed to a low oxidation catalyst with DSI. In addition, a 2-year catalyst would increase the annual SCR cost by approximately $5 million/year.

The use of an ultra-low oxidation catalyst is not BACT, because it does not achieve lower emissions than DSI.



## 4.2.5 STEP 5 – Select the Best Available Control Technology
As previously discussed in Section 4.1.2.4, wet electr ostatic precipitation is not BACT due to the very high cost effectiveness of approximately $178,000 per t on of sulfuric acid mist controlled As BACT, APS proposes the use of a low oxidation SCR cataly st, DSI, fabric filtration, and wet FGD to limit H 2 

### SO 4 

### mist emissions to 0.00435 lb/MMBtu which is e quivalent to 1.5 ppmvd corrected to 3% O 2 

### . The proposed H 2 

### SO 4 

### emission rate of 0.00435 lb/MMBtu is within the range of recent BACT determinations listed in Appendix B, Table B-1. Permit limits vary wi dely due to many factors including boiler design, coal characteristics, S CR design and NOx control requirements, particulate control equipment type, SO 2 

### control equipment, and other factors. For example, the coal used by the projects listed in Appendix B, Table B-1 typically are not high ash, low alkalinity coal similar to the coal used at the FCPP. In addition, it s hould be noted almost all of the projects listed in Table B-1 are new boilers, not retrofit projects like the FCPP SCR Retrofit Project. In almost all cases, the listed controls were selected to meet SO 2 

### and particulate control requirements in the most cost effective manner.AECOM Environment 4-16

60221977-460 April 2014 

### The design of a new air pollution control system can allow the cost of a wet ESP, for example, to be partially offset by reduced costs for other air pollution control equipm ent. Also, the cost of control equipment for a new boiler is much lower than the cost to retrofit the same equipment at an existing facility.

While there are some lower emission rates listed in Table B-1, many of those instances are for circulating fluidized bed combustion projects not pulverized coal-fired boilers. The high concentrations of limestone and lime in a circulating fluidiz ed bed combustion unit can be expected to provide lowerH 2 

### SO 4 

### mist emissions than a pulverized coal-fired boiler.

The emission limits for many of the other projects listed in Table B-1 have not been demonstrated as achieved in practice because the projects were never built. Notices of violation were issued for the lowest emission rates, which were in the 0.00050 to 0.00140 lb/MMBtu range at the Naughton facility in Wyoming. One or two projects with low per mitted emission limits do not demonstrate that the FCPP can consistently achieve the same emission rate on a continuous basis. Even when a stack test showing compliance is available, this does not demonstrate that the project can achieve the specified permit limit on a long term basis. Stack tests are ty pically conducted within 180 days of startup when the air pollution control system is almost new and before the maximum number of catalyst layers have been installed, and hence are no t representative of how well the system will control emissions over time.

Figure 4-1 presents a block flow diagram of the planned e mission controls for Units 4 and 5. The flue gas exits the boiler system through the economizer, where heat is recovered by heating boiler feed water. When the SCR’s are installed, there will be an economizer bypass or a change in the economizer design to increase the flue gas temperature during start-up. This will allow ammonia (NH 3 

### ) for NO x 

### control to be added to the SCR sooner in th e start-up process. The SCR catalyst is ineffective without NH 3 

### and NH 3 

### cannot be added until the temperat ure is at a minimum to avoid ammonium bisulfate scalin g of the SCR system.
After the economizer and the injection of NH 3 

### , the flue gas passes through the SCR, where NOx reacts with NH 3 

### and is converted to nitrogen (N 2 

### ). The SCR also causes some SO 2 

### to be converted to SO 3 

### . Flue gas from the SCR passes through the ai r preheater, where heat is recovered by heating the combustion air. Because the flue gas tem perature drops as it passe s through the air preheater, there is some ammonium bisulfate and/or H 2 

### SO 4 

### mist deposition towards the back of the air preheater.

After the air preheater, DSI emission control system wi ll inject hydrated lime in order to control H 2 

### SO 4 

### mist emissions. The hydrated lime used in the DSI system will react with SO 3 

### , and some SO 2 

### , in the flue gas to form salts which can be removed in the fabric filter.

The fabric filter will remove the sulfur salts, unreacted lime and fly ash. In addition, some H 2 

### SO 4 

### mist will be removed by the cake on the bag surfaces.

Finally, the flue gas enters the we t flue gas desulfurization system. SO 2 

### and some additional SO 3 

### /H 2 

### SO 4 

### will be removed, as well as a minor amount of fine particulate that passed through the fabric filter. From the wet flue gas desulfurization system, the flue gas goes to the stack.AECOM Environment 4-17

60221977-460 April 2014 

### Figure 4-1 FCPP Air Pollution Control Equipment Block Flow Diagram Atmosphere (hydrated lime)

Wet Flue Gas Desulfurization Fabric Filter Stack Dry Sorbent Injection Bypass NH3 Injection

C oa l C onveyor Economizer Boiler

Air Preheater ( urea, 29% aqueous NH3 or anhydrous NH3)

Selective Catalytic ReductionAECOM Environment 5-1

60221977-460 April 2014 

# 5.0 Project Emission Summary

The emissions increases due to the SCR Retrofit Project are based on the differences between projected future emissions or potential emissions for new sources and baseline actual emissions as described in this section.



## 5.1 Coal Fired Boilers

5.1.1 Baseline Actual Emissions
Baseline emissions are based on the annual average e missions for a 24- month period within 5 years of the expected start of construction. APS has selected the January 2011 to December 2012 for the determination of baseline actual emissions. Baseline SO 2 

### , NO x 

### , and CO 2 

### emissions and fuel use are based on CEMS data from EPA’s Air Markets Program data base. Supplemental information such as stack test data for sulfuric acid mist and AP-42 factors for condensable PM 10 

### and PM 2.5 

### was also used to complete the baseline emission calculations. Table 5-1 presents a summary of the emission factor or average in pounds per million British thermal uni ts (lb/MMBtu) and the baseline emissions in tons per year (tpy) for Units 4 and 5. Detailed bas eline emission calculations for Units 4 and 5 are presented in Tables A-1.1 and A-1.2 in Appendix A.

The same procedures for the same January 2011 to December 2012 period were used to determine actual emission decreases due to the shutdown of Units 1, 2, and 3. Detailed actual emission calculations for Units 1, 2, and 3 are presented in Tables A-1.3 and A-1.4 in Appendix A.



## 5.1.2 Future Projected Emissions
Future projected emissions are based on the APS’s projections that the FCPP annual capacity factor may increase to 89.35% due to demand growth as show n in Appendix A, Table A-8. In addition, there will be a projected related increase in the utilizat ion of Units 4 and 5 due to the additional power needed to operate the SCR system and occasional by passing of the economizer. The SCR system is expected to increase fuel use by 0.3%, as shown in Appendix A, Table A-9, above the projected 89.35% utilization due to these paras itic power requirements. The e missions rates (lb/MMBtu) for all pollutants—other than NO x 

### , H 2 

### SO 4 

### , PM 10 

### , and PM 2.5 

### —are not expected to be affected by the project. Therefore, projected emission rates are for the post-project period —other than NO x 

### , H 2 

### SO 4 

### , PM 10 

### , and PM 2.5 

### —are the same as the baseline. The post-project NO x 

### rate will be significantly lower after the project because the SCR is designed to reduce NO x 

### . The post-project emission rates for H 2 

### SO 4 

### , PM 10 

### , and PM 2.5 

### are higher than in the baseline period as a result of the SCR operation. Projected future emissions for FCPP Units 4 and 5 are shown in Table 5-2 . An H 2 

### SO 4 

### source test report that was used in support of the calculations is provided in Appendix D.

Under 40 CFR §52.21(b)(41)(ii), in determining pr ojected actual emissi ons under paragraph (b)(41) the operator shall exclude, in calculating any increas e in emissions that results from the particular project, that portion of the unit's emissions foll owing the project that an existing unit could have accommodated during the consecutive 24-month per iod used to establish the baseline actual emissions under paragraph (b)(48) of this section and t hat are also unrelated to the particular project. All of the post-project emissions, except for the emissions associated with the increased heat inputAECOM Environment 5-2

60221977-460 April 2014 

### due to the parasitic power for the SCR and the increases in H 2 

### SO 4 

### , PM 10 

### , and PM 2.5 

### emission rates, are unrelated to the SCR retrofit project; and they also could have been accommodated in the baseline period because the SCR has no other impacts on the utilization of the unit or the emission
rates.



## 5.2 New Emission Sources

New sources of air emissions consist of silos for storage of the sorbents and reagents for dry sorbent injection and SCR. In addition, there will be an incr ease in road traffic for delivery of these sorbents and reagents.

The project will include a new silo for storage of hydr ated lime and, if urea is used for the SCR system, a second silo for urea storage. Emissions from the silos occur during pneumatic transfer of delivered materials from the delivery trucks to the silos. The sorbent and ur ea silos are sma ll emission sources with low flow rates, at or below 5,000 acfm. Th e new silos will have bin vent filter/baghouses for control of PM 10 

### and PM 2.5 

### emissions. PM 10 

### and PM 2.5 

### emissions will be limited to 0.0050 gr/scf and this rate will result in maximum annual emissi ons of 0.0029 tpy and 0.0071 tpy for the sorbent and urea silos, respectively.

The SCR Retrofit Project will increase on-site truck traffic due to the delivery of reagents for the DSI and SCR systems. Truck traffi c will increase fugitive PM 10 

### and PM 2.5 

### emissions from roadways. Dust controls at the FCPP include watering and sweeping as described in the FCPP’s Dust Control Plan as required by 40 CFR §49.5512(j). 13 

### Estimated maximum PM 10 

### and PM 2.5 

### emissions are 0.010 tpy and 0.090 tpy, respectively.

Emission calculations for these small sources are presented in Tables A-4 and A-5 in Appendix A.


## 5.3 PSD Applicability
The FCPP SCR Retrofit Project decreases NOx emissions from Units 4 and 5 by approximately 19,200 tpy. However, the addition of SCR will increase H 2 

### SO 4 

### mist emissions. The increase in H 2 

### SO 4 

### mist will be minimized by using dry sorbent injection. Overall, the Project will be subject to PSD for H 2 

### SO 4 

### mist as is shown in Table 3-3 and Table A-3 in Appendix A.

13 

### Dust Control Plan for Four Corners Steam Electric Station, Title V Operating Permit NN-ROP-05-07, November

19, 2012.AECOM Environment 5-3

60221977-460 April 2014 

## Table 5-1 Baseline Emission Summary for Units 4 and 5 (a )



### Pollutant Emission Factor or Average Emissions (lb/MMBtu) 24-Month Annual Average Emissions (tpy) Basis for Emission Factor or Annual Emissions

SO 2 

### 0.1722 8,373 CEMS, EPA Air Markets Program data

NOx 0.4941 24.029 CEMS, EPA Air Markets Program data

PM 0.0132 644.2 Annual PM Test & CEMS Heat Input

PM 10 

### 0.0165 801.3 92% of creditable filterable PM based on AP-42 Table 1.1-6 plus organic condensables at 20 % of 0.02 lb/MMBtu based on AP-42 Table 1.1-5 plus inorganic condensables equal to H2SO4 mist

PM 2.5 

### 0.0113 550.0 52% of creditable filterable PM based on AP-42 Table 1.1-6 plus organic condensables at 20 % of 0.02 lb/MMBtu based on AP-42 Table 1.1-5 plus inorganic condensables equal to H2SO4 mist

H 2 

### SO 4 

### 0.00029 14.1 2011 stack test

CO 0.0297 1,444 Fuel use and AP-42 Table 1.1-3 10/96

VOCs 0.00012 5.79 Fuel use and EPRI Emission Factor Handbook

Lead 2.36E-06 0.1148 Fuel use and EPRI Emission Factor Handbook

GHG as CO 2 

### e 206.8 10,058,133 CEMS, EPA Air Markets Program data

(a) 

### Baseline emissions are based on the annual average emissions for the 24-month period beginning on January 1, 2012 and ending December 31, 2012AECOM Environment 5-4

60221977-460 April 2014 

## Table 5-1 Projected Future Emission Calculation for Units 4 and 5

Parameter Value Units Comments

Pre-Project Heat Input 97,258, 307 MMBtu/yr See Table A 1.2
Post-Project Heat Input with Demand Growth without Parasitic Load and Economizer Inefficiency 116,008,264 MMBtu/yr 89.35% capacity factor, see table A-8

Heat Input to Demand Growth 18,749,957 MMBtu/yr

Increased Power Demand due to New Emission Controls 348,025 MMBtu/yr 0.3% (see Table A-9) of the future projected capacity factor of 89.35% (see Table A-8) which includes demand growth

Total Projected Future Fuel Use 116,356,289 MMBtu/yr Post-Project heat input including demand growth and increased power demand due to new emission controls
Total Projected Capacity Factor 89.61%
Projected Future Fuel Use Excluding Demand Growth 97,606,332 MMBtu/yr Pre-Project heat input plus increased power demand due to new emission controls
Projected Capacity Factor Excluding Demand Growth and Non-Project Related Changes 75.17%

SO 2 

### Emission Rate 0.1722 lb/MMBtu Same as baseline, no Project related change

SO 2 

### Emissions 8,403.2 tpy Based on projected Future Fuel Use Excluding Demand Growth

NO x 

### Emission Rate 0.0980 lb/MMBtu 40 CFR 49 BART Rule, 30-day rolling average

NO x 

### Emissions 4,782.7 tpy Based on projected Future Fuel Use Excluding Demand Growth
PM Emission Rate 0.0132 lb/MMBtu Same as baseline, no Project related change

PM Emissions 646.5 tpy Based on projected Future Fuel Use Excluding Demand Growth

PM 10 

### Emission Rate 0.0222 lb/MMBtu BACT - 92% of 0.015 lb/MMBtu plus 0.0040 lb/MMBtu condensable organics plus 0.00435 lb/MMBtu sulfuric acid mist emissions

PM 10 

### Emissions 1,288.9 tpy Total emi ssions including demand growth

Basis for Demand Growth Exclusion (c) 

### 0.0165 lb/MMBtu Baseline emission rate

Demand Growth Exclusion (c) 

### 154.47 tpy Baseline emission rate x demand growth

PM 10 

### Emissions 1,134.4 tpy Excluding non-Project related emissionsAECOM Environment 5-5

60221977-460 April 2014 

### PM 2.5 

### Emission Rate 0.0163 lb/MMBtu BACT - 53% of 0.015 lb/MMBtu plus 0.0040 lb/MMBtu condensable organics plus 0.00435 lb/MMBtu sulfuric acid mist emissions

PM 2.5 

### Emissions 948.5 tpy Total emissions including demand growth

Basis for Demand Growth Exclusion (c) 

### 0.0113 lb/MMBtu Baseline emission rate

Demand Growth Exclusion (c) 

### 106.04 tpy Baseline emission rate x demand growth

PM 2.5 

### Emissions. 842.5 tpy Excluding non-Project related emissions

Sulfuric Acid Mist Emission Rate 0.00435 lb/MMBtu See Table A-2
Sulfuric Acid Mist Emissions 253.29 tpy Total emissions including demand growth

Basis for Demand Growth Exclusion (c) 

### 0.00029 lb/MMBtu Baseline emission rate

Demand Growth Exclusion (c) 

### 2.72 tpy Baseline emission rate x demand growth
Sulfuric Acid Mist Emissions 250.6 tpy Excluding non-Project related emissions
CO Emission Rate 0.02969 lb/MMBtu Same as baseline, no Project related change

CO Emissions 1,449.0 tpy Based on projected Future Fuel Use Excluding Demand Growth

VOC Emission Rate 0.000119 lb/MMBtu Same as baseline, no Project related change

VOC Emissions 5.81 tpy Based on projected Future Fuel Use Excluding Demand Growth

Lead Emission Rate 2.36E-06 lb/MMBtu Same as baseline, no Project related change

Lead Emissions 0.115 tpy Based on projected Future Fuel Use Excluding Demand Growth

CO 2 

### Emission Rate 205.2 lb/MMBtu Same as baseline, no Project related change

CO 2 

### Emissions 10,013,236 tpy Based on projected Future Fuel Use Excluding Demand Growth

CO 2 

### e Emission Rate 206.8 lb/MMBtu Same as baseline, no Project related change

CO 2 

### e Emissions 10,094,124 tpy Based on projected Future Fuel Use Excluding Demand Growth

(a) Projected actual emissions do not include exclusions allowe d by 40 CFR 52.21(b)(41)(ii): "In determining projected actua l emissions under paragraph (b)(41) the operator shall exclude, in calculat ing any increase in emissions that results from the particular project, that portion of the unit's emissions following the project that an existing unit could have accommodated during the consecutive 24-m onth period used to establish the baseline actual emissions under paragra ph (b)(48) of this section and that are also unrelated to t he particular project, including any increased utilization due to product demand growth. (b) The auxiliary load, in terms of increased fuel use, is based on occasional or periodic increased firing to compensate for SCR power use and economizer bypass which result in lower net power output. See Table A-9. (c) Emissions from demand growth at the baseline emissi on rate are "unrelated to the particular project".AECOM Environment

60221977-460 April 2014 6-1



# 6.0 Endangered Species Act Impact Analysis

The San Juan River basin is located within the Colorado Plateau Major Land Resource Area 35 (Natural Resources Conservation Service [NRCS ] 2006), which encompasses western New Mexico, northern Arizona, and south-central Utah. The average annual precipitation ranges from 6 to 18 inches in most of this area. About half of the precipitat ion falls from July through September. The San Juan River basin in the part of this area in northwest Ne w Mexico has the highest streamflow volume in the state, relying almost entirel y on surface water (NRCS 2006).
The soils of the San Juan River basin have been prin cipally developed by weathering of the underlying parent material, including shale, sandstone, limestone, dolomite, and volcanic rock, as well as aeolian deposits, alluvium, and colluvium. As a result of the arid climate, the soils are poorly developed, retaining many of the geochemical characteristics of the parent material, mainly volcanic in the mountains and late Paleozoic to recent sedimentary rocks in the va lleys overlain by alluvium on floodplains and terraces.
In order to define the endangered species that may be affected by future FCPP emissions with the addition of SCRs, the area likely to be affect ed was delineated using dispersion and deposition modeling for the EIS that is being prepared concu rrently with this PSD application. The CALPUFF model was applied within a 100-km radius of the FCPP to simulate dispersion and deposition of selected metals that are primary ecological risk driver s to estimate the contribution of future continuous full load operations of the FCPP units (4 and 5) for 25 years to surface soil concentrations in the region. The metals used for evaluation were derived from a study by EPRI (2011) which identified the metals from coal-fired power plants that typically contri bute most to ecological risk (arsenic, cadmium, chromium, and mercury), in addition to antimony, lead, copper, and selenium because the ecological toxicity of each has been widely studied. The predict ed surface soil concentrations of the selected metals deposited on the soil were compared to the esti mated existing soil conc entrations derived from the PLUTO database for San Juan County, New Mexico (USGS 2012). The future surface soil concentrations of each metal calculated to accumu late over 25 years were computed (based on CALPUFF modeling) and compared to the corresponding 95 th 

### percent upper confidence limit (95UCL) of the soil concentrations derived from the PLUT O data. The resulting Deposition Area, shown in Figure 6-1 was determined by delineating the area where the predicted future increase (after 25 years of future full load plant operations) in soil concentrati on of any of the metals is projected to be more than one percent of current concentrations. Beyond this area, the very small increase in soil concentration would be sufficiently low to be considered discountable 14



### .

14 

### Using a percentage of background as a threshold for deposited metals is consistent with the acidic deposition screening approach established by the Federal Land Manager’s Air Quality Related Values Work Group (FLAG 2011). Given that the FLAG Deposition Analysis Threshold is based on 2 percent of natural background rather than measured background, a one percent threshold of measured soil concentration was determined to be a conservative screening threshold. Any soil concentration with an accumulation of less than one percent of background under future conditions (25 years of accumulation) was determined to be discountable.AECOM Environment60221977-460April 20146-2Figure 6-1 Deposition Area for the ESA AnalysisAECOM Environment

60221977-460 April 2014 

### 6

- 3



### Based on the Southwest Regional Gap Analysis Project (SWReGAP) (Lowry et. al 2005), five vegetation cover types account for approximately 80 percent of the Deposition Area, which is approximately 1,800 square km: Inter-Mountain Basi ns Semi-Desert Grassland (23%), Inter-Mountain Basins Mixed Salt Desert Scrub (20%), Colo rado Plateau Mixed Bedrock Canyon and Tableland (13%), Agriculture (12%), and Inter-Mountain Basins Semi-Desert Shrub Steppe (10%). Dominant plant species within these cover types include a variety of grasses (galleta [ Pleuraphis jamesii ], Indian ricegrass [ Stipa hymenoides ]), and shrubs (saltbush [ Atriplex sp.], shadscale [ Atriplex confertifolia ], rabbitbrush [ Chrysothamnus sp.]).

Over 300 birds and mammals have the potential to o ccur within the Deposition Area. Based on the Habitat Model (AECOM 2013a) prepared in suppor t of the EIS and Endangered Species Act (ESA) Section 7 consultation, federally listed species with potential habitat that may occur within the Deposition Area include the following two plants, three birds, and two fish:

 Mesa Verde cactus ( Sclerocactus mesae-verdae )

 Mancos milk-vetch ( Astragalus humillimus )

 Mexican spotted owl ( Strix occidentalis lucida )

 Southwestern willow flycatcher ( Empidonax traillii extimus ),

 Yellow-billed cuckoo ( Coccyzus americanus )

 Colorado pikeminnow ( Ptychocheilus lucius )

 Razorback sucker ( Xyrauchen texanus )

It should be noted that the availability of suitable habitat does not necessarily indicate that the species is present. The only designated critic al habitat for federally listed spec ies within the Deposition Area is the Colorado pikeminnow and razorback sucker habitat in the San Juan River (59 Federal Register 13399-13400 [FR DOC # 94-6508] March 21, 1994)..

The soils within the Deposition Area are alkaline (m ost with a pH greater than 8.0), with low organic matter content (most less than 1%), and well-drained (less than 1% poorly drained). Typical soil depths range from shallow to deep (NRCS 2008a, 200 8b, 2009). Soil acidity affects the chemical properties and leaching potential of metals because me tals are less soluble in water as pH increases, making them less available for uptake by plants and animals.

To predict the amount of acid deposition likely to resu lt from 25 years of full load operations of Units 4 and 5 with SCRs, AECOM used the same dispersion and deposition modeling that was applied to predict future metal deposition within the Deposit ion Area. After taking into account the total deposition of all acid-generating compounds (H 2 

### SO 4 

### , SO 2 

### , NOx, HCl, and hydrogen fluoride [HF]), the model predicted a maximum deposition of 0.0047 hydronium ion equivalents per square meter.

To determine whether the quantity of acid depositi on coming from the FCPP would affect the pH of the soils within the Deposition Area, a comparison of the soil acid neutralizing capacity (ANC) to the maximum deposition amount was conducted. Using t he lowest ANC from soil samples, collected in support of the ERA prepared for the EIS and ESA Section 7 consultation (AECOM 2013b), it was determined that acid deposition from the FCPP would ut ilize no more than 3 percent of the ANC of theAECOM Environment

60221977-460 April 2014 

### 6

- 4



### soil with the lowest potential to buffer the acid. It was concluded that the so il within the Deposition Area has the ability to accept much more ac idic deposition than would be generated by FCPP emissions and would not be affected by Projec t emissions. Because th e small amount of acid deposition in water bodies would be diluted by flowing water and deposition on plants would not accumulate over a long period of time, no adverse effects on soils, water bodies, animals and plants (including endangered species), or the ecosystem woul d result from Project-related emissions.

The future operations of Units 4 and 5 with SCRs we re shown in the Draft EIS to be well below both the primary and secondary NAAQS for PM 10 

### and PM 2.5 

### even without accounting for the overall decrease in PM emissions related to the shutdown of Units 1, 2, and 3. Because the air quality standards for PM 10 

### and PM 2.5 

### will not be exceeded due to future op erations of Units 4 and 5, it can be concluded that the increase in H 2 

### SO 4 

### mist along with the overall decr ease in PM and other pollutant emissions will not adversely affect the environm ent or the populations and habitat of listed species within the Deposition Area.AECOM Environment

60221977-460 April 2014 

### 7- 1



# 7.0 References

AECOM, 2013b. Four Corners Power Plant and Navajo Mine Energy Project Ecological Risk Assessment. AECOM Environment. July 15.

[United States] Environmental Protection Agen cy (EPA). Clean Air Act Permitting for Greenhouse Gases. http://www.epa.gov /nsr/ghgpermitting.html

EPA, 2010. Source Specific Federal Implementation Plan for Implementing Best Available Retrofit Technology for Four Corners Power Plant: Navajo Nation, available at http://federal.eregulations.us/rulema king/document/EPA-R09-OAR-2010-0683-0002.

EPA, 2005a. Guideline on Air Quality Models (as incorportated in Appendix W of 40 CFR Part 51).

EPA, 2005b. Regional Haze Regulations and Guidelin es for Best Available Retrofit Technology (BART) Determinations; Final Rule. 40 CFR Pa rt 51.FRL–7925–9. U.S. Environmental Protection Agency, Research Triangle Park, North Caro lina 27711. Federal Register, July 6, 2005. http://www.gpo.gov/fdsys/pkg /FR-2005-07-06/pdf/05-12526.pdf

EPA, 2002. EPA Air Pollution Cost Control Manual. EPA/452/B-02-001. U.S. Environmental Protection Agency, Research Tri angle Park, North Carolina 27711.

EPA, 1998. Compilation of Air Pollutant E mission Factors (AP-42), Section 1.1.3.2.

EPA, 1990. New Source Review Workshop Manual. October, Draft. Accessed at http://www.epa.gov/NSR/tt nnsr01/gen/wkshpman.pdf

FLAG, 2010. Federal Land Manager’s Air Quality Rela ted Values Work Group (FLAG) Phase I Report – Revised (2010); Natural Resources Re port NPS/NRPC/NRR-2010/232. Available at http://www.nature/nps.gov/a ir/pubs/pdf/flag/FLAG_2010.pdf

NRCS, 2008a. Soil Survey Geographic (SSURGO) da tabase for Shiprock Area, Parts of San Juan County, New Mexico and Apache County, Arizona. So il Survey Area NM 717. U.S. Department of Agriculture. Fort Worth, December 9. URL:http://SoilDataMart.nrcs.usda.gov/.

NRCS, 2008b. Soil Survey Geographic (SSURGO) database for Ute Mountain Area, Colorado and New Mexico. Soil Survey Area CO 670. U.S. Depar tment of Agriculture. Fort Worth, January 28. URL:http://SoilDataMart.nrcs.usda.gov/.

NRCS, 2006. Land Resource Regions and Major Land Re source Areas of the United States, the Caribbean, and the Pacific Basin. United States Department of Agriculture Handbook 296. Third Edition.AECOM Environment

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### 7- 2



### Office of Surface Mining Reclamation and Enforcem ent, 2014. Draft Environmental Impact Statement for the Four Corners Power Plant and Navajo Mine Energy Project, Navajo Nation, New Mexico. March.

Sewell, M. R. and J. Dickerman, 2012. Dry Sorbent Injection Options for Controlling Emissions of HCl and Related Acid Gases, Lhoist North America, TAPPI Peers Conference 2012.

United States Geological Survey (USGS). 2012. G eochemistry of soils in the US from the PLUTO database. Reston, VA. URL: http://tin.er.usgs. gov/pluto/soil/. Accessed July 30, 2012.AECOM Environment

60221977-460 April 2014 

# Appendix A

Emission CalculationsAppendix A Table of ContentsEmission CalculationsTable A-1.1 Monthly Baseline Emissions - Units 4 and 5Table A-1.2 Annual Average Emissions based on Rolling 24-Month Average -Units 4 and 5 (a)Table A-1.3 Monthly Baseline Emissions - Units 1, 2, and 3Table A-1.4 Annual Average Emissions based on Rolling 24-Month Average -Units 1, 2, and 3 (a)Table A-2 Future Sulfuric Acid Mist Emission Calculation for Units 4 and 5Table A-3 Projected Future Emission Calculation for Units 4 and 5 (a)Table A-4 Projected Emission Increase Calculation for Reagent HandlingTable A-5.1 Projected Emission Increase Calculation for Reagent Delivery (DSIand 29% Aqueous Ammonia)Table A-5.2 Projected Emission Increase Calculation for Reagent Delivery (DSIand Urea Pellets)Table A-5.3 Projected Emission Increase Calculation for Reagent Delivery (DSIand Anhydrous Ammonia)Table A-6 FOUR CORNERS Unit 4 and Unit 5 SCR Project PSD ApplicabilityTable A-7 FOUR CORNERS Unit 4 and Unit 5 SCR Project Tribal Minor SourceNSR Applicability (a)Table A-8 FCPP Projected Capacity Factors including Demand Growth and NonProject Related FactorsTable A-9 Estimated Increased Fuel Use due to SCR Parasitic Load andEconomizer BypassTableA‐1.1MonthlyBaselineEmissionsMonth Unit ID SO2 Ratelb/MMBtuSO2tonsNOx Ratelb/MMBtuNOxtonsPMlb/MMBtuPMtonsPM10lb/MMBtuPM10tonsPM2.5lb/MMBtuPM2.5tonsH2SO4Mistlb/MMBtuH2SO4MisttonsCOlb/MMBtuCOtonsVOCslb/MMBtuVOCstonsLeadlb/MMBtuLeadtonsGHGslbCO2e/MMBtuGHGstons CO2eCO2tonsHeat InputMMBtuJanuary-10 Unit 4 0.1848144.100.445379.350.00705.460.01078.370.00806.240.000290.230.03023.151.19E-04 0.093 2.36E-06 1.84E-03 206.6161,105159,8121,559,614February-10 Unit 4 0.00 0.00 0.00700.00 0.01070.00 0.00800.00 0.000290.00 0.0300.00 1.19E-04 0.000 2.36E-06 0.00E+00 0.00 0.00 0.00March-10 Unit 4 0.00 0.00 0.00700.00 0.01070.00 0.00800.00 0.000290.00 0.0300.00 1.19E-04 0.000 2.36E-06 0.00E+00 0.00 0.00 0.00April-10 Unit 4 0.2654203.750.306293.610.00705.370.01078.240.00806.140.000290.220.03022.79 1.19E-04 0.091 2.36E-06 1.81E-03 206.9158,791157,5181,535,210May-10 Unit 4 0.1478341.480.4581,068.940.007016.170.010724.790.008018.480.000290.670.03068.60 1.19E-04 0.275 2.36E-06 5.45E-03 206.9477,955474,1254,620,786June-10 Unit 4 0.1668378.630.4721,084.010.007015.890.010724.360.008018.160.000290.660.03067.41 1.19E-04 0.270 2.36E-06 5.36E-03 206.8469,573465,8104,541,048July-10 Unit 4 0.1722301.270.461842.040.007012.240.010718.770.008013.990.000290.510.03051.93 1.19E-04 0.208 2.36E-06 4.13E-03 206.9361,796358,8973,498,104August-10 Unit 4 0.1501217.880.443699.180.007010.160.010715.580.008011.610.000290.420.03043.11 1.19E-04 0.173 2.36E-06 3.43E-03 206.7300,060297,6532,903,747September-10 Unit 4 0.1417341.700.4871,177.840.007016.880.010725.870.008019.290.000290.700.03071.58 1.19E-04 0.287 2.36E-06 5.69E-03 207.0498,991494,9954,821,725October-10 Unit 4 0.1535362.080.4721,119.620.007016.510.010725.310.008018.870.000290.680.03070.04 1.19E-04 0.281 2.36E-06 5.57E-03 206.9488,064484,1554,717,870November-10 Unit 4 0.2209485.940.5041,133.550.007015.400.010723.600.008017.600.000290.640.03065.31 1.19E-04 0.262 2.36E-06 5.19E-03 206.7454,600450,9544,399,453December-10 Unit 4 0.2290315.900.429631.110.00709.660.010714.800.008011.040.000290.400.03040.96 1.19E-04 0.164 2.36E-06 3.26E-03 206.8285,324283,0372,759,319January-11 Unit 4 0.1890455.360.4961,204.260.011026.500.014434.720.010124.380.000290.700.03071.54 1.19E-04 0.287 2.36E-06 5.69E-03 206.6497,874493,8814,818,978February-11 Unit 4 0.1853363.680.452921.030.011021.590.014428.290.010119.870.000290.570.03058.28 1.19E-04 0.234 2.36E-06 4.63E-03 206.9406,054402,8013,926,055March-11 Unit 4 0.1675354.790.463993.870.011023.300.014430.530.010121.440.000290.610.03062.90 1.19E-04 0.252 2.36E-06 5.00E-03 206.8438,004434,4934,236,866April-11 Unit 4 0.1877442.930.4811,138.340.011025.960.014434.010.010123.880.000290.680.03070.07 1.19E-04 0.281 2.36E-06 5.57E-03 206.5487,453483,5414,720,085May-11 Unit 4 0.1565376.890.4861,178.200.011026.480.014434.690.010124.370.000290.700.03071.49 1.19E-04 0.287 2.36E-06 5.68E-03 206.6497,333493,3434,815,280June-11 Unit 4 0.1544360.040.4981,172.060.011025.660.014433.610.010123.610.000290.680.03069.26 1.19E-04 0.278 2.36E-06 5.50E-03 206.8482,383478,5174,665,251July-11 Unit 4 0.1563392.940.5101,288.240.011027.660.014436.230.010125.440.000290.730.03074.65 1.19E-04 0.299 2.36E-06 5.93E-03 206.6519,432515,2655,028,511August-11 Unit 4 0.1557345.560.4741,094.550.011024.410.014431.980.010122.460.000290.640.03065.89 1.19E-04 0.264 2.36E-06 5.24E-03 206.8459,015455,3364,438,588September-11 Unit 4 0.1492317.950.456987.890.011023.440.014430.710.010121.570.000290.620.03063.27 1.19E-04 0.254 2.36E-06 5.03E-03 206.9440,975437,4434,262,185October-11 Unit 4 0.1866149.750.471395.980.01108.830.014411.570.01018.120.000290.230.03023.83 1.19E-04 0.096 2.36E-06 1.89E-03 206.8165,996164,6661,605,241November-11 Unit 4 0.2083102.720.372205.290.01105.430.01447.110.01014.990.000290.140.03014.64 1.19E-04 0.059 2.36E-06 1.16E-03 207.1102,130101,313986,383December-11 Unit 4 0.1643403.490.4451,092.240.011027.020.014435.400.010124.860.000290.710.03072.93 1.19E-04 0.292 2.36E-06 5.80E-03 207.0508,393504,3214,912,582January-12 Unit 4 0.1759418.090.4611,099.050.026061.790.028267.040.018142.940.000290.690.03070.56 1.19E-04 0.283 2.36E-06 5.61E-03 206.7491,306487,3674,752,868February-12 Unit 4 0.1850413.100.4641,039.450.026058.060.028263.000.018140.350.000290.650.03066.31 1.19E-04 0.266 2.36E-06 5.27E-03 206.9462,088458,3874,466,424March-12 Unit 4 0.1688276.630.421732.400.026042.600.028246.230.018129.610.000290.480.03048.65 1.19E-04 0.195 2.36E-06 3.87E-03 206.8338,813336,0973,277,307April-12 Unit 4 0.1446182.690.450598.360.026032.850.028235.650.018122.830.000290.370.03037.52 1.19E-04 0.150 2.36E-06 2.98E-03 206.9261,495259,4002,527,269May-12 Unit 4 0.1276196.390.479779.950.026040.020.028243.420.018127.810.000290.450.03045.70 1.19E-04 0.183 2.36E-06 3.63E-03 206.8318,343315,7923,078,124June-12 Unit 4 0.1142225.120.5011,016.080.026051.250.028255.610.018135.620.000290.570.03058.53 1.19E-04 0.235 2.36E-06 4.65E-03 206.9407,899404,6323,942,563July-12 Unit 4 0.1215234.250.456922.650.026050.130.028254.390.018134.840.000290.560.03057.25 1.19E-04 0.229 2.36E-06 4.55E-03 206.8398,777395,5813,856,303August-12 Unit 4 0.1131175.750.491820.870.026040.410.028243.840.018128.080.000290.450.03046.14 1.19E-04 0.185 2.36E-06 3.67E-03 206.9321,484318,9083,108,086September-12 Unit 4 0.1216310.370.5401,382.270.026066.380.028272.020.018146.130.000290.740.03075.80 1.19E-04 0.304 2.36E-06 6.03E-03 206.7527,718523,4875,106,082October-12 Unit 4 0.1384367.720.5331,421.440.026069.100.028274.980.018148.030.000290.770.03078.92 1.19E-04 0.316 2.36E-06 6.27E-03 206.4548,626544,2215,315,754November-12 Unit 4 0.1537337.980.5511,236.070.026057.160.028262.020.018139.730.000290.640.03065.28 1.19E-04 0.262 2.36E-06 5.19E-03 206.7454,485450,8414,397,283December-12 Unit 4 0.1858468.800.5401,366.600.026065.600.028271.180.018145.590.000290.730.03074.91 1.19E-04 0.300 2.36E-06 5.95E-03 206.8521,851517,6695,046,099January-13 Unit 4 0.1833439.560.5221,265.770.00409.590.008019.110.006415.370.000290.700.03071.20 1.19E-04 0.285 2.36E-06 5.66E-03 206.9496,115492,1404,796,076February-13 Unit 4 0.1639291.840.5521,018.100.00407.120.008014.190.006411.410.000290.520.03052.87 1.19E-04 0.212 2.36E-06 4.20E-03 207.0368,571365,6193,561,508March-13 Unit 4 0.1438299.550.5121,103.140.00408.330.008016.600.006413.350.000290.600.03061.83 1.19E-04 0.248 2.36E-06 4.91E-03 206.9430,938427,4874,165,091April-13 Unit 4 0.122579.660.465305.600.00402.600.00805.180.00644.170.000290.190.03019.31 1.19E-04 0.077 2.36E-06 1.53E-03 206.8134,492133,4141,300,528May-13 Unit 4 0.1753255.520.461747.390.00405.830.008011.620.00649.340.000290.420.03043.27 1.19E-04 0.173 2.36E-06 3.44E-03 206.8301,391298,9752,914,866June-13 Unit 4 0.1471347.030.5181,236.890.00409.440.008018.800.006415.120.000290.680.03070.05 1.19E-04 0.281 2.36E-06 5.57E-03 207.0488,421484,5104,718,818July-13 Unit 4 0.1241229.010.492947.630.00407.380.008014.700.006411.830.000290.540.03054.78 1.19E-04 0.220 2.36E-06 4.35E-03 206.8381,567378,5093,689,821August-13 Unit 4 0.1275308.930.4971,210.290.00409.690.008019.310.006415.530.000290.700.03071.92 1.19E-04 0.288 2.36E-06 5.72E-03 206.7500,706496,6914,844,520September-13 Unit 4 0.1480236.360.522853.350.00406.390.008012.730.006410.240.000290.460.03047.42 1.19E-04 0.190 2.36E-06 3.77E-03 206.9330,480327,8333,194,475October-13 Unit 4 0.1551280.620.5481,017.720.00407.240.008014.420.006411.600.000290.520.03053.73 1.19E-04 0.215 2.36E-06 4.27E-03 206.8374,226371,2273,619,423November-13 Unit 4 0.1435327.440.5281,213.180.00409.130.008018.190.006414.630.000290.660.03067.77 1.19E-04 0.272 2.36E-06 5.39E-03 206.8471,927468,1444,564,807December-13 Unit 4 0.1869221.050.512645.350.00404.730.00809.430.00647.580.000290.340.03035.13 1.19E-04 0.141 2.36E-06 2.79E-03 206.9244,801242,8412,366,028January-10 Unit 5 0.1901510.560.4811,292.900.008021.490.011731.290.008522.910.000290.780.03079.75 1.19E-04 0.320 2.36E-06 6.34E-03 206.7555,096550,6445,371,675February-10 Unit 5 0.1825432.940.5031,192.640.008018.980.011727.630.008520.230.000290.690.03070.43 1.19E-04 0.282 2.36E-06 5.60E-03 206.6490,119486,1884,743,915March-10 Unit 5 0.1672441.880.4881,291.270.008021.150.011730.790.008522.550.000290.770.03078.48 1.19E-04 0.315 2.36E-06 6.24E-03 206.7546,470542,0895,286,548April-10 Unit 5 0.1804449.870.4801,221.960.008019.950.011729.060.008521.280.000290.720.03074.05 1.19E-04 0.297 2.36E-06 5.89E-03 206.7515,563511,4294,988,314May-10 Unit 5 0.1618428.760.4891,298.300.008021.200.011730.870.008522.600.000290.770.03078.67 1.19E-04 0.315 2.36E-06 6.25E-03 206.7547,825543,4345,299,405June-10 Unit 5 0.1857287.060.471772.950.008012.360.011718.010.008513.180.000290.450.03045.89 1.19E-04 0.184 2.36E-06 3.65E-03 206.9319,735317,1733,091,132July-10 Unit 5 0.1680364.430.5181,143.210.008017.350.011725.270.008518.500.000290.630.03064.39 1.19E-04 0.258 2.36E-06 5.12E-03 206.8448,462444,8674,337,411August-10 Unit 5 0.1366268.060.501988.140.008015.700.011722.860.008516.740.000290.570.03058.25 1.19E-04 0.233 2.36E-06 4.63E-03 207.0406,147402,8953,923,978September-10 Unit 5 0.1473347.360.4941,193.650.008018.860.011727.470.008520.110.000290.680.03070.01 1.19E-04 0.281 2.36E-06 5.56E-03 206.7487,276483,3684,715,560October-10 Unit 5 0.1708432.560.5051,285.850.008020.250.011729.500.008521.600.000290.730.03075.17 1.19E-04 0.301 2.36E-06 5.98E-03 206.8523,600519,4045,063,590November-10 Unit 5 0.2370596.150.5301,335.460.008020.120.011729.300.008521.460.000290.730.03074.68 1.19E-04 0.299 2.36E-06 5.94E-03 206.6519,740515,5715,030,752December-10 Unit 5 0.2197476.560.4901,090.300.008017.350.011725.270.008518.500.000290.630.03064.41 1.19E-04 0.258 2.36E-06 5.12E-03 206.5447,887444,2914,338,387January-11 Unit 5 0.2615571.180.4721,077.500.010021.840.013529.470.009620.950.000290.630.03064.86 1.19E-04 0.260 2.36E-06 5.16E-03 207.1452,326448,7054,368,754February-11 Unit 5 0.2430540.970.4701,052.130.010022.260.013530.030.009621.350.000290.650.03066.10 1.19E-04 0.265 2.36E-06 5.25E-03 207.1460,985457,2954,452,798March-11 Unit 5 0.2039432.690.440967.570.010021.220.013528.620.009620.350.000290.620.03062.99 1.19E-04 0.252 2.36E-06 5.01E-03 207.1439,421435,9044,243,254April-11 Unit 5 0.2460127.660.460242.510.01005.190.01357.000.00964.980.000290.150.03015.41 1.19E-04 0.062 2.36E-06 1.22E-03 207.0107,432106,5711,038,010May-11 Unit 5 0.2125186.380.382393.310.01008.770.013511.830.00968.410.000290.250.03026.04 1.19E-04 0.104 2.36E-06 2.07E-03 206.8181,395179,9421,754,094June-11 Unit 5 0.1737356.920.455971.580.010020.550.013527.730.009619.710.000290.600.03061.02 1.19E-04 0.245 2.36E-06 4.85E-03 206.8425,087421,6804,110,498July-11 Unit 5 0.1364316.030.4841,151.450.010023.160.013531.250.009622.210.000290.670.03068.78 1.19E-04 0.276 2.36E-06 5.47E-03 206.8479,119475,2794,632,886TableA‐1.1MonthlyBaselineEmissionsMonth Unit ID SO2 Ratelb/MMBtuSO2tonsNOx Ratelb/MMBtuNOxtonsPMlb/MMBtuPMtonsPM10lb/MMBtuPM10tonsPM2.5lb/MMBtuPM2.5tonsH2SO4Mistlb/MMBtuH2SO4MisttonsCOlb/MMBtuCOtonsVOCslb/MMBtuVOCstonsLeadlb/MMBtuLeadtonsGHGslbCO2e/MMBtuGHGstons CO2eCO2tonsHeat InputMMBtuAugust-11 Unit 5 0.1207183.450.477757.430.010015.190.013520.500.009614.570.000290.440.03045.11 1.19E-04 0.181 2.36E-06 3.59E-03 206.8314,208311,6903,038,607September-11 Unit 5 0.1452351.510.5041,239.080.010024.210.013532.660.009623.220.000290.700.03071.88 1.19E-04 0.288 2.36E-06 5.71E-03 206.8500,664496,6514,841,997October-11 Unit 5 0.2062509.160.5081,257.370.010024.690.013533.310.009623.680.000290.720.03073.32 1.19E-04 0.294 2.36E-06 5.83E-03 206.9510,950506,8574,938,771November-11 Unit 5 0.2189547.630.5141,286.260.010025.020.013533.750.009623.990.000290.730.03074.28 1.19E-04 0.298 2.36E-06 5.90E-03 206.6516,928512,7815,003,720December-11 Unit 5 0.2282580.670.5221,328.990.010025.440.013534.320.009624.400.000290.740.03075.54 1.19E-04 0.303 2.36E-06 6.00E-03 207.0526,588522,3715,088,454January-12 Unit 5 0.2235577.320.5181,339.210.006015.500.009825.340.007519.300.000290.750.03076.70 1.19E-04 0.307 2.36E-06 6.10E-03 206.8534,207529,9265,166,560February-12 Unit 5 0.2213527.710.4981,189.910.006014.310.009823.390.007517.810.000290.690.03070.79 1.19E-04 0.284 2.36E-06 5.63E-03 207.1493,911489,9594,768,715March-12 Unit 5 0.2142443.340.4791,026.490.006012.420.009820.300.007515.460.000290.600.03061.45 1.19E-04 0.246 2.36E-06 4.88E-03 207.1428,613425,1824,139,506April-12 Unit 5 0.2052237.620.479566.120.00606.950.009811.360.00758.650.000290.340.03034.37 1.19E-04 0.138 2.36E-06 2.73E-03 207.1239,733237,8142,315,397May-12 Unit 5 0.1773254.490.427631.290.00608.610.009814.080.007510.720.000290.420.03042.62 1.19E-04 0.171 2.36E-06 3.39E-03 206.9296,972294,5932,870,813June-12 Unit 5 0.1479295.040.457927.830.006011.970.009819.570.007514.900.000290.580.03059.24 1.19E-04 0.237 2.36E-06 4.71E-03 206.8412,579409,2723,990,395July-12 Unit 5 0.1192307.530.4751,233.960.006015.480.009825.300.007519.270.000290.750.03076.59 1.19E-04 0.307 2.36E-06 6.09E-03 206.7533,304529,0295,158,952August-12 Unit 5 0.1225274.150.4811,098.170.006013.420.009821.950.007516.710.000290.650.03066.43 1.19E-04 0.266 2.36E-06 5.28E-03 206.8462,645458,9374,474,533September-12 Unit 5 0.1384338.740.4971,230.920.006014.690.009824.010.007518.280.000290.710.03072.67 1.19E-04 0.291 2.36E-06 5.78E-03 206.8506,086502,0294,895,140October-12 Unit 5 0.1746459.170.5201,372.250.006015.780.009825.800.007519.650.000290.760.03078.09 1.19E-04 0.313 2.36E-06 6.21E-03 207.0544,583540,2245,260,406November-12 Unit 5 0.1991413.350.4851,023.640.006012.460.009820.370.007515.510.000290.600.03061.64 1.19E-04 0.247 2.36E-06 4.90E-03 207.0429,816426,3754,152,108December-12 Unit 5 0.1909240.790.460606.330.00607.570.009812.370.00759.420.000290.370.03037.44 1.19E-04 0.150 2.36E-06 2.98E-03 206.8260,790258,6992,522,078January-13 Unit 5 0.2218527.810.4611,117.900.00409.520.008018.960.006415.250.000290.690.03070.64 1.19E-04 0.283 2.36E-06 5.61E-03 207.0492,487488,5434,758,392February-13 Unit 5 0.2351364.700.457723.950.00406.200.008012.360.00649.940.000290.450.03046.06 1.19E-04 0.185 2.36E-06 3.66E-03 206.9320,896318,3253,102,447March-13 Unit 5 0.2069413.480.476972.500.00408.000.008015.930.006412.810.000290.580.03059.35 1.19E-04 0.238 2.36E-06 4.72E-03 206.7413,260409,9473,997,684April-13 Unit 5 0.1911324.970.511912.120.00406.800.008013.550.006410.900.000290.490.03050.49 1.19E-04 0.202 2.36E-06 4.01E-03 206.9351,893349,0753,400,890May-13 Unit 5 0.2035364.280.483898.050.00407.160.008014.270.006411.470.000290.520.03053.15 1.19E-04 0.213 2.36E-06 4.22E-03 207.0370,430367,4633,579,894June-13 Unit 5 0.1381249.350.526983.570.00407.220.008014.390.006411.580.000290.520.03053.62 1.19E-04 0.215 2.36E-06 4.26E-03 206.8373,509370,5153,611,634July-13 Unit 5 0.1299192.020.514791.240.00405.910.008011.780.00649.470.000290.430.03043.88 1.19E-04 0.176 2.36E-06 3.49E-03 207.0305,923303,4732,955,782August-13 Unit 5 0.1284284.340.4811,082.330.00408.860.008017.640.006414.190.000290.640.03065.73 1.19E-04 0.263 2.36E-06 5.22E-03 206.7457,500453,8314,427,704September-13 Unit 5 0.1515235.980.478767.800.00406.230.008012.410.00649.980.000290.450.03046.24 1.19E-04 0.185 2.36E-06 3.68E-03 206.6321,769319,1883,114,408October-13 Unit 5 0.2097463.570.5081,139.720.00408.840.008017.620.006414.170.000290.640.03065.64 1.19E-04 0.263 2.36E-06 5.22E-03 206.9457,415453,7514,421,401November-13 Unit 5 0.1862393.720.5331,129.190.00408.460.008016.850.006413.550.000290.610.03062.77 1.19E-04 0.252 2.36E-06 4.99E-03 206.9437,422433,9194,227,961December-13 Unit 5 0.181997.350.504272.430.0042.140.00804.270.00643.430.000290.160.03015.89 1.19E-04 0.064 2.36E-06 1.26E-03 206.7110,645109,7581,070,415Emission Basis and/or Emission FactorsSO2, lb/MMBtu Calculated from SO2 (tons) and heat input (MMBtu)SO2, tons CEMS, EPA Air Markets Program DataNOx, lb/MMBtu CEMS, EPA Air Markets Program DataNOx, tons CEMS, EPA Air Markets Program DataPM, lb/MMBtu Annual stack testing, see belowPM, tons PM (lb/MMBtu) and heat input (MMBtu)92% of filterable PM, AP-42 Table 1.1-5, Baghouse+PM10 condensable inorgnaics (sulfuric acid mist)+PM10 condensable organics (20% of 0.02 lb/MMBtu based on AP-42 Table 1.1-553% of filterable PM, AP-42 Table 1.1-5, Baghouse+PM2.5 condensable inorgnaics (sulfuric acid mist)+PM2.5 condensable organics (20% of 0.02 lb/MMBtu based on AP-42 Table 1.1-5Sulfuric acid mist, lb/MMBtu 0.00029 lb/MMBtu based on 2011 stack testCO, lb/MMBtu 0.5 lb/ton of coal based on AP-42 Table 1.4 and 8,420 Btu/lb of coalVOCs, lb/MMBtu 0.000119 lb/MMBtu based on EPRI Emission Factor HandbookLead, lb/MMBtu 2.36E-06 lb/MMBtu based on EPRI Emission Factor HandbookGHGs, lb CO2e/MMBtuCO2, tons CEMS, EPA Air Markets Program DataHeat Input, MMBtu CEMS, EPA Air Markets Program DataPM, lb/MMBtu Unit 4 Unit 52010 0.0070 0.00802011 0.0110 0.01002012 0.0260 0.00602013 0.0040 0.0040PM10, lb/MMBtuPM2.5, lb/MMBtuCO2 plus CH4 at 0.0243 lb/MMBtu x 25 plus N2O at 0.00353 lb/MMBtu x 398 plus CO2based on EPA's GHG Mandatory Reporting RuleHeat Input SO2 NOx PM PM10 PM2.5 H2SO4MistCO VOCs Lead GHGstons CO2eCO2MMBtu/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yrJune-12 95,866,8448,66423,492525.3688.9484.113.901,4235.700.1139,914,0239,834,576July-12 96,456,7148,60223,577543.3706.8494.913.991,4325.740.1149,974,9359,894,999August-12 96,834,1618,58423,693557.3720.5503.114.041,4385.760.11410,013,8969,933,647September-12 97,066,1308,56423,814580.0741.8515.614.071,4415.780.11510,037,6659,957,224October-12 97,463,4798,58024,008604.1764.8529.214.131,4475.800.11510,078,4379,997,667November-12 97,023,0728,41523,903621.1779.5537.314.071,4405.770.11410,033,4189,953,013December-12 97,258,3078,37324,029644.2801.3550.014.101,4445.790.11510,058,1339,977,533January-13 97,441,6758,34424,080629.6788.2542.714.131,4475.800.11510,077,3349,996,582February-13 96,584,2278,22023,965614.3772.3532.714.001,4345.750.1149,988,5489,908,506March-13 96,425,5548,18224,022600.2759.0524.913.981,4315.740.1149,971,9349,892,024April-13 95,897,2158,09923,940589.3747.9518.013.911,4245.710.1139,917,6859,838,213May-13 95,859,9098,12823,977578.2737.6512.113.901,4235.700.1139,914,2319,834,790June-13 95,637,2608,06724,016563.4723.5503.813.871,4205.690.1139,891,4609,812,204July-13 94,129,3637,92323,665544.6703.0490.613.651,3975.600.1119,735,9309,657,923August-13 95,026,8777,95623,885534.1695.2486.913.781,4115.650.1129,828,4229,749,671September-13 93,629,2277,85723,583516.6676.1474.613.581,3905.570.1109,683,7279,606,134October-13 94,377,6337,90023,835507.9669.7471.613.681,4015.620.1119,761,0759,682,862November-13 95,778,9667,93524,260501.5666.8471.213.891,4225.700.1139,906,2209,826,846December-13 92,496,6697,60223,508478.7638.8452.113.411,3735.500.1099,566,4539,489,799Baselineemissions January2011 throughDecember 2012,MMBtu/yr andton/yr97,258,3078,37324,029644.2801.3550.014.101,4445.790.11510,058,1339,977,533Baselineemissions January2011 throughDecember 2012,lb/MMBtu0.1720.4940.01320.01650.01130.000290.0300.0001192.36E-06 206.8205.2Table A-1.2 Annual Average Emissions based on Rolling 24-Month Average - Units 4 and 5(a)Month(a) The expected start of construction is mid 2015 (approximately June 30, 2015. Therefore, the earliest allowable baselineperiod is July 2010 through June 2012.TableA‐1.1MonthlyBaselineEmissionsMonth Unit ID SO2 Ratelb/MMBtuSO2tonsNOx Ratelb/MMBtuNOxtonsPMlb/MMBtuPMtonsPM10lb/MMBtuPM10tonsPM2.5lb/MMBtuPM2.5tonsH2SO4Mistlb/MMBtuH2SO4MisttonsCOlb/MMBtuCOtonsVOCslb/MMBtuVOCstonsLeadlb/MMBtuLeadtonsGHGslbCO2e/MMBtuGHGstons CO2eCO2tonsHeat InputMMBtuOperatingTimehoursJanuary-10 Unit 1 0.073346.17 0.776494.26 0.017010.71 0.016210.21 0.01288.07 0.000140.09 0.03018.71 1.19E-04 0.075 2.36E-06 1.49E-03 206.8130,309.60 129,265.27 1,260,174.22 687.78February-10 Unit 1 0.117466.88 0.753435.04 0.01700.00 0.01629.23 0.01287.30 0.000140.08 0.03016.91 1.19E-04 0.068 2.36E-06 1.34E-03 206.9117,876.62 116,932.44 1,139,325.18 632.58March-10 Unit 1 0.114175.37 0.768517.89 0.01700.00 0.016210.71 0.01288.46 0.000140.09 0.03019.62 1.19E-04 0.079 2.36E-06 1.56E-03 207.0136,776.36 135,681.20 1,321,505.42 724.50April-10 Unit 1 0.139268.05 0.760386.87 0.01708.31 0.01627.92 0.01286.26 0.000140.07 0.03014.51 1.19E-04 0.058 2.36E-06 1.15E-03 206.8101,048.07 100,238.04 977,442.49 557.62May-10 Unit 1 0.1626105.81 0.781515.78 0.017011.06 0.016210.55 0.01288.34 0.000140.09 0.03019.32 1.19E-04 0.077 2.36E-06 1.54E-03 207.1134,742.65 133,664.07 1,301,494.99 709.24June-10 Unit 1 0.069044.86 0.808526.61 0.017011.05 0.016210.53 0.01288.33 0.000140.09 0.03019.30 1.19E-04 0.077 2.36E-06 1.53E-03 207.1134,586.07 133,508.90 1,299,791.30 720.00July-10 Unit 1 0.087551.99 0.766459.41 0.017010.11 0.01629.64 0.01287.62 0.000140.08 0.03017.65 1.19E-04 0.071 2.36E-06 1.40E-03 206.9123,017.19 122,031.80 1,189,047.70 723.00August-10 Unit 1 0.099366.34 0.757514.76 0.017011.36 0.016210.83 0.01288.56 0.000140.09 0.03019.83 1.19E-04 0.079 2.36E-06 1.58E-03 207.1138,377.77 137,270.53 1,336,074.67 734.91September-10 Unit 1 0.089154.61 0.796488.41 0.017010.41 0.01629.93 0.01287.85 0.000140.09 0.03018.19 1.19E-04 0.073 2.36E-06 1.45E-03 207.0126,836.51 125,821.10 1,225,276.10 680.00October-10 Unit 1 0.152393.31 0.778493.17 0.017010.42 0.01629.93 0.01287.85 0.000140.09 0.03018.20 1.19E-04 0.073 2.36E-06 1.45E-03 207.0126,874.88 125,859.13 1,225,683.23 664.35November-10 Unit 1 0.156999.74 0.788514.00 0.017010.80 0.016210.30 0.01288.14 0.000140.09 0.03018.87 1.19E-04 0.076 2.36E-06 1.50E-03 206.9131,523.60 130,470.17 1,271,158.75 710.73December-10 Unit 1 0.2295153.53 0.789532.24 0.017011.37 0.016210.84 0.01288.57 0.000140.09 0.03019.86 1.19E-04 0.080 2.36E-06 1.58E-03 206.7138,290.72 137,182.00 1,337,865.60 744.00January-11 Unit 1 0.184089.44 0.714377.19 0.01808.75 0.01698.22 0.01336.47 0.000140.07 0.03014.43 1.19E-04 0.058 2.36E-06 1.15E-03 206.8100,526.69 99,721.09 972,090.52 622.42February-11 Unit 1 0.115564.96 0.747446.85 0.018010.12 0.01699.51 0.01337.49 0.000140.08 0.03016.69 1.19E-04 0.067 2.36E-06 1.33E-03 206.8116,262.89 115,331.03 1,124,453.03 663.57March-11 Unit 1 0.124476.37 0.780488.27 0.018011.05 0.016910.39 0.01338.18 0.000140.09 0.03018.22 1.19E-04 0.073 2.36E-06 1.45E-03 206.8126,908.44 125,891.13 1,227,565.56 690.55April-11 Unit 1 0.092042.71 0.756365.55 0.01808.35 0.01697.85 0.01336.18 0.000140.06 0.03013.78 1.19E-04 0.055 2.36E-06 1.10E-03 206.996,002.41 95,233.38 927,974.27 523.64May-11 Unit 1 0.076743.30 0.786451.44 0.018010.17 0.01699.56 0.01337.52 0.000140.08 0.03016.77 1.19E-04 0.067 2.36E-06 1.33E-03 206.9116,874.88 115,938.79 1,129,553.26 636.34June-11 Unit 1 0.116768.74 0.789473.04 0.018010.61 0.01699.97 0.01337.85 0.000140.08 0.03017.50 1.19E-04 0.070 2.36E-06 1.39E-03 207.1122,061.85 121,085.20 1,178,500.17 642.47July-11 Unit 1 0.137176.89 0.759441.95 0.018010.09 0.01699.49 0.01337.47 0.000140.08 0.03016.65 1.19E-04 0.067 2.36E-06 1.32E-03 206.9116,013.52 115,084.24 1,121,346.88 655.03August-11 Unit 1 0.146792.30 0.749489.33 0.018011.32 0.016910.64 0.01338.38 0.000140.09 0.03018.68 1.19E-04 0.075 2.36E-06 1.48E-03 207.0130,204.52 129,162.00 1,257,988.70 744.00September-11 Unit 1 0.104761.71 0.742450.80 0.018010.61 0.01699.97 0.01337.85 0.000140.08 0.03017.50 1.19E-04 0.070 2.36E-06 1.39E-03 206.8121,919.54 120,942.45 1,179,030.26 717.64October-11 Unit 1 0.190846.80 0.744189.17 0.01804.42 0.01694.15 0.01333.27 0.000140.03 0.0307.28 1.19E-04 0.029 2.36E-06 5.79E-04 206.850,736.72 50,330.14 490,617.16 284.41November-11 Unit 1 0.14204.82 0.43524.27 0.01800.61 0.01690.57 0.01330.45 0.000140.00 0.0301.01 1.19E-04 0.004 2.36E-06 8.00E-05 206.67,007.05 6,950.83 67,836.97 74.57December-11 Unit 1 0.117763.38 0.754420.07 0.01809.69 0.01699.11 0.01337.17 0.000140.08 0.03015.98 1.19E-04 0.064 2.36E-06 1.27E-03 206.8111,314.46 110,422.16 1,076,716.37 627.39January-12 Unit 1 0.107465.44 0.797487.01 0.029017.67 0.024715.06 0.018911.53 0.000140.09 0.03018.09 1.19E-04 0.072 2.36E-06 1.44E-03 206.8125,960.69 124,951.07 1,218,290.60 738.78February-12 Unit 1 0.111151.67 0.733365.49 0.029013.48 0.024711.50 0.01898.80 0.000140.07 0.03013.81 1.19E-04 0.055 2.36E-06 1.10E-03 206.996,182.59 95,411.95 929,907.26 567.12March-12 Unit 1 0.075631.66 0.755327.47 0.029012.14 0.024710.36 0.01897.93 0.000140.06 0.03012.43 1.19E-04 0.050 2.36E-06 9.88E-04 206.886,611.19 85,917.15 837,476.50 506.67April-12 Unit 1 0.10106.10 0.53242.37 0.02901.75 0.02471.49 0.01891.14 0.000140.01 0.0301.79 1.19E-04 0.007 2.36E-06 1.43E-04 206.912,501.54 12,401.40 120,848.51 141.82May-12 Unit 1 0.101240.62 0.741316.01 0.029011.64 0.02479.92 0.01897.60 0.000140.06 0.03011.91 1.19E-04 0.048 2.36E-06 9.47E-04 207.083,035.19 82,370.18 802,448.10 496.73June-12 Unit 1 0.086652.00 0.779474.28 0.029017.42 0.024714.85 0.018911.37 0.000140.08 0.03017.83 1.19E-04 0.071 2.36E-06 1.42E-03 206.9124,280.93 123,285.37 1,201,318.82 714.97July-12 Unit 1 0.127669.55 0.742417.01 0.029015.81 0.024713.48 0.018910.32 0.000140.08 0.03016.18 1.19E-04 0.065 2.36E-06 1.29E-03 206.9112,776.91 111,873.61 1,090,000.88 677.83August-12 Unit 1 0.181992.74 0.745403.29 0.029014.78 0.024712.61 0.01899.65 0.000140.07 0.03015.14 1.19E-04 0.061 2.36E-06 1.20E-03 206.7105,362.38 104,517.39 1,019,637.10 618.15September-12 Unit 1 0.173789.03 0.742399.54 0.029014.86 0.024712.67 0.01899.70 0.000140.07 0.03015.22 1.19E-04 0.061 2.36E-06 1.21E-03 206.8105,996.90 105,147.44 1,025,024.06 594.84October-12 Unit 1 0.1938135.32 0.810565.27 0.029020.24 0.024717.26 0.018913.21 0.000140.10 0.03020.73 1.19E-04 0.083 2.36E-06 1.65E-03 206.8144,371.42 143,214.38 1,396,175.50 743.75November-12 Unit 1 0.174790.36 0.775410.00 0.029015.00 0.024712.79 0.01899.79 0.000140.07 0.03015.35 1.19E-04 0.062 2.36E-06 1.22E-03 206.7106,898.59 106,041.56 1,034,158.81 573.84December-12 Unit 1 0.1676110.88 0.779522.77 0.029019.18 0.024716.36 0.018912.52 0.000140.09 0.03019.64 1.19E-04 0.079 2.36E-06 1.56E-03 206.9136,864.04 135,767.61 1,323,045.76 735.35January-13 Unit 1 0.171086.76 0.721400.19 0.01507.61 0.01487.50 0.01185.98 0.000140.07 0.03015.07 1.19E-04 0.060 2.36E-06 1.20E-03 206.8104,905.71 104,064.72 1,014,801.61 610.73February-13 Unit 1 0.178499.74 0.808450.82 0.01508.39 0.01488.27 0.01186.59 0.000140.08 0.03016.60 1.19E-04 0.067 2.36E-06 1.32E-03 206.8115,617.64 114,691.09 1,118,047.55 670.02March-13 Unit 1 0.149485.63 0.750441.93 0.01508.60 0.01488.48 0.01186.76 0.000140.08 0.03017.02 1.19E-04 0.068 2.36E-06 1.35E-03 206.8118,550.72 117,600.72 1,146,336.86 695.50April-13 Unit 1 0.166896.02 0.770453.36 0.01508.64 0.01488.52 0.01186.79 0.000140.08 0.03017.10 1.19E-04 0.069 2.36E-06 1.36E-03 206.7119,032.96 118,078.65 1,151,543.88 649.40May-13 Unit 1 0.1711115.11 0.757511.75 0.015010.09 0.01489.95 0.01187.93 0.000140.09 0.03019.97 1.19E-04 0.080 2.36E-06 1.59E-03 206.7139,023.92 137,909.06 1,345,281.14 743.90June-13 Unit 1 0.175695.58 0.735411.88 0.01508.16 0.01488.05 0.01186.42 0.000140.08 0.03016.16 1.19E-04 0.065 2.36E-06 1.28E-03 206.9112,587.71 111,685.71 1,088,415.23 710.76July-13 Unit 1 0.186090.85 0.768384.42 0.01507.33 0.01487.22 0.01185.76 0.000140.07 0.03014.50 1.19E-04 0.058 2.36E-06 1.15E-03 206.8101,010.65 100,201.01 976,974.27 570.57August-13 Unit 1 0.19123.27 0.73413.23 0.01500.26 0.01480.25 0.01180.20 0.000140.00 0.0300.51 1.19E-04 0.002 2.36E-06 4.04E-05 206.93,541.77 3,513.40 34,236.27 20.08September-13 Unit 1 0.01500.00 0.01480.00 0.01180.00 0.000140.00 0.0300.00 1.19E-04 0.000 2.36E-06 0.00E+000.00October-13 Unit 1 0.01500.00 0.01480.00 0.01180.00 0.000140.00 0.0300.00 1.19E-04 0.000 2.36E-06 0.00E+000.00November-13 Unit 1 0.01500.00 0.01480.00 0.01180.00 0.000140.00 0.0300.00 1.19E-04 0.000 2.36E-06 0.00E+000.00December-13 Unit 1 0.01500.00 0.01480.00 0.01180.00 0.000140.00 0.0300.00 1.19E-04 0.000 2.36E-06 0.00E+000.00January-10 Unit 2 0.068248.99 0.660475.58 0.020014.37 0.018313.18 0.014310.30 0.000140.10 0.03021.33 1.19E-04 0.086 2.36E-06 1.70E-03 207.0148,724.07 147,533.10 1,437,113.50 744.00February-10 Unit 2 0.134986.73 0.650417.98 0.020012.86 0.018311.79 0.01439.22 0.000140.09 0.03019.09 1.19E-04 0.077 2.36E-06 1.52E-03 206.9133,029.91 131,964.30 1,285,852.30 672.00March-10 Unit 2 0.141982.98 0.626384.62 0.020011.70 0.018310.73 0.01438.39 0.000140.08 0.03017.37 1.19E-04 0.070 2.36E-06 1.38E-03 206.6120,872.06 119,902.54 1,169,898.53 655.20April-10 Unit 2 0.152061.82 0.658269.11 0.02008.13 0.01837.46 0.01435.83 0.000140.06 0.03012.08 1.19E-04 0.048 2.36E-06 9.60E-04 206.684,031.79 83,357.64 813,480.56 434.97May-10 Unit 2 0.493623.84 0.34028.61 0.02000.97 0.01830.89 0.01430.69 0.000140.01 0.0301.43 1.19E-04 0.006 2.36E-06 1.14E-04 207.09,995.63 9,915.59 96,587.69 112.54June-10 Unit 2 0.048531.70 0.653427.50 0.020013.08 0.018312.00 0.01439.38 0.000140.09 0.03019.42 1.19E-04 0.078 2.36E-06 1.54E-03 206.8135,245.18 134,161.00 1,308,256.40 720.00July-10 Unit 2 0.085948.76 0.611356.58 0.020011.35 0.018310.41 0.01438.14 0.000140.08 0.03016.85 1.19E-04 0.068 2.36E-06 1.34E-03 206.8117,380.91 116,440.31 1,134,996.71 638.64August-10 Unit 2 0.086447.70 0.627350.94 0.020011.04 0.018310.13 0.01437.92 0.000140.08 0.03016.39 1.19E-04 0.066 2.36E-06 1.30E-03 206.9114,255.03 113,339.85 1,104,322.54 626.17September-10 Unit 2 0.068244.43 0.647421.51 0.020013.03 0.018311.95 0.01439.34 0.000140.09 0.03019.34 1.19E-04 0.078 2.36E-06 1.54E-03 206.5134,539.32 133,459.70 1,302,750.80 720.00October-10 Unit 2 0.124971.30 0.648374.77 0.020011.41 0.018310.47 0.01438.18 0.000140.08 0.03016.95 1.19E-04 0.068 2.36E-06 1.35E-03 206.9118,102.81 117,156.84 1,141,483.25 644.34November-10 Unit 2 0.130583.10 0.658418.72 0.020012.74 0.018311.68 0.01439.13 0.000140.09 0.03018.91 1.19E-04 0.076 2.36E-06 1.50E-03 206.8131,701.22 130,645.50 1,273,918.50 720.00December-10 Unit 2 0.2260141.16 0.668424.20 0.020012.49 0.018311.46 0.01438.96 0.000140.09 0.03018.55 1.19E-04 0.074 2.36E-06 1.47E-03 206.8129,199.78 128,164.36 1,249,422.94 698.88January-11 Unit 2 0.2057134.63 0.670450.55 0.030019.63 0.025416.65 0.019412.72 0.000140.09 0.03019.43 1.19E-04 0.078 2.36E-06 1.54E-03 207.0135,453.65 134,368.93 1,308,914.82 726.72February-11 Unit 2 0.110256.81 0.667352.59 0.030015.46 0.025413.11 0.019410.02 0.000140.07 0.03015.30 1.19E-04 0.061 2.36E-06 1.22E-03 207.0106,667.63 105,813.44 1,030,734.33 574.07March-11 Unit 2 0.097465.93 0.682461.94 0.030020.31 0.025417.23 0.019413.16 0.000140.09 0.03020.10 1.19E-04 0.081 2.36E-06 1.60E-03 206.9140,065.39 138,943.10 1,354,241.70 744.00April-11 Unit 2 0.087556.12 0.677437.08 0.030019.23 0.025416.31 0.019412.46 0.000140.09 0.03019.03 1.19E-04 0.076 2.36E-06 1.51E-03 207.0132,698.40 131,636.00 1,281,977.60 720.00May-11 Unit 2 0.060840.48 0.674449.65 0.030019.98 0.025416.94 0.019412.94 0.000140.09 0.03019.77 1.19E-04 0.079 2.36E-06 1.57E-03 206.9137,744.07 136,640.40 1,331,767.80 744.00TableA‐1.1MonthlyBaselineEmissionsMonth Unit ID SO2 Ratelb/MMBtuSO2tonsNOx Ratelb/MMBtuNOxtonsPMlb/MMBtuPMtonsPM10lb/MMBtuPM10tonsPM2.5lb/MMBtuPM2.5tonsH2SO4Mistlb/MMBtuH2SO4MisttonsCOlb/MMBtuCOtonsVOCslb/MMBtuVOCstonsLeadlb/MMBtuLeadtonsGHGslbCO2e/MMBtuGHGstons CO2eCO2tonsHeat InputMMBtuOperatingTimehoursJune-11 Unit 2 0.108245.73 0.629278.54 0.030012.68 0.025410.75 0.01948.21 0.000140.06 0.03012.55 1.19E-04 0.050 2.36E-06 9.97E-04 206.787,340.40 86,640.06 845,075.94 489.89July-11 Unit 2 0.127487.96 0.655452.13 0.030020.72 0.025417.57 0.019413.43 0.000140.10 0.03020.51 1.19E-04 0.082 2.36E-06 1.63E-03 206.6142,701.16 141,556.40 1,381,361.20 744.00August-11 Unit 2 0.128482.72 0.643419.43 0.030019.33 0.025416.39 0.019412.53 0.000140.09 0.03019.13 1.19E-04 0.077 2.36E-06 1.52E-03 206.8133,273.96 132,206.03 1,288,649.22 690.63September-11 Unit 2 0.083557.33 0.655449.51 0.030020.59 0.025417.46 0.019413.34 0.000140.10 0.03020.38 1.19E-04 0.082 2.36E-06 1.62E-03 206.6141,773.31 140,635.80 1,372,613.50 720.00October-11 Unit 2 0.1976104.23 0.634347.24 0.030015.83 0.025413.42 0.019410.25 0.000140.07 0.03015.66 1.19E-04 0.063 2.36E-06 1.24E-03 206.6108,966.05 108,091.74 1,055,004.91 578.88November-11 Unit 2 0.1631113.26 0.633439.68 0.030020.84 0.025417.67 0.019413.50 0.000140.10 0.03020.62 1.19E-04 0.083 2.36E-06 1.64E-03 206.5143,407.98 142,256.80 1,389,108.43 716.09December-11 Unit 2 0.106369.28 0.631416.95 0.030019.56 0.025416.59 0.019412.67 0.000140.09 0.03019.36 1.19E-04 0.078 2.36E-06 1.54E-03 206.4134,574.89 133,494.36 1,303,861.26 688.36January-12 Unit 2 0.062232.17 0.641338.52 0.025012.93 0.021911.32 0.01698.74 0.000140.07 0.03015.36 1.19E-04 0.062 2.36E-06 1.22E-03 206.6106,827.11 105,969.89 1,034,382.01 586.97February-12 Unit 2 0.097233.26 0.637226.13 0.02508.55 0.02197.49 0.01695.78 0.000140.05 0.03010.16 1.19E-04 0.041 2.36E-06 8.07E-04 206.770,738.69 70,171.60 684,297.01 400.78March-12 Unit 2 0.071547.78 0.682455.10 0.025016.71 0.021914.63 0.016911.29 0.000140.09 0.03019.85 1.19E-04 0.080 2.36E-06 1.58E-03 206.8138,236.55 137,128.71 1,336,802.99 743.93April-12 Unit 2 0.141228.01 0.582119.68 0.02504.96 0.02194.34 0.01693.35 0.000140.03 0.0305.89 1.19E-04 0.024 2.36E-06 4.68E-04 206.941,047.70 40,718.82 396,862.83 248.65May-12 Unit 2 0.102844.83 0.657296.01 0.025010.91 0.02199.55 0.01697.37 0.000140.06 0.03012.95 1.19E-04 0.052 2.36E-06 1.03E-03 206.790,161.03 89,438.02 872,440.91 517.94June-12 Unit 2 0.067342.06 0.670418.44 0.025015.61 0.021913.67 0.016910.55 0.000140.09 0.03018.54 1.19E-04 0.074 2.36E-06 1.47E-03 206.8129,120.40 128,085.40 1,248,913.66 695.60July-12 Unit 2 0.107862.85 0.654392.14 0.025014.57 0.021912.76 0.01699.84 0.000140.08 0.03017.30 1.19E-04 0.069 2.36E-06 1.38E-03 206.7120,480.59 119,514.63 1,165,597.35 721.05August-12 Unit 2 0.190392.32 0.654329.68 0.025012.13 0.021910.62 0.01698.20 0.000140.07 0.03014.41 1.19E-04 0.058 2.36E-06 1.15E-03 206.9100,406.22 99,601.96 970,488.80 564.56September-12 Unit 2 0.212894.22 0.654304.54 0.025011.07 0.02199.69 0.01697.48 0.000140.06 0.03013.15 1.19E-04 0.053 2.36E-06 1.05E-03 206.791,540.57 90,806.62 885,641.11 520.92October-12 Unit 2 0.2087143.67 0.694477.46 0.025017.21 0.021915.07 0.016911.62 0.000140.10 0.03020.44 1.19E-04 0.082 2.36E-06 1.62E-03 206.6142,188.73 141,047.98 1,376,517.68 743.75November-12 Unit 2 0.161171.92 0.662309.53 0.025011.16 0.02199.77 0.01697.54 0.000140.06 0.03013.26 1.19E-04 0.053 2.36E-06 1.05E-03 206.692,225.48 91,485.44 892,990.74 513.66December-12 Unit 2 0.1908111.78 0.653392.25 0.025014.65 0.021912.82 0.01699.89 0.000140.08 0.03017.39 1.19E-04 0.070 2.36E-06 1.38E-03 206.8121,122.54 120,151.55 1,171,672.49 656.77January-13 Unit 2 0.170293.13 0.636366.98 0.01508.21 0.01488.09 0.01186.45 0.000140.08 0.03016.24 1.19E-04 0.065 2.36E-06 1.29E-03 206.8113,124.48 112,217.81 1,094,062.70 658.87February-13 Unit 2 0.178393.65 0.703373.56 0.01507.88 0.01487.77 0.01186.19 0.000140.07 0.03015.59 1.19E-04 0.063 2.36E-06 1.24E-03 206.5108,464.94 107,594.40 1,050,461.57 598.10March-13 Unit 2 0.166691.01 0.694384.56 0.01508.19 0.01488.08 0.01186.44 0.000140.08 0.03016.22 1.19E-04 0.065 2.36E-06 1.29E-03 206.6112,820.81 111,915.58 1,092,315.35 643.55April-13 Unit 2 0.1853106.98 0.659402.06 0.01508.66 0.01488.54 0.01186.81 0.000140.08 0.03017.14 1.19E-04 0.069 2.36E-06 1.36E-03 206.7119,293.27 118,336.50 1,154,517.10 652.47May-13 Unit 2 0.1729110.73 0.716460.38 0.01509.60 0.01489.47 0.01187.55 0.000140.09 0.03019.01 1.19E-04 0.076 2.36E-06 1.51E-03 206.8132,365.87 131,304.74 1,280,442.27 743.90June-13 Unit 2 0.167074.88 0.717326.87 0.01506.72 0.01486.63 0.01185.29 0.000140.06 0.03013.31 1.19E-04 0.053 2.36E-06 1.06E-03 206.692,620.90 91,877.87 896,606.96 588.92July-13 Unit 2 0.152595.11 0.696439.71 0.01509.36 0.01489.23 0.01187.36 0.000140.09 0.03018.52 1.19E-04 0.074 2.36E-06 1.47E-03 207.0129,150.29 128,116.31 1,247,679.01 743.37August-13 Unit 2 0.178786.63 0.631333.85 0.01507.27 0.01487.17 0.01185.72 0.000140.07 0.03014.39 1.19E-04 0.058 2.36E-06 1.14E-03 206.9100,287.19 99,483.72 969,530.49 647.66September-13 Unit 2 0.1797102.53 0.676386.00 0.01508.56 0.01488.44 0.01186.73 0.000140.08 0.03016.94 1.19E-04 0.068 2.36E-06 1.35E-03 206.7117,955.62 117,009.89 1,141,186.42 658.99October-13 Unit 2 0.1661102.63 0.672422.22 0.01509.27 0.01489.14 0.01187.29 0.000140.09 0.03018.35 1.19E-04 0.074 2.36E-06 1.46E-03 206.9127,857.04 126,832.71 1,236,031.62 725.49November-13 Unit 2 0.1677101.99 0.671407.61 0.01509.12 0.01488.99 0.01187.17 0.000140.09 0.03018.05 1.19E-04 0.072 2.36E-06 1.43E-03 206.9125,805.67 124,797.90 1,216,049.10 720.00December-13 Unit 2 0.163799.56 0.664405.53 0.01509.12 0.01489.00 0.01187.17 0.000140.09 0.03018.06 1.19E-04 0.072 2.36E-06 1.44E-03 206.7125,738.60 124,730.51 1,216,440.62 710.03January-10 Unit 3 0.064663.61 0.573568.52 0.023022.65 0.020520.16 0.015915.63 0.000140.14 0.03029.24 1.19E-04 0.117 2.36E-06 2.32E-03 206.7203,545.33 201,913.34 1,969,288.23 742.66February-10 Unit 3 0.1195102.94 0.578499.48 0.023019.81 0.020517.63 0.015913.67 0.000140.12 0.03025.57 1.19E-04 0.102 2.36E-06 2.03E-03 206.7177,962.30 176,535.00 1,722,292.70 672.00March-10 Unit 3 0.093773.52 0.570457.43 0.023018.04 0.020516.06 0.015912.45 0.000140.11 0.03023.29 1.19E-04 0.093 2.36E-06 1.85E-03 206.9162,356.25 161,055.94 1,569,062.00 669.69April-10 Unit 3 0.1126109.00 0.573554.80 0.023022.27 0.020519.82 0.015915.36 0.000140.14 0.03028.74 1.19E-04 0.115 2.36E-06 2.28E-03 207.1200,479.20 198,874.70 1,936,115.00 720.00May-10 Unit 3 0.1361129.64 0.578549.69 0.023021.91 0.020519.50 0.015915.12 0.000140.13 0.03028.29 1.19E-04 0.113 2.36E-06 2.25E-03 206.9197,132.02 195,552.80 1,905,603.10 744.00June-10 Unit 3 0.051443.06 0.587493.99 0.023019.28 0.020517.15 0.015913.30 0.000140.12 0.03024.88 1.19E-04 0.100 2.36E-06 1.98E-03 206.7173,247.48 171,858.46 1,676,088.72 661.73July-10 Unit 3 0.069754.37 0.572458.20 0.023017.95 0.020515.97 0.015912.38 0.000140.11 0.03023.17 1.19E-04 0.093 2.36E-06 1.84E-03 206.7161,252.26 159,959.08 1,560,449.49 619.45August-10 Unit 3 0.079263.94 0.559473.94 0.023018.56 0.020516.52 0.015912.81 0.000140.11 0.03023.96 1.19E-04 0.096 2.36E-06 1.90E-03 206.7166,789.12 165,451.61 1,613,943.78 674.74September-10 Unit 3 0.091185.78 0.574547.42 0.023021.65 0.020519.27 0.015914.94 0.000140.13 0.03027.95 1.19E-04 0.112 2.36E-06 2.22E-03 206.8194,684.62 193,124.26 1,882,840.36 698.96October-10 Unit 3 0.1619142.88 0.591537.87 0.023020.30 0.020518.07 0.015914.01 0.000140.12 0.03026.21 1.19E-04 0.105 2.36E-06 2.08E-03 206.9182,612.49 181,149.61 1,765,226.78 679.83November-10 Unit 3 0.1775127.56 0.583441.21 0.023016.53 0.020514.71 0.015911.40 0.000140.10 0.03021.34 1.19E-04 0.086 2.36E-06 1.70E-03 206.8148,620.06 147,428.95 1,437,289.88 596.56December-10 Unit 3 0.2728218.29 0.598490.09 0.023018.40 0.020516.38 0.015912.70 0.000140.11 0.03023.76 1.19E-04 0.095 2.36E-06 1.89E-03 206.9165,540.85 164,214.77 1,600,152.10 616.93January-11 Unit 3 0.2998155.32 0.571309.70 0.048024.86 0.038219.80 0.028614.83 0.000140.07 0.03015.38 1.19E-04 0.062 2.36E-06 1.22E-03 207.0107,233.36 106,374.79 1,036,011.81 456.82February-11 Unit 3 0.195865.27 0.392192.49 0.048016.00 0.038212.74 0.02869.54 0.000140.05 0.0309.90 1.19E-04 0.040 2.36E-06 7.87E-04 206.968,968.51 68,415.95 666,763.65 386.87March-11 Unit 3 0.1503135.31 0.625561.56 0.048043.23 0.038234.42 0.028625.77 0.000140.13 0.03026.74 1.19E-04 0.107 2.36E-06 2.13E-03 206.8186,264.54 184,771.96 1,801,061.14 743.18April-11 Unit 3 0.1917174.54 0.599554.92 0.048043.71 0.038234.81 0.028626.06 0.000140.13 0.03027.04 1.19E-04 0.108 2.36E-06 2.15E-03 206.7188,209.80 186,700.36 1,821,410.27 712.11May-11 Unit 3 0.098995.39 0.621598.62 0.048046.29 0.038236.86 0.028627.60 0.000140.14 0.03028.63 1.19E-04 0.115 2.36E-06 2.28E-03 206.6199,233.85 197,635.50 1,928,686.70 744.00June-11 Unit 3 0.1246105.58 0.629531.98 0.048040.68 0.038232.39 0.028624.25 0.000140.12 0.03025.16 1.19E-04 0.101 2.36E-06 2.00E-03 206.6175,109.62 173,705.00 1,694,924.30 720.00July-11 Unit 3 0.1429132.50 0.617581.80 0.048044.50 0.038235.43 0.028626.53 0.000140.13 0.03027.53 1.19E-04 0.110 2.36E-06 2.19E-03 206.8191,717.61 190,181.00 1,854,187.10 744.00August-11 Unit 3 0.1559126.43 0.612505.84 0.048038.92 0.038230.99 0.028623.21 0.000140.11 0.03024.08 1.19E-04 0.096 2.36E-06 1.91E-03 206.6167,511.24 166,167.23 1,621,793.02 607.88September-11 Unit 3 0.098591.94 0.599573.55 0.048044.81 0.038235.68 0.028626.72 0.000140.13 0.03027.72 1.19E-04 0.111 2.36E-06 2.20E-03 206.9193,188.07 191,640.71 1,867,166.51 716.54October-11 Unit 3 0.164494.39 0.551341.96 0.048027.56 0.038221.94 0.028616.43 0.000140.08 0.03017.04 1.19E-04 0.068 2.36E-06 1.35E-03 206.6118,617.36 117,665.88 1,148,136.48 553.83November-11 Unit 3 0.1661117.94 0.605440.19 0.048034.08 0.038227.13 0.028620.32 0.000140.10 0.03021.08 1.19E-04 0.084 2.36E-06 1.68E-03 206.7146,716.85 145,540.13 1,419,915.74 597.09December-11 Unit 3 0.1268111.56 0.620549.20 0.048042.23 0.038233.63 0.028625.18 0.000140.12 0.03026.12 1.19E-04 0.105 2.36E-06 2.08E-03 206.7181,816.07 180,357.89 1,759,555.48 695.98January-12 Unit 3 0.1422113.81 0.599492.77 0.021016.81 0.019115.25 0.014911.89 0.000140.11 0.03023.77 1.19E-04 0.095 2.36E-06 1.89E-03 206.8165,566.95 164,239.96 1,601,246.70 668.83February-12 Unit 3 0.1266109.81 0.612533.85 0.021018.22 0.019116.53 0.014912.88 0.000140.12 0.03025.76 1.19E-04 0.103 2.36E-06 2.05E-03 206.8179,431.26 177,993.30 1,735,158.10 696.00March-12 Unit 3 0.09167.66 0.46352.07 0.02101.76 0.01911.59 0.01491.24 0.000140.01 0.0302.48 1.19E-04 0.010 2.36E-06 1.97E-04 207.217,318.68 17,180.13 167,183.65 90.26April-12 Unit 3 0.157374.20 0.577288.03 0.02109.91 0.01918.99 0.01497.01 0.000140.07 0.03014.01 1.19E-04 0.056 2.36E-06 1.11E-03 206.997,586.36 96,804.51 943,443.69 457.22May-12 Unit 3 0.1448131.52 0.607555.81 0.021019.08 0.019117.31 0.014913.49 0.000140.13 0.03026.97 1.19E-04 0.108 2.36E-06 2.14E-03 206.8187,900.63 186,394.83 1,817,017.52 735.58June-12 Unit 3 0.105287.71 0.609514.35 0.021017.52 0.019115.89 0.014912.39 0.000140.12 0.03024.76 1.19E-04 0.099 2.36E-06 1.97E-03 206.9172,535.35 171,152.91 1,668,151.66 644.57July-12 Unit 3 0.1647165.04 0.605610.93 0.021021.04 0.019119.09 0.014914.88 0.000140.14 0.03029.75 1.19E-04 0.119 2.36E-06 2.36E-03 206.8207,165.99 205,505.50 2,003,676.60 744.00August-12 Unit 3 0.2448206.70 0.599520.50 0.021017.73 0.019116.09 0.014912.54 0.000140.12 0.03025.07 1.19E-04 0.100 2.36E-06 1.99E-03 207.0174,769.05 173,369.43 1,688,895.36 620.59September-12 Unit 3 0.1740171.45 0.641630.04 0.021020.69 0.019118.77 0.014914.63 0.000140.14 0.03029.25 1.19E-04 0.117 2.36E-06 2.33E-03 206.9203,888.84 202,255.89 1,970,444.52 716.51October-12 Unit 3 0.1939184.23 0.601581.73 0.021019.96 0.019118.10 0.014914.11 0.000140.13 0.03028.22 1.19E-04 0.113 2.36E-06 2.24E-03 206.9196,637.78 195,062.64 1,900,685.96 666.87TableA‐1.1MonthlyBaselineEmissionsMonth Unit ID SO2 Ratelb/MMBtuSO2tonsNOx Ratelb/MMBtuNOxtonsPMlb/MMBtuPMtonsPM10lb/MMBtuPM10tonsPM2.5lb/MMBtuPM2.5tonsH2SO4Mistlb/MMBtuH2SO4MisttonsCOlb/MMBtuCOtonsVOCslb/MMBtuVOCstonsLeadlb/MMBtuLeadtonsGHGslbCO2e/MMBtuGHGstons CO2eCO2tonsHeat InputMMBtuOperatingTimehoursNovember-12 Unit 3 0.1714143.96 0.596507.78 0.021017.64 0.019116.00 0.014912.48 0.000140.12 0.03024.94 1.19E-04 0.100 2.36E-06 1.98E-03 206.8173,773.95 172,381.51 1,680,220.14 717.60December-12 Unit 3 0.1810131.87 0.590449.67 0.021015.30 0.019113.88 0.014910.82 0.000140.10 0.03021.64 1.19E-04 0.087 2.36E-06 1.72E-03 206.9150,742.34 149,534.54 1,457,425.80 574.29January-13 Unit 3 0.1880167.43 0.614550.35 0.015013.36 0.014813.17 0.011810.50 0.000140.12 0.03026.44 1.19E-04 0.106 2.36E-06 2.10E-03 206.8184,165.73 182,689.78 1,780,999.77 740.17February-13 Unit 3 0.2144187.77 0.583517.84 0.015013.14 0.014812.96 0.011810.33 0.000140.12 0.03026.01 1.19E-04 0.104 2.36E-06 2.07E-03 207.2181,468.11 180,016.22 1,751,960.96 667.40March-13 Unit 3 0.1632151.85 0.564525.23 0.015013.96 0.014813.76 0.011810.97 0.000140.13 0.03027.63 1.19E-04 0.111 2.36E-06 2.20E-03 206.8192,414.65 190,872.41 1,860,983.51 710.12April-13 Unit 3 0.1705132.36 0.562454.76 0.015011.64 0.014811.48 0.01189.15 0.000140.11 0.03023.04 1.19E-04 0.092 2.36E-06 1.83E-03 206.7160,432.67 159,146.26 1,552,287.72 621.90May-13 Unit 3 0.1885137.10 0.585435.43 0.015010.91 0.014810.76 0.01188.58 0.000140.10 0.03021.60 1.19E-04 0.087 2.36E-06 1.72E-03 207.1150,628.03 149,422.27 1,454,965.33 606.74June-13 Unit 3 0.1809120.46 0.601425.42 0.01509.99 0.01489.85 0.01187.85 0.000140.09 0.03019.77 1.19E-04 0.079 2.36E-06 1.57E-03 206.8137,746.71 136,642.87 1,331,977.95 573.75July-13 Unit 3 0.1880169.73 0.632575.47 0.015013.54 0.014813.35 0.011810.64 0.000140.13 0.03026.80 1.19E-04 0.107 2.36E-06 2.13E-03 206.9186,764.97 185,268.89 1,805,288.44 743.82August-13 Unit 3 0.1894108.55 0.600378.91 0.01508.60 0.01488.48 0.01186.76 0.000140.08 0.03017.02 1.19E-04 0.068 2.36E-06 1.35E-03 206.7118,462.93 117,512.79 1,146,507.09 611.26September-13 Unit 3 0.2019155.91 0.548434.82 0.015011.59 0.014811.42 0.01189.11 0.000140.11 0.03022.93 1.19E-04 0.092 2.36E-06 1.82E-03 206.9159,844.80 158,564.59 1,544,803.02 717.87October-13 Unit 3 0.161278.80 0.528261.09 0.01507.33 0.01487.23 0.01185.76 0.000140.07 0.03014.52 1.19E-04 0.058 2.36E-06 1.15E-03 206.9101,156.63 100,346.29 977,816.48 609.40November-13 Unit 3 0.1804114.72 0.550363.94 0.01509.54 0.01489.41 0.01187.50 0.000140.09 0.03018.88 1.19E-04 0.076 2.36E-06 1.50E-03 206.9131,567.98 130,513.79 1,272,071.31 547.74December-13 Unit 3 0.1726120.95 0.524378.38 0.015010.51 0.014810.37 0.01188.26 0.000140.10 0.03020.81 1.19E-04 0.083 2.36E-06 1.65E-03 206.9145,008.92 143,847.22 1,401,801.93 710.28Emission Basis and/or Emission FactorsSO2, lb/MMBtu Calculated from SO2 (tons) and heat input (MMBtu)SO2, tons CEMS, EPA Air Markets Program DataNOx, lb/MMBtu CEMS, EPA Air Markets Program DataNOx, tons CEMS, EPA Air Markets Program DataPM, lb/MMBtu Annual stack testing, see belowPM, tons PM (lb/MMBtu) and heat input (MMBtu)71% of filterable PM, AP-42 Table 1.1-5, Venturi Scrubber+PM10 condensable inorgnaics (sulfuric acid mist)+PM10 condensable organics (20% of 0.02 lb/MMBtu based on AP-42 Table 1.1-551% of filterable PM, AP-42 Table 1.1-5, Venturi Scrubber+PM2.5 condensable inorgnaics (sulfuric acid mist)+PM2.5 condensable organics (20% of 0.02 lb/MMBtu based on AP-42 Table 1.1-5Sulfuric acid mist, lb/MMBtu 0.00014 lb/MMBtu based on 2011 stack testCO, lb/MMBtu 0.5 lb/ton of coal based on AP-42 Table 1.4 and 8,420 Btu/lb of coalVOCs, lb/MMBtu 0.000119 lb/MMBtu based on EPRI Emission Factor HandbookLead, lb/MMBtu 2.36E-06 lb/MMBtu based on EPRI Emission Factor HandbookGHGs, lb CO2e/MMBtuCO2, tons CEMS, EPA Air Markets Program DataHeat Input, MMBtu CEMS, EPA Air Markets Program DataPM, lb/MMBtu Unit 1 Unit 2 Unit 32010 0.0170 0.0200 0.02302011 0.0180 0.0300 0.04802012 0.0290 0.0250 0.021020130.0150 0.0150 0.0150PM10, lb/MMBtuPM2.5, lb/MMBtuCO2 plus CH4 at 0.0243 lb/MMBtu x 25 plus N2O at 0.00353 lb/MMBtu x 398 plus CO2based on EPA's GHG Mandatory Reporting RuleHeat Input SO2 NOx PM PM10 PM2.5 H2SO4MistCO VOCs Lead GHGstons CO2eCO2MMBtu/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yrJune-12 44,292,3452,85114,958626.9536.8411.43.10657.552.640.0524,579,8644,543,158July-12 44,479,7352,92215,031632.9541.4414.93.11660.332.650.0524,599,2514,562,390August-12 44,292,0753,02914,988634.7542.4415.43.10657.542.640.0524,579,8094,543,103September-12 44,027,1973,11414,926635.5542.3415.23.08653.612.620.0524,552,4924,516,005October-12 44,297,6903,19115,035643.1548.3419.73.10657.632.640.0524,580,2964,543,585November-12 44,110,1913,18914,962645.0549.3420.33.09654.842.620.0524,560,8224,524,267December-12 43,992,5433,11014,921648.4551.5421.83.08653.102.620.0524,548,6714,512,213January-13 44,278,9663,09415,011636.4543.5416.23.10657.352.630.0524,578,1624,541,467February-13 44,828,2263,19115,186630.3540.3414.33.14665.502.670.0534,634,9884,597,838March-13 44,686,6093,21715,106608.4524.5402.83.13663.402.660.0534,620,2624,583,229April-13 44,600,1033,24815,083587.2509.2391.83.12662.122.650.0534,611,1864,574,225May-13 44,445,4433,33915,037564.3492.7379.83.11659.822.640.0524,595,2684,558,436June-13 44,244,6933,37514,977544.8478.4369.43.10656.842.630.0524,574,4904,537,824July-13 44,081,2163,40414,939522.2462.0357.63.09654.412.620.0524,557,7374,521,206August-13 43,072,1383,35314,595495.5441.0341.93.02639.432.560.0514,453,3884,417,693September-13 42,205,7273,37614,268467.6419.3325.82.95626.572.510.0504,363,8484,328,871October-13 41,965,7723,34414,170452.0407.8317.42.94623.012.500.0504,339,1954,304,417November-13 41,771,4023,33514,104433.5394.3307.62.92620.122.490.0494,319,3154,284,699December-13 41,010,4563,32313,803407.6374.3292.82.87608.832.440.0484,240,8374,206,850Baselineemissions January2011 throughDecember 2012,MMBtu/yr andton/yr43,992,5433,11014,921648.4551.5421.83.086532.620.0524,548,6714,512,213Baselineemissions January2011 throughDecember 2012,lb/MMBtu0.1410.6780.02950.02510.01920.000140.0300.0001192.36E-06 206.8205.1Table A-1.4 Annual Average Emissions based on Rolling 24-Month Average - Units 1, 2, and 3(a)Month(a) The expected start of construction is mid 2015 (approximately June 30, 2015. Therefore, the earliest allowable baselineperiod is July 2010 through June 2012.Parameter Value Units CommentsBoiler Heat Input 14,822 MMBtu/hr Typical maximum valueFuel S 0.78% wt % Typical valueFuel heating Value 8,776 Btu/lb Typical valueOxidation of Fuel S to SO3 0.294% Calculated from stack testSO3 at Boiler Outlet 96.96 lb/hr APS source testOxidation of SO2 to SO3 by SCR 1.00%APS estimate for 4 layers lowoxidation catalystSO3 added by SCR 329.34 lb/hr CalculatedSO3 at SCR outlet 426.30 lb/hr CalculatedRemoval by Air Preheater 50%EPRI(a)Removal by Baghouse and WetScrubber57.39% APS source testSO3 Emissions 90.82 lb/hr CalculatedH2SO4 Emissions 111.26 lb/hr CalculatedH2SO4 Emissions before Control 0.00751 lb/MMBtu CalculatedH2SO4 Control Efficiency, % 42% APS estimateH2SO4 Emissions after control 0.00435 lb/MMBtu CalculatedH2SO4 Emissions after control 1.5ppmvd correctedto 3% O2Calculated from lb/MMBtubased on 40 CFR Part 60Appendix A Method 19(a) Estimating Total Sulfuric Acid Mist Emissions from Stationary Power Plants, Technical Update,March 2012. EPRI Report 1023790.Table A-2 Future Sulfuric Acid Mist Emission Calculation for Units 4 and 5Parameter Value Units CommentsPre-Project Heat Input 97,258,307 MMBtu/yr See Table A 1.2Post-Project Heat Input with Demand Growthwithout Parasitic Load and EconomizerInefficiency116,008,264 MMBtu/yr 89.35% capacity factor, see table A-8Heat Input to Demand Growth 18,749,957 MMBtu/yrIncreased Power Demand due to New EmissionControls348,025 MMBtu/yr0.3% (see Table A-9) of the future projected capacityfactor of 89.35% (see Table A-8) which includes demandgrowthTotal Projected Future Fuel Use 116,356,289 MMBtu/yrPost-project heat input including demand growth andincreased power demand due to new emission controlsTotal Projected Capacity Factor 89.61%Projected Future Fuel Use Excluding DemandGrowth97,606,332 MMBtu/yrPre-project heat input plus increased power demand dueto new emission controlsProjected Capacity Factor Excluding DemandGrowth and Non-Project Related Changes75.17%SO2Emission Rate0.1722 lb/MMBtu Same as baseline, no project related changeSO2Emissions8,403.2 ton/yrBased on Projected Future Fuel Use Excluding DemandGrowthNOx Emission Rate 0.0980 lb/MMBtu 40 CFR 49 BART Rule, 30-day rolling averageNOx Emissions 4,782.7 ton/yrBased on Projected Future Fuel Use Excluding DemandGrowthPM Emission Rate 0.0132 lb/MMBtu Same as baseline, no project related changePM Emissions 646.5 ton/yrBased on Projected Future Fuel Use Excluding DemandGrowthPM10Emission Rate0.0222 lb/MMBtuBACT - 92% of 0.015 lb/MMBtu plus 0.0040 lb/MMBtucondensable organics plus 0.00435 lb/MMBtu sulfuricacid mist emissionsPM10Emissions1,288.9 ton/yr Total emissions including demand growthBasis for Demand Growth Exclusion(c)0.0165 lb/MMBtu Baseline emission rateDemand Growth Exclusion(c)154.47 ton/yr Baseline emission rate x demand growthPM10Emissions1,134.4 ton/yr Excluding non-project related emissionsPM2.5Emission Rate0.0163 lb/MMBtuBACT - 53% of 0.015 lb/MMBtu plus 0.0040 lb/MMBtucondensable organics plus 0.00435 lb/MMBtu sulfuricacid mist emissionsPM2.5Emissions948.5 ton/yr Total emissions including demand growthTable A-3 Projected Future Emission Calculation for Units 4 and 5(a)Parameter Value Units CommentsTable A-3 Projected Future Emission Calculation for Units 4 and 5(a)Basis for Demand Growth Exclusion(c)0.0113 lb/MMBtu Baseline emission rateDemand Growth Exclusion(c)106.04 ton/yr Baseline emission rate x demand growthPM2.5Emissions842.5 ton/yr Excluding non-project related emissionsSulfuric Acid Mist Emission Rate 0.00435 lb/MMBtu See Table A-2Sulfuric Acid Mist Emissions 253.29 ton/yr Total emissions including demand growthBasis for Demand Growth Exclusion(c)0.00029 lb/MMBtu Baseline emission rateDemand Growth Exclusion(c)2.72 ton/yr Baseline emission rate x demand growthSulfuric Acid Mist Emissions 250.6 ton/yr Excluding non-project related emissionsCO Emission Rate 0.02969 lb/MMBtu Same as baseline, no project related changeCO Emissions 1,449.0 ton/yrBased on Projected Future Fuel Use Excluding DemandGrowthVOC Emission Rate 0.000119 lb/MMBtu Same as baseline, no project related changeVOC Emissions 5.81 ton/yrBased on Projected Future Fuel Use Excluding DemandGrowthLead Emission Rate 2.36E-06 lb/MMBtu Same as baseline, no project related changeLead Emissions 0.115 ton/yrBased on Projected Future Fuel Use Excluding DemandGrowthCO2Emission Rate205.2 lb/MMBtu Same as baseline, no project related changeCO2Emissions10,013,236 ton/yrBased on Projected Future Fuel Use Excluding DemandGrowthCO2eEmission Rate206.8 lb/MMBtu Same as baseline, no project related changeCO2eEmissions10,094,124 ton/yrBased on Projected Future Fuel Use Excluding DemandGrowth(c) Emissions from demand growth at the baseline emission rate are "unrelated to the particular project".(a) Projected actual emissions do not include exclusions allowed by 40 CFR 52.21(b)(41)(ii): "In determining projected actual emissions underparagraph (b)(41) the operator shall exclude, in calculating any increase in emissions that results from the particular project, that portion of the unit'semissions following the project that an existing unit could have accommodated during the consecutive 24-month period used to establish the baselineactual emissions under paragraph (b)(48) of this section and that are also unrelated to the particular project, including any increased utilization due toproduct demand growth.(b) The auxiliary load, in terms of increased fuel use, is based on occasional or periodic increased firing to compensate forSCR power use andeconomizer bypass which result in lower net power output. See Table A-9gr/scf ton/yrMaximumlb/daySilo for Dry SorbentStoragePneumaticTransfer to Silowith Fabric FilterControl2,0002,000100.0050 0.0857 0.857Silo for SCR ReagentStorage(a)PneumaticTransfer to Silowith Fabric FilterControl5,0002,000100.0050 0.2143 2.143(a) The SCR reagent silo will only be built if urea pellets are selected as the SCR reagent. Other reagent options beingconsidered are 29% aqueous ammonia and anhydrous ammonia. There will be no emissions from SCR reagent storage ifeither ammonia option is selected.Table A-4 Projected Emission Increase Calculation for Reagent HandlingPM PM10 PM2.5 EmissionsMaximumDailyOperatingHoursSource Source TypeFlowscfmAnnualOperatingHoursSource RoadTypeVehicleTypeTrucksperYearTrucksperDayTruckWeightEmpty(tons)TruckWeightFull(tons)TruckWeightAverage(tons)Length(m)Length(miles)Avgvehicleweight(tons)SiltLoading(g/m2)PMbeforeControllb/VMTPMControlEfficiencyPMAnnualEmissions(ton/yr)PM DailyEmissions(lb/day)PM10beforeControllb/VMTPM10ControlEfficiencyPM10AnnualEmissions(ton/yr)PM10DailyEmissions(lb/day)PM2.5beforeControllb/VMTPM2.5ControlEfficiencyPM2.5AnnualEmissions(ton/yr)PM2.5DailyEmissions(lb/day)DSIDeliveryTrucks900 3 12 24 18 684.2 0.425 18.0 9.70 1.659 85% 0.0952 0.6346 0.3317 85% 0.0190 0.1269 0.0814 85% 0.0047 0.0312WateringTrucksReagentTrucks1500 5 12 34.5 23.25 289.3 0.180 23.3 9.70 2.153 85% 0.0871 0.5806 0.4307 85% 0.0174 0.1161 0.1057 85% 0.0043 0.0285WateringTrucks(a) The SCR system may use 29% aqueous ammonia, urea pellets, or anhydrous ammonia. The worst case for emissions from road traffic is 29% aqueous ammonia.Paved Roadway Equation (AP-42 Section 13.2.1)E (lb/VMT) =k * sL0.91* W1.02k =0.011 for PM, 0.0022 for PM10, 0.00054 for PM2.5sL =silt loading (g/m2)W = average vehicle weightTable A-5.1 Projected Emission Increase Calculation for Reagent Delivery (DSI and 29% Aqueous Ammonia)No increaseDelivery ofSorbent for DrySorbentInjectionPavedDelivery ofSCR Reagent(29% AqueousAmmonia) (a)PavedNo increaseSource RoadTypeVehicleTypeTrucksperYearTrucksperDayTruckWeightEmpty(tons)TruckWeightFull(tons)TruckWeightAverage(tons)Length(m)Length(miles)Avgvehicleweight(tons)SiltLoading(g/m2)PMbeforeControllb/VMTPM ControlEfficiencyPMAnnualEmissions(ton/yr)PM DailyEmissions(lb/day)PM10beforeControllb/VMTPM10ControlEfficiencyPM10AnnualEmissions(ton/yr)PM10DailyEmissions(lb/day)PM2.5beforeControllb/VMTPM2.5ControlEfficiencyPM2.5AnnualEmissions(ton/yr)PM2.5DailyEmissions(lb/day)DSIDeliveryTrucks900 3 12 24 18 684.2 0.425 18.0 9.70 1.659 85% 0.0952 0.6346 0.3317 85% 0.0190 0.1269 0.0814 85% 0.0047 0.0312WateringTrucksReagentTrucks874 3 12 32.1 22.0 289.3 0.180 22.0 9.70 2.038 85% 0.0480 0.3297 0.4076 85% 0.0096 0.0659 0.1000 85% 0.0024 0.0162WateringTrucks(a) The SCR system may use 29% aqueous ammonia, urea pellets, or anhydrous ammonia. The worst case for emissions from road traffic is 29% aqueous ammonia.Paved Roadway Equation (AP-42 Section 13.2.1)E (lb/VMT) =k * sL0.91* W1.02k =0.011 for PM, 0.0022 for PM10, 0.00054 for PM2.5sL =silt loading (g/m2)W = average vehicle weightDelivery of SCRReagent (UreaPellets) (a)PavedNo increaseTable A-5.2 Projected Emission Increase Calculation for Reagent Delivery (DSI and Urea Pellets)Delivery ofSorbent for DrySorbent InjectionPavedNo increaseSource RoadTypeVehicleTypeTrucksperYearTrucksperDayTruckWeightEmpty(tons)TruckWeightFull(tons)TruckWeightAverage(tons)Length(m)Length(miles)Avgvehicleweight(tons)SiltLoading(g/m2)PMbeforeControllb/VMTPM ControlEfficiencyPMAnnualEmissions(ton/yr)PM DailyEmissions(lb/day)PM10beforeControllb/VMTPM10ControlEfficiencyPM10 AnnualEmissions(ton/yr)PM10DailyEmissions(lb/day)PM2.5beforeControllb/VMTPM2.5ControlEfficiencyPM2.5AnnualEmissions(ton/yr)PM2.5DailyEmissions(lb/day)DSIDeliveryTrucks900 3 12 24 18 684.2 0.425 18.0 9.70 1.659 85% 0.0952 0.6346 0.3317 85% 0.0190 0.1269 0.0814 85% 0.0047 0.0312WateringTrucksReagentTrucks643 2 12 27.5 19.8 289.3 0.180 19.8 9.70 1.824 85% 0.0316 0.1967 0.3647 85% 0.0063 0.0393 0.0895 85% 0.0016 0.0097WateringTrucks(a) The SCR system may use 29% aqueous ammonia, urea pellets, or anhydrous ammonia. The worst case for emissions from road traffic is 29% aqueous ammonia.Paved Roadway Equation (AP-42 Section 13.2.1)E (lb/VMT) =k * sL0.91* W1.02k =0.011 for PM, 0.0022 for PM10, 0.00054 for PM2.5sL =silt loading (g/m2)W = average vehicle weightDelivery of SCRReagent(AnhydrousAmmonia) (a)PavedNo increaseTable A-5.3 Projected Emission Increase Calculation for Reagent Delivery (DSI and Anhydrous Ammonia)Delivery ofSorbent for DrySorbent InjectionPavedNo increaseNOxSO2PMPM10PM2.5CO VOCH2SO4LeadGHG CO2e(ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr)Unit 4 and 5 BaselineEmissions24,029.2 8,373.2 644.2 801.3 550.0 1,443.9 5.787 14.1 1.15E-01 10,058,133Unit 4 and 5 ProjectedFuture Emissions (a)4,782.7 8,403.2 646.5 1,134.4 842.5 1,449.0 5.808 250.6 1.15E-01 10,094,124Unit 4 and Unit 5Emission Change-19,246.5 30.0 2.3 333.1 292.4 5.17 0.021 236.5 4.11E-04 35,992DSI Sorbent Truck TrafficEmission Change0.0 0.0 0.0952 0.0190 0.0047 0.0 0.0 0.0 0.0 0.0SCR Reagent TruckTraffic Emission Change(worst case)0.0 0.0 0.0871 0.0174 0.0043 0.0 0.0 0.0 0.0 0.0DSI Sorbent MaterialHandling EmissionChange0.0 0.0 0.0857 0.0857 0.0857 0.0 0.0 0.0 0.0 0.0SCR Reagent MaterialHandling EmissionChange (worst case)0.0 0.0 0.2143 0.2143 0.2143 0.0 0.0 0.0 0.0 0.0Total Project EmissionChange-19,246.5 30.0 2.79 333.5 292.8 5.2 0.021 236.5 4.11E-04 35,992Major Source Threshold(ton/yr)100 100 100 100 100 100 100 100 100 100,000PSD Threshold forSignificant NetEmission Rate40 40 25 15 10 100 40 7 0.6 75,000PSD Netting Required No No No Yes Yes No No Yes No NoContemporaneousProjects - AuxiliaryBoilersNA NA NA 0.96 0.96 NA NA 0.0 NA NAContemporaneousProjects - Shutdown ofUnits 1, 2, and 3NA NA NA -551.5 -421.8 NA NA -3.1 NA NATotal PSD EmissionChange-19,246.5 30.0 2.79 -217.0 -128.1 5.2 0.021 233.4 4.11E-04 35,992PSD Applicable No No No No No No No Yes No NoTable A-6 FOUR CORNERS Unit 4 and Unit 5 SCR Project PSD ApplicabilityEmission SourceDescription(a) 40 CFR 52.21(b)(41)(ii) In determining projected actual emissions under paragraph (b)(41) the operator shall exclude, incalculatingany increase in emissions that results from the particular project, that portion of the unit's emissions following the projectthat an existingunit could have accommodated during the consecutive 24-month period used to establish the baseline actual emissions under paragraph(b)(48) of this section and that are also unrelated to the particular project, including any increased utilization due to product demand growth.See details in Table A-3.NA = Not ApplicableNOxSO2PMPM10PM2.5CO VOC LeadGHG CO2e(ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr) (ton/yr)Unit 4 and 5 Baseline Emissions 24,029.2 8,373.2 644.2 801.3 550.0 1,443.9 5.787 1.15E-01 10,058,133Unit 4 and 5 Projected FutureEmissions4,782.7 8,403.2 646.5 1,134.4 842.5 1,449.0 5.808 1.15E-01 10,094,124Unit 4 and Unit 5 EmissionChange-19,246.5 30.0 2.3 333.1 292.4 5.17 0.0214.11E-04 35,992DSI Sorbent Truck TrafficEmission Change0.0 0.0 0.0952 0.0190 0.0047 0.0 0.00.0 0.0SCR Reagent Truck TrafficEmission Change (worst case)0.0 0.0 0.0871 0.0174 0.0043 0.0 0.00.0 0.0DSI Sorbent Material HandlingEmission Change0.0 0.0 0.0857 0.0857 0.0857 0.0 0.00.0 0.0SCR Reagent Material HandlingEmission Change (worst case)0.0 0.0 0.2143 0.2143 0.2143 0.0 0.00.0 0.0Total Project Emission Change -19,246.5 30.0 2.79 333.5 292.8 5.2 0.021 4.11E-04 35,992Tribal Significant Net EmissionRate10 10 10 5 3 10 5 0.1 NATribal NSR Netting Required No Yes No Yes Yes No No No NoContemporaneous Projects -Auxiliary BoilersNA 0.05 NA 0.96 0.96 NA NA NA NAContemporaneous Projects -Shutdown of Units1, 2, and 3(b)NA -3,110.1 NA -551.5 -421.8 NA NA NA NATotal Emission Change -19,246.5 -3,080.1 2.79 -217.0 -128.1 5.2 0.021 4.11E-04 35,992Tribal NSR Applicable No No No No No No No No NoNA = Not ApplicableEmission Source DescriptionTable A-7 FOUR CORNERS Unit 4 and Unit 5 SCR Project Tribal Minor Source NSR Applicability(a)(b) Annual average emissions for the years 2011 and 2012 based on APS CEMS data(a) Pollutants not subject to PSDFourCornersUnit 4FourCornersUnit 5Heat InputMMBtu/yr201483.90 76.52 80.21104,145,465201590.73 71.45 81.09105,286,324201679.96 83.62 81.79106,195,622201761.15 81.88 71.5192,855,166201886.65 62.75 74.7096,992,215201984.67 82.34 83.50108,421,857202083.08 85.37 84.22109,355,561202192.85 85.8589.35116,008,264202290.37 87.96 89.16115,770,562202365.79 90.32 78.06101,348,267202492.83 64.43 78.63102,094,163Capacity FactorYear FCPP AverageTable A-8 FCPP Projected Capacity Factors includingDemand Growth and Non-Project Related FactorsSCR Parasitic Load Calculation(a)Parameter Units ValueParasitic Load due to SCR, MW MW 3.80Gross Capacity, MW MW 810Unit 4 Hours at reduced load hr/yr 1,195Unit 5 Hours at reduced load hr/yr 4,112Hours in a Year hr/yr 8,760Unit 4 Parasitic Load Capacity Factor % 0.064%Unit 5 Parasitic Load Capacity Factor % 0.220%Average Parasitic load % 0.142%Economizer Bypass(b)Parameter Units Unit 4 2012 Unit 4 2013 Unit 5 2012 Unit 5 2013Average% of Operating Hours Needing Temperature Increase % 31.7% 24.1% 46.3% 33.9% 34.0%Temperature Increase Required °F 29.61 13.13 14.29 12.68 17.43Weighted Average Temperature Increase Required °F 9.4 3.2 6.6 4.3 5.9Operating Hours hr/yr 7,542 6,810 7,302 6,810 7,116Average Non-zero MW MW 719.3 725.7 746.3 684.0 718.9% Efficiency Loss/°F in Economizer %/°F 0.025% 0.025% 0.025% 0.025% 0.025%Total MWH Increase Due to Economizer Bypass MWh/yr 12,749 3,918 9,007 5,009 7,671Heat Rate Btu/KWh 9,800 9,800 9,800 9,800 9,800Total MMBtu Increase Due to Economizer Bypass MMBtu/yr 124,937 38,394 88,265 49,090 75,171Approximate Unit MWH/yr MWh/yr 5,425,205 4,942,251 5,449,796 4,658,170 5,118,855Approximate Capacity Factor % 80.2% 73.3% 80.6% 69.1% 75.8%Approximate Unit MMBtu/yr MMBtu/yr 53,167,009 48,434,058 53,408,003 45,650,062 50,164,783Increase in MMBtu/yr due to Economizer Bypass % 0.235% 0.079% 0.165% 0.108% 0.147%Total increased fuel use due to parasitc load and economizer bypass is esitimated to be 0.3% as shown above.(b) The SCR will, at times, require some bypasing of the economizer in order to maintain the requried SCR inlet temperature. This operating scenariocan result in increased fuel use.Table A-9 Estimated Increased Fuel Use due to SCR Parasitic Load and Economizer BypassCommentsAPS 2021 projected hours of operation at reduced load (highestcapacity factor of 92.8%)APS 2021 projected hours of operation at reduced load (highestcapacity factor of 85.8%)Information from Black & VeatchParasitic load / gross capacity x hours at reduced load / 8,760 hr/yrParasitic load / gross capacity x hours at reduced load / 8,760 hr/yr(a) This calculation is intended to account for increased fuel use due to the SCR parastiic load. Fuel feed to the furnaces can only be increased duirngperiods when they are operating at reduced load, When operating at full load, the fuel use cannot be increased; the net poweroutput will decrease.AECOM Environment

60221977-460 April 2014 

# Appendix B

RBLC Clearinghouse DataRBLCID FACILITYNAMECORPORATEORCOMPANYNAMEFACILITYCOUNTYFACILITYSTATEPERMITISSUANCEDATEFACILITYDESCRIPTION PROCESSNAMEPRIMARYFUELTHROUGHPUTTHROUGHPUTUNITCONTROLMETHODDESCRIPTIONEMISSIONLIMITEMISSIONLIMITUNITCASE‐BY‐CASEBASISAnalysisandCommentsSC‐0104SANTEECOOPERCROSSGENERATINGSTATIONSANTEECOOPER BERKELEY SC 2/5/2004 ELECTRICUTILITYBOILER,NO.3ANDNO.4BITUMINOUSCOAL5,700MMBTU/HUnit3hascoldsideESP,SCRandwetscrubber.0.00140 LB/MMBTUOtherCase‐by‐CaseUnit3stacktests(01/16‐01‐19/2007)showedemissionsat0.00021lb/MMBtu.December2006stacktestsonUnits1and2showedbothunitsat0.00040lb/MMBtuOK‐0118HUGOGENERATINGSTAWESTERFARMERSELECTRICCCOPCHOCTAW OK 2/9/2007COAL‐FIREDSTEAMEGUBOILER(HU‐UNIT2)PULVERIZEDCOALFIREDELECTRICGENERATINGUNITCOAL750MWSCR,BAGHOUSE,WETFGD0.00370 LB/MMBTU BACT‐PSDTheprojectwascancelled.Thisemissionratehasnotbeendemonstratedasachievedinpractice.TX‐0585TENASKATRAILBLAZERENERGYCENTERTENASKATRAILBLAZERPARTNERSLLCNOLAN TX 12/30/2010 Coal‐firedelectricgeneratingfacility Coal‐firedBoilerSub‐bituminouscoal8,307MMBTU/H Wetscrubber 0.00370 LB/MMBTU BACT‐PSDConstructionhasnotstarted.Therefore,thisemissionratehasnotbeendemonstratedasachievedinpractice..NotApplicableDesertRockGeneratingStationPublicServiceCompanyofNewMexicoNM Jul‐08 1,500MWcoalfiredpowerplant Coal‐firedBoiler Coal WetScrubber 0.00400 LB/MMBTU BACT‐PSDTheprojectwascancelled.Thisemissionratehasnotbeendemonstratedasachievedinpractice.MI‐0389KARNWEADOCKGENERATINGCOMPLEXCONSUMERSENERGYBAY MI 12/29/2009ELECTRICITYGENERATINGFACILITY,EXISTINGCAPACITYGREATERTHAN2,000MW.BOILERPRBCOALOR50/50BLEND8,190MMBTU/HHYDRATEDLIMEINJECTIONANDWETFGD0.00400 LB/MMBTU BACT‐PSDTheprojectwascancelled.Thisemissionratehasnotbeendemonstratedasachievedinpractice.UT‐0065INTERMOUNTAINPOWERGENERATINGSTATION‐UNIT#3INTERMOUNTAINPOWERSERVICECORPORATIONMILLARD UT 10/15/2004NEWPULVERIZEDCOALFIREDELECTRICGENERATINGUNIT#3,DESIGNEDAT950‐GROSSMW(900‐NETMW)WITHADRYBOTTOM,TANGENTIALLYFIREDORWALL‐FIREDBOILER.UNIT#3BOILERWILLBEEQUIPPEDWITHWETFLUEGASDESULPHURIZATION,LNB,OVERFIREAIR,SELECTIVECATALYTICREDUCTIONANDBAGHOUSESFORCONTROLOFVARIOUSEMISSIONS.THEEXISTINGPLANTHASTWODRUM‐TYPE,PULVERIZEDCOALFIREDBOILERS,DESIGNATEDASUNIT1ANDUNIT2,EACHWITH950‐GROSSMWPULVERIZEDCOALFIREDELECTRICGENERATINGUNITBITUMINOUSORBLEND950MW‐grossBAGHOUSE/FABRICFILTERANDWETFLUEGASDESULPHURIZATION0.00440 LB/MMBTU BACT‐PSDTheprojectwascancelled.Thisemissionratehasnotbeendemonstratedasachievedinpractice.NotApplicableCliffsideUnit6 Duke Rutherfird NC 1/29/2008 SupercriticalPC Unit6 HighScoal800MWSprydryerabsorber,baghouse,wetFGD0.0050 LB/MMBTU BACT‐PSDInitialstacktestresult:0.0010lb/MMBtu*MI‐0399DETROITEDISON‐‐MONROEDETROITEDISON MONROE MI 12/21/2010 Utility‐‐CoalfiredpowerplantBoilerUnits1,2,3and4Coal7,624MMBTU/HRESPsandwetfluegasdesulfurization.0.00500 LB/MMBTU BACT‐PSD ConstructedNotApplicablePrairieStateGenerationStationPrairieStateGeneratingCompanyWashington MO 12/28/2005Twopowerboilerswith1,500MWtotalcapacityburninghighsulfurcoalTwopulverizedcoalfiredboilersCoal7,450MMBtu/hreachSCR,ESP,WetFGD,WetESP0.00500 lb/MMBtu BACT‐PSD ConstructedTableB‐1SulfuricAcidMistEmissionLimitsforCoalFiredBoilersRBLCID FACILITYNAMECORPORATEORCOMPANYNAMEFACILITYCOUNTYFACILITYSTATEPERMITISSUANCEDATEFACILITYDESCRIPTION PROCESSNAMEPRIMARYFUELTHROUGHPUTTHROUGHPUTUNITCONTROLMETHODDESCRIPTIONEMISSIONLIMITEMISSIONLIMITUNITCASE‐BY‐CASEBASISAnalysisandCommentsTableB‐1SulfuricAcidMistEmissionLimitsforCoalFiredBoilersOH‐0310AMERICANMUNICIPALPOWERGENERATINGSTATIONAMERICANMUNICIPALPOWERMEIGS OH 10/8/2009TWO5191MMBTU/HOURPULVERIZEDCOAL‐FIREDBOILERS;ONE150MMBTU/HOURNATURALGASAUXILIARYBOILER,ONEFLYASHANDGYPSUMLANDFILL,COALSTORAGE,CRUSHERS,FERTILIZERPLANT,LIMESTONEANDFLYASHHANDLINGEQUIPMENT,ANDCOOLINGCELLS.BOILER(2),PULVERIZEDCOALFIREDPULVERIZEDCOAL5,191MMBTU/HWETFLUEGASDESULFURIZATION0.0075 LB/MMBTU BACT‐PSD CanceledNotApplicableELMROADGNEERATINGSTATIONWEENERGY WIJanuary2004and5/31/2011TWOPCUNITS,615MWEACHPCCOALFIREDBOILERSEASTERNCOAL6,180MMBTU/HREACHSCR,BAGHOUSE,WETFGD,WETESP0.01000 LB/MMBTU BACT‐PSD Stacktest2010:0.0029lb/MMBtuAECOM Environment

60221977-460 April 2014 

# Appendix C

Units 4 & 5 – Indirect Heat Exchanger H 2 

# SO 4 

# CAM PlanAECOM Environment 

### C

- 1

60221977

- 460 April 2014 

### Units 4 & 5

– Indirect Heat Exchanger

–

H 2 

### SO 4 

### C ompliance Assurance Monitoring (C AM ) Plan

This section contains the H 2 

### SO 4 

### CAM plan being proposed for Units 4 and 5. The control train for Units 4 and 5 includes an SO 3 

### mitigation system, which is the primary control system used to minimize the formation and emission of H 2 

### SO 4 

### . CAM Background

Table 1: Emission Unit and H 2 

### SO 4 

### Controls

Facility: Arizona Public Service Company
Four Corners Power Plant Fruitland, NM

Emission Unit Identification: Units 4 and 5

Description: Units 4 and 5 are dry bottom, opposed fired boilers with nominal heat capacit ies of 7,411 MMBtu/hr. At a nominal coal heat input of 8,776 Btu/lb, the each boiler can fire up to 422 tons/h ou r of coal. Unit 4 was constructed in 1969 and Unit 5 was constructed in 1970

.

H 2 

### SO 4 

### Controls: Upon completion of the project

, as outlined in the PSD permit application, each boiler will be equipped with low

- NOx cell burners, an SCR system, an SO 3 

### mitigation system, a baghouse, and a wet FGD system. The SO 3 

### mitigation system will be designed specifically to control SO 3 

### and, subsequently, the formation of H 2 

### SO 4 

### emissions.

Table 2: Applicable Regulations and Current Monitoring for H 2 

### SO 4



### Pollutant: H 2 

### SO 4



### Regulation: Expected PSD BACT emission limit to be issued pursuant to 40 CFR 52.21(b)(12)

Emission Limit: There currently is no H 2 

### SO 4 

### emission limit in place for Units 4 and 5. The proposed BACT emission limit s are 0.0 04 35 lb/MMBtu which is equivalent to 1.5 ppmvd corrected to 3% O 2 

### . Current Monitoring Requirements: As there is currently no applicable H 2 

### SO 4 

### emission limit, there are no current monitoring requirements specifically for H 2 

### SO 4 

### .

Table 3: Current Estimated Pre

- Controlled and Controlled H 2 

### SO 4 

### Emissions

CAM Designation: Large PSEUAECOM Environment 

### C

- 2

60221977

- 460 April 2014 

### CAM Applicability
The Units 4 and 5 boilers will be subject to a BACT emission limit for H 2 

### SO 4 

### upon issuance of the PSD permit. Pursuant to 40 CFR 64.2(a), because the SO 3 

### mitigation system is used to achieve compliance with this emission limit and potential pre

- controlled H 2 

### SO 4 

### emissions (calculated at the exit of the air pre

heater) exceed 100 tpy, CAM applies to the Units 4 and 5 boilers for H 2 

### SO 4 

### . This CAM P lan addr esses the proposed monitoring that will ensure compliance with the H 2 

### SO 4 

### emission limit.

Monitoring Approach for H 2 

### SO 4


### SO 3 

### is generated in the Units 4 and 5 boilers due to the oxidation of sulfur in the combustion process. Additional SO 3 

### can be generated in the SCR unit due to catalytic oxidation of SO 2 

### to SO 3 

### . The amount of SO 3 

### generated is a function of coal sulfur content, operating conditions (e.g., gas temperature) and characteristics of the SCR system (e.g., catalytic material). S O 3 

### reacts with water in the flue gas to form H 2 

### SO 4 

### vapor, which then condenses to form sub

- micron H 2 

### SO 4 

### mist. APS will primarily utilize an SO 3 

### mitigation system to control H 2 

### SO 4 

### formation and emissions although the SO 3 

### control attained in the other existing control devices for PM and SO 2 

### namely the baghouses and wet FGD s , is also enhance the SO 3 

### system.
The specific design and operation of the SO 3 

### mitigation system has not yet been finalized

, so APS is still working wit h prospective equipment vendors on design details . However, it is anticipated that the system will use hydrated lime and will consist of a sorbent receiving and storage system and an injection system. The sorbent will be injected in the flue gas immediat ely downstream of the economizer . The sorbent reacts with the SO 3 

### to form solid compounds (e.g., sodium sulfate), which are removed in the dry baghouses and wet FGD systems.

The effectiveness of the SO 3 

### mitigation system will be a function of the sorbent injection rate, the stoichiometric ratio of calcium to sulfur, the sorbent particle size and physical characteristics (e.g., surface area), the degree of mixing in the flue gas, and residence time. The mixing and residence time properties are not anticipated to be control parameters once the system is installed. Direct continuous measurement of SO 3 

### and/or H 2 

### SO 4 

### in the flue gas is not technically feasible currently. Therefore, APS proposes to use the so rbent injection rate as the primary indicator of performance of the SO 3 

### mitigation system. Continuously monitored SO 2 

### emissions will also be used as a secondary indicator parameter, since SO 3 

### formation, and thus H 2 

### SO 4 

### emissions, may be correlated to SO 2 

### emissions

. APS is not in the position of having had a PSD construction permit issued, and initial compliance tests completed before the requisite CAM P lan is submitted. Accordingly, certain aspects of the monitoring approach proposed cannot be finalized or implemented until start

- up and initial performance testing are completed. Pending future changes based on the results of the initial compliance testing, the monitoring approach outlined in Table 4 should provide on

- going assurance of compliance with th e anticipated H 2 

### SO 4 

### BACT emission limit. The specific details regarding each monitoring method and the monitoring performance criteria are provided in the following table:

Table 4: Units 4 and 5

– Monitoring Approach Summary for H 2 

### SO 4



### Method Indicator Parameter Range Frequency

1. SO 3 

### Mitigation System Monitoring Sorbent Injection Rate (lb/hr/acfm ) To be established during initial performance t est Continuous

2. SO 2 

### Emissions Monitoring SO 2 

### Emission Rate (30

- day rolling average) <0.30 lb/MMBtu ContinuousAECOM Environment 

### C

- 3

60221977

- 460 April 2014 

### Table 5: Primary Indicator #1

– Sorbent Injection Rate

General Criteria

Primary Indicator Sorbent Injection Rate (lb/hr/acfm)

Measurement Approach Sorbent injection rate will be continuously recorded (data captured at least once every 15 minutes)

Indicator Range A minimum injection rate threshold will be set during the first performance test. An excursion will be defined if the hourly average injection rate falls below this threshold.

Corrective Actions In response to an excursion, APS will initiate an inspection of the injection system to determine the cause within 30 minutes of discovery and then will correct any revealed performance issues in the most expedient manner possible.

Performance Criteria

Data Representativeness A mass flow meter will be installed on the injection line between the sorbent storage silo and injection point. The specific manufacturer and model for the flow meter will be selected as part of the final engineering design of the system. The mass flow m eter will be selected to have an accuracy of approximately ± 10% of the target
span

.

Verification of Operational Status APS will follow the installation, calibration, and startup procedures recommended by the manufacturer of the equipment prior to putting the metering system into operation.

QA/QC Practices and Criteria The mass flow meter will be periodically calibrated in accordance with the manufacturer’s recommended practices.

Monitoring Frequency

Data Collection Procedure

Averaging Period Mass flow data will be captured at least once every 15 minutes when the system is in use. The mass flow meter will be equipped with a process logic controller that will capture readings electronically and send t hem to a data storage drive, where the informatio n can be monitored and trended. Up to four (4) readings each hour will be averaged to yield an hourly average injection rate for each operating hour of the day

.

Recordkeeping • Electronic archives of sorbent injection rate data

• The causes and corrective actions taken associated with any excursions will be noted in the maintenance log

• Documentation and records of mass flow meter calibrations

Reporting A summary of sorbent injection readings and a tally of excursions will be provided in the Title V semi

- an nual monitoring reports.AECOM Environment 

### C

- 4

60221977

- 460 April 2014 

### Secondary Indicator #2

– SO 2 

### Emission Rates

The Unit s 4 and 5 boilers will use a 40 CFR Part 75 compliant CEMS to continuously measure SO 2 

### at the outlet of the main stack as a backup in case the primary indicator is out of service . The data reporting system for the CEMS will calculate SO 2 

### emission rates in terms of lb/MMBtu based on a 30

- day average for the emission units. SO 2 

### emissions from Units 4 and 5 will be limited to 0.30 lb /MMBtu based on a rolling 30 boiler operating day average pursuant to the Mercury Air Toxics Standard. In response to an excursion, APS will initiate an inspection of the SO 3 

### mitigation system within 30 minutes of discovery to determine the cause and then will correct any revealed performance issues in the most expedient manner possible.

Monitoring Approach Justification
Rational for Selecting Performance Indicators
Monitoring of the sorbent injection rate provides direct co nfirmation that the SO 3 

### mitigation system is in operation. Because other variables associated with the operation of the SO 3 

### mitigation system (e.g., size and characteristics of the sorbent) are relatively fixed upon start

- up and reaching steady

- state oper ation, maintaining the sorbent injection rate at a value that exceeds the lower threshold value established in the performance test will ensure that H 2 

### SO 4 

### emissions are also kept to levels less than the permit limit.
During the initial performance test, AP S will confirm that when the SO 2 

### emission rate is below the allowable emission rate, the H 2 

### SO 4 

### emission s are also below their allowable rate. Because SO 2 

### and H 2 

### SO 4 

### emissions should be correlated, SO 2 

### should serve as a suitable surrogate for H 2 

### SO 4 

### emissions. Therefore, continuous monitoring of SO 2 

### at levels below its allowable rate will provide a level of assurance that the H 2 

### SO 4 

### emissions also remain below the allowable rate.
Rational for Selecting Indicator Ranges
Because the specific vendor and design of the SO 3 

### mitigation system has not yet been selected, and initial performance testing has not yet been completed, it is not possible to establish the excursion range for the sorbent injection rate. APS will follow the initial SO 2 

### and H 2 

### SO 4 

### compliance testing schedule specified in the PSD permit, and anticipates that testing will occur within 180 days of start

- up of the SCR system. During the test, monitoring data will be collected to establish the threshold. This testing will be conducted under conditions that would be expected to yield the highest H 2 

### SO 4 

### emission rate (e.g., highest coal sulfur content and lowest SO 3 

### sorbent injection rates). SO 2 

### emissions will be continuously monitoring simultaneous with the H 2 

### SO 4 

### emissions testing. The final test plan will detail the operating conditions and target sorbent injection rates that will be used during which H 2 

### SO 4 

### emissions are measured. The target sorbent injection rates for the final initial test will be determined based on consultations with the equipment vendor.AECOM Environment

60221977-460 April 2014 

# Appendix D

H 2 

# SO 4 

# Source Test Report

# T EST 

# R EPORT

In

- House Engineering Test

On F ive 

# C OAL FIRED 

# U NITS

At The 

# Four Corners Power Plant

Located near 

# Fruitland, New Mexico

Prepared For 

# Arizona Public Service
Four Corners Power Plant End of County Road 6675 Fruitland, New Mexico 87416



# Prep ared By 

# TRC Environmental Corporation 7761 Shaffer Parkway Suite 100 Littleton, Colorado 80127



# TRC Report No. 182436

. INHE

April

- September 2011

# T EST 

# R EPORT

In

- House Engineering Test

On F ive 

# C OAL FIRED 

# U NITS

At The 

# Four Corners Power Plant

Loca ted near 

# Fruitland, New Mexico

Prepared For 

# Arizona Public Service
Four Corners Power Plant End of County Road 6675 Fruitland, New Mexico 87416



# Prepared By 

# TRC Environmental Corporation 7761 Shaffer Parkway Suite 100 Littleton, Colorado 80127

TRC Project No. 182436 .0000.0000

April

- September 2011

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE iii 

# TABLE OF CONTENTS

Page

1.0 INTRODUCTION ..................................................................................................... 1

1.1 Test Objectives ............................................................................................. 1

1.2 Process Description ...................................................................................... 1

2.0 SUMMARY OF RESULTS ...................................................................................... 5

3.0 PROCEDURES ..................................................................................................... 15

3.3 Percent Moisture Measurement ................................................................. 15

3.2 O 2 

## Determination ........................................................................................ 15

3.3 SO 3 

## Determination ...................................................................................... 16

4.0 QUALITY ASSURANCE / QUALITY CONTROL ................................................. 18

4.1 O 2 

## Continuous Emissions Monitors ............................................................ 18

4.2 Moisture ...................................................................................................... 19

4.3 SO 3 

## Sampling ............................................................................................ 19

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE iv 

# LIST OF TABLES

Page

Table 1-1. Executive Summary Units 1- 5 (ppmv, lb/hr) ................................................. 2 Table 1-2. Executive Summary Units 1- 5 (lb/MMBTU, lb/MWH) ................................... 3 Table 1-3. General Facility and Testing Information ....................................................... 4

Table 1-4. Test Methods .................................................................................................. 4 Table 2-1. Summary of Results Unit 1 ............................................................................ 7 Table 2-2. Summary of Results Unit 2 ............................................................................ 8 Table 2-3. Summary of Results Unit 3 ............................................................................ 9 Table 2-4. Summary of Results Unit 4 .......................................................................... 10 Table 2-5. Summary of Results Unit 5 (April) ............................................................... 11 Table 2-6. Summary of Results Unit 5 APH Inlet .......................................................... 12 Table 2-7. Summary of Results Unit 5 APH Outlet ....................................................... 13 Table 2-8. Summary of Results Unit 5 (September) ..................................................... 14

Table 3-1. List of Instruments ....................................................................................... 16

Table 4-1. Reference Method CEMS Performance Criteria .......................................... 19



# LIST OF FIGURES

Page

Figure 3-1. CTM-013 Sample System Diagram ............................................................ 17

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE v 

# A PPENDICES

Page

APPENDIX A – FIELD DATA SHEETS ........................................................................ A1

APPENDIX B – EXAMPLE CALCULATIONS .............................................................. B1
APPENDIX C – QUALITY ASSURANCE ACTIVITIES ................................................. C1

APPENDIX D – CALIBRATION CERTIFICATIONS ..................................................... D1

APPENDIX E – LOGGED DATA RECORDS ................................................................ E1

APPENDIX F – UNIT OPERATIONAL DATA ............................................................... F1

APPENDIX G – LABORATORY ANALYSES DATA .................................................... G1

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE vi 

# LIST OF ACRONYMS AND ABBREVIATIONS

% Percent

o F Degrees Fahrenheit BACT Best Available Control Technology CEMS Continuous Emission Monitor System CFR Code of Federal Regulations CO 2 

## Carbon Dioxide CTM Conditional Test Method DSCFH Dry Standard Cubic Feet per Hour EPA Environmental Protection Agency H 2 

## O 2 

## Hydrogen Peroxide H 2 

## SO 4 

## Hr Sulfuric Acid Hour lb Pounds lb/HR Pounds per Hour MMBTU Million British Thermal Units MSCFH Thousand Standard Cubic Feet per Hour MW Megawatts MWH Megawatts per Hour NO X 

## Nitrogen Oxides O 2 

## Oxygen PPMV Parts Per Million Volume QA/QC Quality Assurance/Quality Control SCF Standard Cubic Feet SCFH Standard Cubic Feet per Hour SO 2 

## Sulfur Dioxide SO 3 

## Sulfur Trioxide Vol % Percentage on Volume Basis VOC Volatile Organic Compounds WSCFH Wet Standard Cubic Feet per Hour

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE vii 

## I certify that to the best of my knowledge:

• Test data and all corresponding information have been checked for accuracy and completeness.

• Analyses have been conducted in accordance with approved protocol, reference methods, and the requirements of NELAC (as applicable).

• All deviations, method modifications, or analytical anomalies are summarized in the appropriate report narrative(s).

• Test results presented in the report relate only to the samples and test conditions presented in this report.

• This report includes a total of 196 pages.

Jason Grizzle, Operations Manager

Date of Issue: November 29, 2011

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE 

## 1.0 INTRODUCTION

TRC Environmental Corporation (TRC) of Littleton, Colorado was retained by Arizona Public Service (APS) to conduct Sulfur Trioxide (SO 3 

## ) testing at the Four Corners Power Plant located on the Navajo Nation near Fruitland, New Mexico. TRC conducted this testing over three mobilizations, spanning from April 2011 through September 2011. This document presents
the results for each unit and the time frame it was tested.

Table 1-1 presents an executive summary of the testing results for the units in parts per million by volume (ppmv) and pounds per hour (lb/hr. Table 1-2 presents an executive summary of the testing results for the unit’s emission rates in pounds per million British thermal units (lb/MMBTU) and pounds per Megawatt hour (lb/MWH). Table 1-3 presents the general facility and testing information. Section 2.0 of this report includes test result summaries. Section 3.0 of this report describes the test methods used including details specific to this test program. Section 4.0 describes the Quality Assurance/ Quality Control (QA/QC) procedures that were used during the sampling phase of this testing.

1.1 Test Objectives

The testing program for each of the five coal fired units included three runs each of which was at a minimum one hour in duration. During each run samples were collected to determine
the SO3 concentrations. The concentrations were then used to calculate the emissions of SO3 using the volumetric flow rates and process parameter supplied by APS personnel. All samples for each measured compound were collected simultaneously during each run. The methods shown in Table 1-2 were used to measure the concentrations and flow rates of the components of interest. Table 1-3 presents a summary of the sample collection strategies used during this testing.

1.2 Process Description

The Four Corners Power Plant, located on the Navajo Nation near Fruitland, New Mexico, is a pulverized coal fired, steam generating electric utility plant serving Arizona and California. Four Corners Power Plant consists of five electrical generating units and auxiliary equipment that provide a generating capacity of approximately 2,060 megawatts (MW).

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE



## Table 1-1. Executive Summary Units 1- 5 (ppmv, lb/hr)

Parameter Location Unit Date of testing Average
Test Result

SO 3 

## (ppmv dry) Stack 1 6/14/11 0.02

SO 3 

## (lb/hr) Stack 1 6/14/11 0.13

SO 3 

## (ppmv dry) Stack 2 4/7/2011 0.06

SO 3 

## (lb/hr) Stack 2 4/7/2011 0.34

SO 3 

## (ppmv dry) Stack 3 4/7/2011 < 0.03

SO 3 

## (lb/hr) Stack 3 4/7/2011 < 0.25

SO 3 

## (ppmv dry) Stack 4 4/6/2011 < 0.05

SO 3 

## (lb/hr) Stack 4 4/6/2011 < 0.89

SO 3 

## (ppmv dry) Stack 5 4/5/2011 < 0.05

SO 3 

## (lb/hr) Stack 5 4/5/2011 < 0.93

SO 3 

## (ppmv dry) APH Inlet 5 9/30/2011 2.07

SO 3 

## (lb/hr) APH Inlet 5 9/30/2011 48.48

SO 3 

## (ppmv dry) APH Outlet 5 9/30/2011 0.18

SO 3 

## (lb/hr) APH Outlet 5 9/30/2011 4.12

SO 3 

## (ppmv dry) Stack 5 9/30/2011 0.08

SO 3 

## (lb/hr) Stack 5 9/30/2011 1.76

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE 

## Table 1-2. Executive Summary Units 1- 5 (lb/MMBTU, lb/MWH)

Parameter Location Unit Date of testing Average Test
Result
SO3 (lb/MMBTU) Stack 1 6/14/11 0.000068

SO3 (lb/MWH) Stack 1 6/14/11 0.00073
SO3 (lb/MMBTU) Stack 2 4/7/2011 0.00018

SO3 (lb/MWH) Stack 2 4/7/2011 0.0020

SO 3 

## (lb/MMBTU) Stack 3 4/7/2011 < 0.000094

SO 3 

## (lb/MWH) Stack 3 4/7/2011 < 0.0011

SO 3 

## (lb/MMBTU) Stack 4 4/6/2011 < 0.00014

SO 3 

## (lb/MWH) Stack 4 4/6/2011 < 0.00113

SO 3 

## (lb/MMBTU) Stack 5 4/5/2011 < 0.00014

SO 3 

## (lb/MWH) Stack 5 4/5/2011 < 0.0013

SO 3 

## (lb/MMBTU) APH Inlet 5 9/30/2011 0.0064

SO 3 

## (lb/MWH) APH Inlet 5 9/30/2011 0.062

SO 3 

## (lb/MMBTU) APH Outlet 5 9/30/2011 0.00055

SO 3 

## (lb/MWH) APH Outlet 5 9/30/2011 0.0052

SO 3 

## (lb/MMBTU) Stack 5 9/30/2011 0.00023

SO 3 

## (lb/MWH) Stack 5 9/30/2011 0.0022

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE 

## Table 1-3. General Facility and Testing Information

Source Owner Arizona Public Service

Source Location Four Corners Power Plant End of County Road 6675 Fruitland, New Mexico 87416
Contact Person Alan Papp Contact Telephone Number (602) 250-5407 Contact Email Address Alan.Papp@aps.com

Contact Address End of San Juan County Road 6675 Fruitland, New Mexico 87416 Types of Process Sampled Exhaust stacks associated with four Coal fired Units Emission Source Stacks of Units 1, 2, 3, 4, and 5 Testing Firm Representative Jason Grizzle Telephone Number (303) 395-4056 Email Address jgrizzle@trcsolutions.com Company Name TRC Environmental Corporation Address 7761 Shaffer Pkwy Suite 100 Littleton, CO 80127

Test Methods Performed EPA Method 3A – O 2 

## Concentration
EPA Method 4 – Stack Gas Moisture
EPA Conditional Test Method 013– SO 3 

## Concentration

Testing Dates April 5-7, June 14, and September 30, 2011

Table 1-4. Test Methods

Parameter Test Method Measurement Technique Modifications to Method

Moisture EPA Method 4 Gravimetrical Analyses of collected moisture in an impingement train None

O 2 

## EPA Method 3A Continuous Analyzer Paramagnetic cell Sampling conducted using Tedlar Bags for some sources

SO 3 

## EPC CTM-013 Controlled Condensation Sample analysis by ion chromatograph

### Emission Test Report Five Coal Fired Units April

- September 2011

Report 

### No.: 182436.INHE 

## 2.0 SUMMARY OF RESULTS

Detailed test results are presented and discussed in this section. Detailed descriptions of the procedures used to perform the compliance test measurements are presented in Section 3.0 of this report.

TRC Environmental Corporation conducted In-House Engineering Testing on five coalfired boilers to determine the emissions of SO 3


## . This testing was conducted at the Arizona Public Service’s Four Corners Power Plant located near Fruitland, New Mexico. These tests were conducted over three separate mobilizations consisting of the date; April 5 through 7, June 14, and September 30, 2011.

Testing in April consisted of determining the emission of SO 3 

## for four of the five units, which included 2, 3, 4 and 5. Unit 1 was not tested during this period due to the unit not being operational at the time of the testing. During each test, three runs were conducted on each unit to
determine the concentrations of SO 3 

## and oxygen (O 2 

## ). These concentrations were determined using the procedures of United State Environmental Protection Agency (EPA) Methods 3A and Condition Test Method (CTM) 013. Each test run was a minimum of 60-minutes in duration while the units were operating at normal load rates. Samples of SO 3 

## were collected in the appropriate sample containers and shipped to a NELAC Accredited laboratory where they were analyzed for SO 3 

## concentrations using ion chromatographic techniques as opposed to the thorin titration techniques. The Tables 2-2 through 2-5 represents the results from these tests on the
four units.

Unit 1 located at the Four Corners Power Plant was tested on June 14, 2011 to determine
the emission of SO 3 

## . Three test runs of 120 minutes in duration were conducted on the unit while operating at normal load rates. SO 3 

## and O 2 

## concentration were collected and analyzed using the EPA Methods 3A and CTM-013. Samples for O 2 

## were collected in Tedlar bags during the sample runs and transported to the stack testing trailer for analyses by instruments as outlined in the EPA Method 3A. Samples of SO 3 

## were collected in the appropriate sample containers and shipped to a NELAC Accredited laboratory where they were analyzed for SO 3 

## concentrations using ion chromatographic techniques as opposed to the thorin titration techniques. The results of this testing can be found in Table 2-1 of this report.

On September 30, 2011 testing was conducted at the APS Four Corners Facility on the Unit 5 located within the facility. Three sampling locations throughout the unit were determined by APS personnel, which consisted of before and after the Air Preheater (APH) and the stack of

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## the unit. Each location was tested to determine the concentrations of SO 3 

## and O 2 

## using the same sampling techniques as employed on Unit 1 during the testing in June. Testing was conducted while the unit was operating at normal load rates. Three test runs were conducted on the APH Inlet and APH Outlet over 60 minutes each, while the testing at the stack of the unit was conducted over three runs of 120 minutes in duration. Samples for O 2 

## were collected in Tedlar bags during the sample runs and transported to the stack testing trailer for analyses by instruments as outlined in the EPA Method 3A. Samples of SO 3 

## were collected in the appropriate sample containers and shipped to a NELAC Accredited laboratory where they were analyzed for SO 3 

## concentrations using ion chromatographic techniques as opposed to the thorin titration techniques. The results of these tests are depicted in Tables 2-6 through 2-8 of this report.

For all the testing conducted on these units the mass emission rates of SO 3 

## were calculated from the concentrations determined during testing and the volumetric flow rates provided by APS personnel. The volumetric flow rates were either determined from theoretical
calculations of fuel combustion or from continuous flow rate monitors installed on the stacks of
the units. The mass emissions of SO 3 

## were calculated from these volumetric flow rates and the corresponding concentration of SO 3 

## . Additionally, APS personnel provide other process parameters to determine the mass emissions in terms of lb/hr, lb/MMBTU and lb/MWH as requested.

All field data sheets utilized in this testing are presented in Appendix A of this report. Example calculations are located in Appendix B. Quality assurance activities are documented in Appendix C. Calibration certifications supporting the results are in Appendix D. Data acquisition records from TRC instrumentation can be found in Appendix E. Operational data is contained in Appendix F. Laboratory analyses data performed by Resolution Analytics can be found in Appendix G.

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## Table 2-1. Summary of Results Unit 1

Client: Arizona Public Service Facility: Four-Corners Facility Fruitland, NM Technicians: RS Project Number: 182436.0000.0000 SOURCE Unit 1 TEST RUN 1 2 3 AVERAGE
Date 6/14/11 6/14/11 6/14/11 Start Time 10:35 12:47 14:56 Stop Time 12:35 14:47 16:56 PROCESS DATA Electric Power Production (MW) 170.2 170.4 170.5 170.4 Fuel Flow (MMBTU/Hr) 1845.1 1840.1 1850.5 1845.2 Fuel Flow Rate of Max (%) 55.8 55.3 55.3 55.5
CEMS O 2 

## (%) 7.6 7.6 7.6 7.6 APS Calculated Volumetric Flow Rate (SCFH) 31,500,000 31,500,000 31,500,000 31,500,000
CEMS SO 2 

## (ppm) 36.0 35.8 38.8 36.9
AMBIENT CONDITIONS Atmospheric Pressure (in. Hg) 24.62 24.62 24.62 24.62 STACK CONCENTRATIONS
O 2 

## (vol %, dry) 6.0 6.1 6.1 6.0 Moisture (%) 14.3 16.1 16.7 15.73
SO 3 

## (ppmv, dry) 0.02 0.02 < 0.01 0.02
OUTLET EMISSION RATES
SO 3 

## (lb/hr) 0.16 0.12 < 0.09 0.13
SO 3 

## (lb/MMBTU) 0.000088 0.000065 < 0.000051 0.000068
SO 3 

## (lb/MWH) 0.00095 0.00070 < 0.00055 0.00073

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## Table 2-2. Summary of Results Unit 2

Client: Arizona Public Service Facility: Four-Corners Facility Fruitland, NM Technicians: TJS, BJM Project Number: 182436.0000.0000 SOURCE Unit 2 TEST RUN 1 2 3 AVERAGE
Date 4/7/11 4/7/11 4/7/11 Start Time 19:30 21:00 22:05 Stop Time 20:30 22:00 23:05 PROCESS DATA Electric Power Production (MW) 170.9 170.7 170.5 170.7 Fuel Flow (MMBTU/Hr) 1877.3 1887.8 1894.1 1886.4 Fuel Flow Rate of Max (%) 57.6 58.3 59.2 58.4
CEMS O 2 

### (%) 5.5 5.6 5.6 5.6 APS Calculated Volumetric Flow Rate (SCFH) 27,734,220 27,734,220 27,734,220 27,734,220
CEMS SO 2 

### (ppm) 53.3 49.7 45.9 49.6
AMBIENT CONDITIONS Atmospheric Pressure (in. Hg) 24.11 24.20 24.20 24.17 STACK CONCENTRATIONS
O 2 

### (vol %, dry) 8.1 8.6 8.8 8.5 Moisture (%) 16.0 14.7 15.2 15.3
SO 3 

### (ppmv, dry) 0.05 0.03 0.09 0.06
OUTLET EMISSION RATES
SO 3 

### (lb/hr) 0.30 0.20 0.54 0.34
SO 3 

### (lb/MMBTU) 0.00016 0.00011 0.00028 0.00018
SO 3 

### (lb/MWH) 0.0017 0.0012 0.0031 0.0020

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## Table 2-3. Summary of Results Unit 3

Client: Arizona Public Service Facility: Four-Corners Facility Fruitland, NM Technicians: TJS, BJM Project Number: 182436.0000.0000 SOURCE Unit 3 TEST RUN 1 2 3 AVERAGE
Date 4/7/11 4/7/11 4/7/11 Start Time 10:10 11:35 13:00 Stop Time 11:10 12:35 14:00 PROCESS DATA Electric Power Production (MW) 221.0 220.7 220.5 220.7 Fuel Flow (MMBTU/Hr) 2633.9 2639.2 2644.4 2639.2 Fuel Flow Rate of Max (%) 65.0 64.4 64.1 64.5
CEMS O 2 

## (%) 2.7 2.7 2.7 2.7 APS Calculated Volumetric Flow Rate (SCFH) 35,298,000 35,298,000 35,298,000 35,298,000
CEMS SO 2 

## (ppm) 55.7 43.6 39.6 46.3
AMBIENT CONDITIONS Atmospheric Pressure (in. Hg) 24.34 24.31 24.24 24.30 STACK CONCENTRATIONS
O 2 

## (vol %, dry) 6.5 6.4 6.3 6.4 Moisture (%) 13.0 13.6 7.9 11.5
SO 3 

## (ppmv, dry) <0.03 <0.03 <0.04 <0.03
OUTLET EMISSION RATES
SO 3 

## (lb/hr) <0.21 <0.22 <0.32 <0.25
SO 3 

## (lb/MMBTU) <0.000079 <0.000082 <0.000121 <0.000094
SO 3 

## (lb/MWH) <0.0009 <0.0010 <0.0014 <0.0011

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## Table 2-4. Summary of Results Unit 4

Client: Arizona Public Service Facility: Four-Corners Facility Fruitland, NM Technicians: TJS, BJM Project Number: 182436.0000.0000 SOURCE Unit 4 TEST RUN 1 2 3 AVERAGE
Date 4/6/11 4/6/11 4/6/11 Start Time 09:05 10:35 12:05 Stop Time 10:05 11:35 13:05 PROCESS DATA Electric Power Production (MW) 785.8 784.4 786.4 785.5 Fuel Flow (MMBTU/Hr) 6405.0 6348.8 6332.1 6362.0 Fuel Flow Rate of Max (%) 64.1 64.3 64.5 64.3
CEMS O 2 

## (%) 2.4 2.4 2.5 2.4 APS Calculated Volumetric Flow Rate (SCFH) 85,084,020 85,084,020 85,084,020 85,084,020
CEMS SO 2 

## (ppm) 66.1 63.8 59.8 63.3
AMBIENT CONDITIONS Atmospheric Pressure (in. Hg) 24.40 24.41 24.36 24.39 STACK CONCENTRATIONS
O 2 

## (vol %, dry) 5.1 5.1 5.1 5.1 Moisture (%) 12.1 11.0 16.1 13.1
SO 3 

## (ppmv, dry) 0.05 0.06 <0.04 <0.05
OUTLET EMISSION RATES
SO 3 

## (lb/hr) 0.87 1.08 <0.72 <0.89
SO 3 

## (lb/MMBTU) 0.00014 0.00017 <0.00011 <0.00014
SO 3 

## (lb/MWH) 0.0011 0.0014 <0.00092 <0.0011

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## Table 2-5. Summary of Results Unit 5 (April)

Client: Arizona Public Service Facility: Four-Corners Facility Fruitland, NM Technicians: TJS, BJM Project Number: 182436.0000.0000 SOURCE Unit 5 TEST RUN 1 2 3 AVERAGE
Date 4/5/11 4/5/11 4/5/11 Start Time 14:00 16:00 18:00 Stop Time 15:00 17:00 19:00 PROCESS DATA Electric Power Production (MW) 745.6 745.5 745.3 745.4 Fuel Flow (MMBTU/Hr) 6755.3 6720.6 6716.8 6730.9 Fuel Flow Rate of Max (%) 63.8 63.8 64.2 63.9
CEMS O 2 

### (%) 2.3 2.3 2.3 2.3 APS Calculated Volumetric Flow Rate (SCFH) 90,021,780 90,021,780 90,021,780 90,021,780
CEMS SO 2 

### (ppm) 92.5 81.9 75.0 83.1
AMBIENT CONDITIONS Atmospheric Pressure (in. Hg) 24.39 24.32 24.29 24.33 STACK CONCENTRATIONS
O 2 

### (vol %, dry) 6.2 6.2 6.3 6.2 Moisture (%) 8.9 10.4 9.2 9.52
SO 3 

### (ppmv, dry) <0.02 <0.03 0.09 <0.05
OUTLET EMISSION RATES
SO 3 

### (lb/hr) <0.45 <0.64 1.71 <0.93
SO 3 

### (lb/MMBTU) <0.000066 <0.000096 0.00025 <0.0001389
SO 3 

### (lb/MWH) <0.00060 <0.00086 0.0023 <0.0012526

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## Table 2-6. Summary of Results Unit 5 APH Inlet

Client: Arizona Public Service Facility: Four-Corners Facility Fruitland, NM Technicians: RS, GH, JH, CM, JE Project Number: 182436.0000.0000 SOURCE TEST RUN 1 2 3 AVERAGE
Date 9/30/11 9/30/11 9/30/11 Start Time 10:30 12:03 13:20 Stop Time 11:30 13:03 14:20 PROCESS DATA Electric Power Production (MW) 787.5 787.0 787.4 787.3 Fuel Flow (MMBTU/Hr) 7524 7533 7534 7530 Fuel Flow Rate of Max (%) 68.8 68.9 69.1 68.9
CEMS O 2 

## (%) 5.6 5.9 5.7 5.8 CEMS Volumetric Flow Rate (SCFH) 112,396,778 112,734,454 113,450,437 112,860,556
CEMS SO 2 

## (ppm) 46.0 48.2 43.6 45.9
AMBIENT CONDITIONS Atmospheric Pressure (in. Hg) 24.87 24.87 24.87 24.87 Unit 5 APH Inlet

STACK CONCENTRATIONS
O 2 

## (vol %, dry) 6.1 6.1 5.9 6.0
SO 3 

## (ppmv, dry) 2.15 1.78 2.28 2.07
OUTLET EMISSION RATES
SO 3 

## (lb/hr) 50.10 41.66 53.67 48.48
SO 3 

## (lb/MMBTU) 0.0067 0.0055 0.0071 0.0064
SO 3 

## (lb/MWH) 0.0636 0.0529 0.0682 0.0616

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## Table 2-7. Summary of Results Unit 5 APH Outlet

Client: Arizona Public Service Facility: Four-Corners Facility Fruitland, NM Technicians: RS, GH, CM, JH, JE Project Number: 182436.0000.0000 SOURCE TEST RUN 1 2 3 AVERAGE
Date 9/30/11 9/30/11 9/30/11 Start Time 10:30 12:00 13:15 Stop Time 11:30 13:00 14:15 PROCESS DATA Electric Power Production (MW) 787.5 787.0 787.4 787.3 Fuel Flow (MMBTU/Hr) 7524 7533 7534 7530 Fuel Flow Rate of Max (%) 68.8 68.9 69.1 68.9
CEMS O 2 

## (%) 5.6 5.9 5.7 5.8 CEMS Volumetric Flow Rate (SCFH) 112,396,778 112,734,454 113,450,437 112,860,556
CEMS SO 2 

## (ppm) 46.0 48.2 43.6 45.9
AMBIENT CONDITIONS Atmospheric Pressure (in. Hg) 24.84 24.84 24.84 24.84 Unit 5 APH Out

STACK CONCENTRATIONS
O 2 

## (vol %, dry) 6.5 6.4 6.5 6.5
SO 3 

## (ppmv, dry) 0.20 0.19 0.14 0.18
OUTLET EMISSION RATES
SO 3 

## (lb/hr) 4.59 4.37 3.40 4.12
SO 3 

## (lb/MMBTU) 0.00061 0.00058 0.00045 0.00055
SO 3 

## (lb/MWH) 0.0058 0.0056 0.0043 0.0052

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## Table 2-8. Summary of Results Unit 5 (September)

Client: Arizona Public Service Facility: Four-Corners Facility Fruitland, NM Technicians: RS, GH, JH, CM, JE Project Number: 182436.0000.0000 SOURCE TEST RUN 1 2 3 AVERAGE
Date 9/30/11 9/30/11 9/30/11 Start Time 09:15 12:15 14:30 Stop Time 11:15 14:15 16:30 PROCESS DATA Electric Power Production (MW) 787.3 787.2 787.8 787.4 Fuel Flow (MMBTU/Hr) 7527 7534 7539 7533 Fuel Flow Rate of Max (%) 68.8 69.0 69.3 69.0
CEMS O 2 

## (%) 5.7 5.8 5.8 5.8 CEMS Volumetric Flow Rate (SCFH) 112,396,778 112,734,454 113,450,437 112,860,556
CEMS SO 2 

## (ppm) 47.2 45.6 44.5 45.8
AMBIENT CONDITIONS Atmospheric Pressure (in. Hg) 24.78 24.78 24.78 24.78 Unit 5 Stack

STACK CONCENTRATIONS
O 2 

## (vol %, dry) 6.1 6.2 6.1 6.1
SO 3 

## (ppmv, dry) 0.10 0.07 0.06 0.08
OUTLET EMISSION RATES
SO 3 

## (lb/hr) 2.32 1.64 1.31 1.76
SO 3 

## (lb/MMBTU) 0.00031 0.00022 0.00017 0.00023
SO 3 

## (lb/MWH) 0.0029 0.0021 0.0017 0.0022

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## 3.0 PROCEDURES

The following section describes the test methods used including details specific to this test program.

3.3 Percent Moisture Measurement

EPA Method 4, Determination of Moisture Content in Stack Gases, was used at the outlets to determine the moisture content of the stack exhaust gases during each sampling run. This testing was only conducted during the April and June testing events. The moisture determination procedure uses a condenser assembly connected between an extraction probe and extraction pump.

A minimum of 21 dry standard cubic feet of stack gas was collected over a period of approximately one hour during each test. Sample gas was drawn from the stack at a flow rate no greater than 0.75 actual cubic feet per minute (dry). The sample gas was then passed through a series of four chilled glass impingers to collect moisture. The impingers were placed into an ice bath to prevent the exit temperature from exceeding 68 oF. The conditioned sample gas was then passed through a calibrated dry gas meter. The entire sample system was leak checked before
and after each test.

After the sample collection is completed, the amount of liquid (condensate) in the impingers was measured gravimetrically and the net gain determined. The total condensate gain of the condenser assembly, incorporated with the calculated volume of gas extracted, determines the total moisture of the gas stream.

3.2 O 2 

## Determination

For the direct analysis of stack gas, an extractive system was used to obtain gas samples for the analysis of O 2 

## . The sample was extracted using a stainless steel/Teflon® diaphragm pump. Sample gas was continuously pulled through a stainless-steel probe. EPA Method 3A samples were transported to the mobile laboratory through a heated Teflon® sample line (maintained at 250 ± 25 oF). The sample gas was passed through a minimum contact condenser to remove any moisture. The conditioned sample gas was then directed to a stainless steel (dry) manifold and partitioned to each of the Non-volatile organic compounds (VOC) continuous analyzers through glass and stainless steel rotameters for flow control of the sample.

During the June and September testing events O 2 

## samples were extracted by one of the following method of a single-point, integrated sampling tedlar bag as used in EPA Method 3.

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## Table 3-1 provides the list of instruments used during the emission tests. Figure 3-1 presents a reference method sample system diagram.

Table 3-1. List of Instruments

Parameter Manufacturer Model Serial Number

O 2 

## Servomex 1400 01420C1/2534

3.3 SO 3 

## Determination

The determination of stack gas concentrations of Sulfuric Acid (H 2 

## SO 4 

## ) Vapor or Mist was performed in accordance with EPA Conditional Test Method 013, which is also referred to as the National Council for Air and Stream Improvement (NCASI) Method 8A. In this method stack gas is extracted at a constant volume rate. The sulfuric acid mist (including SO 3 

## ) and the sulfur dioxide (SO 2 

## ) are separated using an H 2 

## SO 4 

## condenser prior to the first impinger. Asshown in Figure 3-2, the gaseous sample was extracted using a quartz-lined probe into a hightemperature (>500°F) filter holder. The sample is then pulled through a modified Graham condenser kept at a nominal 180°F. The gas is then pulled through a chilled liquid impingement train. Impingers 1 and 2 contained 100 ml of 3% hydrogen peroxide (H 2 

## O 2 

## ). Upon completion of each run a 15-minute purge of ambient air was performed.

Following the sampling purge, the sample train was transported to the sample turn area in the sampling trailer or other secure area for sample collection and sample storage. The condenser was washed a minimum of three times with deionized water into a polyurethane bottle for storage. The liquid level was marked and the sample was logged into the change of custody. Once the testing was completed, the samples were shipped by Federal Express carrier to the analytical laboratory.

TRC elected to use Resolution Analytics, Incorporated (Resolution) of Raleigh, North Carolina for analysis of the sulfuric acid. The samples were prepared for analyses by obtaining the final volume of the contents of the samples. The samples were then analyzed using a Dionex ICS-2100 ion chromatograph that used an IonPac AS18 4x250mm separation column. Each sample was analyzed in duplicate using the same parameters of CTM-013 for acceptability of results. Laboratory reports for each testing event can be found in Appendix G of this report.

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## Figure 3-1. CTM-013 Sample System Diagram

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## 4.0 QUALITY ASSURANCE / QUALITY CONTROL

To ensure accurate results, strict quality assurance and control measures were followed. All testing was performed following standard EPA protocols as outlined in Code of Federal Regulations Title 40, Part 60, Appendix A. The test data was thoroughly documented and checked for completeness.

4.1 O 2 

## Continuous Emissions Monitors

The O 2 

## monitors used by TRC were operated per manufacturer instructions and in accordance with the applicable EPA reference methods. Appendix C documents the results of QA/QC activities.

The continuous analyzers were calibrated prior to testing using gas standards certified by the vendor using EPA Protocol Procedure G1. The gas certification documentation for standards used during this test program is included in Appendix D.

A calibration error test was performed. A low, mid, and high gas was introduced directly to each analyzer. TRC elected to use ambient air as the high level gas (20.9%) for O 2 

## . The calibration error test for each analyzer met the requirements of the reference methods.

After the “direct to the analyzer” calibration error test, the total sampling system which includes the sample line, sample pump, and condenser was tested for system bias. All sample system bias tests met the reference method requirements. After each run, the measured
concentrations of O 2 

## were corrected for bias following the requirements of Method 7E.

During the initial sample system bias tests, the response time of each analyzer was determined. The longest elapsed time was chosen as the system response time. Test runs were started after two times the sample system response time elapsed.

Additionally, sample system drift was determined at the end of each run. System drift is defined in the Method 7E as the value derived by subtracting the pre-run bias test concentration from the post-run bias test concentration, expressed as a percentage of calibration span. All sample system drift tests met the requirements of the test methods.

These checks ensure that the system remains within the tolerance levels defined by the respective EPA reference methods. Calibration results are documented in the final report. Table 4-1 presents the reference method continuous emissions monitoring systems (CEMS) performance criteria.

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## Table 4-1. Reference Method CEMS Performance Criteria

Criteria O 2 

## (M3A) Calibration Error, % ≤ 2 System Bias, % ≤ 5 Zero Drift, % ≤ 3 Calibration Drift, % ≤ 3 Interference Response, % ≤ 2.5

4.2 Moisture

The dry gas meter used for the moisture tests was calibrated prior to testing in accordance with EPA methodology. A post test calibration check was also conducted on the meter. Calibration certification documentation of the dry gas meters can be found in Appendix C. That documentation shows that the difference between the pre and post test calibrations differed by less than 5% as required. The absence of leaks in the sampling system was also verified by conducting leak checks prior to and following each test.

4.3 SO 3 

## Sampling

In accordance with EPA CTM-013 as referenced in NCASI Method 8A, the 3% H 2 

## O 2 

## solution in impingers 1 and 2 of the sampling train was prepared freshly on the date of each test
from a stock solution of 30% H 2 

## O 2 

## . Prior to and after each test run, a leak check was performed to verify the absence of leaks within the sample system. All samples were collected and shipped in accordance with method guidelines.

The dry gas meter used for the moisture tests was calibrated prior to testing in accordance with EPA methodology. A post test calibration check was also conducted on the meter. Calibration certification documentation of the dry gas meters can be found in Appendix C. That documentation shows that the difference between the pre and post test calibrations differed by less than 5% as required. The absence of leaks in the sampling system was also verified by conducting leak checks prior to and following each test.

## APPENDIX A– FIELD DATA SHEETS

## APPENDIX B– EXAMPLE CALCULATIONS

### Example Calculations

Values may differ from Summary Tables due to rounding and truncation. 

### Example for Run: Unit 2 Run 3 Observed Measurements: Constants/Conversions/Standards:

0.1 C SO3 , corrected SO 3 concentration (ppm) 385.3 ideal gas constant @ EPA STP (68 OF and 29.92 "Hg);
8.07 C O2 , corrected O 2 concentration (%) (scf / lb-mol) 2.77E+07 Qd, stack exhaust flow rate (DSCFH) 80.07 Molecular weight of SO 3 (lb/lb-mol)

170.9 MWHr 29.92 EPA STP ( " Hg); P ref
1894 MMBTU/Hr 454 conversion, grams per pound

.

SO 3 density factor, SO 3



### = 80.07 lb/lb-mol x 10 -6

385.3 scf/lb-mol



### = 2.08E-07 lb/scf

SO 3 mass emission rate (lb/hr), E SO3 (lb/hr)



### = C SO3 x Qd x D SO3



### = 0.09 x 2.77E+07 x 2.08E-07



### = 0.54 lbs/hr

SO 3 mass emission rate (lb/MMBtu)



### = SO 3 (lb/hr)
MMBTU/hr



### = 0.5360
1894.10



### = 0.0002830 lbs/MMBtu

SO 3 mass emission rate (lb/MWHr)



### = SO 3 (lb/hr)

MW-hr



### = 0.54
170.9



### = 0.0031 lb/MW-hr 

### SO 3 

### Emission Rates

# Example Calculations

Refers to Test Run: Unit 2 Run 1

C X 

## = raw concentration of component
C O 

## = average of initial and final zero bias checks
C M 

## = average of intial and final span bias checks
C MA 

## = actual concentration of upscale calibration gas

C MA 

## C M 

## - C O



## Oxygen
C O2 

## 7.97 %
C O 

## 0.03 %
C M 

## 9.86 %
C MA 

## 9.99 %

9.86

- 0.03
C O2 

## = 8.07 % C O2 

## = 7.97

- 0.03 

# * 9.99 Corrected Emission Concentrations (Equation 7E-5)

(Eq. 7E-1) Cx Corrected 

## = C X 

## - C O 

# *

### EXAMPLE CALCULATIONS

Values may differ from Summary Tabes due to rounding and truncation. Observed Data

154 = SO 3 ( μ g) from analyses

80.07 = Molecular Weight of SO 3 (gr/gmole) 24.04 = Volume of Gas per mol (US EPA) (l/gmol) 17.57 = Volume of Gas collected during run (SCFH) 1000000 = Conversion from μ g to gr 1000000 = Conversion from μ l to l 28.3 = Conversion from SCF to l

Example Calculations for Unit 2 Run 3 

### SO 3 

### (ppmv) Calculation

Conc. SO 3 

### (ppmv) = Conc SO 3 (ug) X Volume of Gas per mol (l/gmol) X Conversion from μ g to g Molecular Weight of SO 3 (gr/gmol) X Volume of Gas Collected (SCFH) X Conversion from l to SCFH X Conversion from μ l to l

= 154 X 24.04 X 1000000
80.07 X 17.57 X 28.3 X 1000000

= 

### 0.09301 (ppmv)

# E XAMPLE 

# C ALCULATIONS:

Arizona Public Service 

### Stack Gas Moisture Fruitland, New Mexico Technicians: TJS, BJM Project Number: 182436.0000.0000 Example calculations for Test Run: Unit 2 Run 3

Observed Measurements: Dry Gas Meter Correction Factor (Kd) = 0.992 Barometric Pressure (Pm) = 24.20 Average Temperature of Dry Gas meter = 72.7

Impinger Weight Gain [IWG]: 3459.9 Ending Impinger Wt. (g) –3414.9 Beginning Impinger Wt. (g) = 45.0 (g) Net Volume Sampled [NVS]: 815.77 Ending Meter Reading (ft3) –801.81 Beginning Meter Reading (ft3) = 13.96 (ft3)

Volume Metered [Vm]: NVS x Kd
13.96 x 0.9923

= 13.85 (ft3)

Average Temperature [Tm]: 460 + 72.7 (°F) = 532.7 (°R)

Moisture Fraction: IWG (g) 1.335 Vm Pm 499.4 IWG (g) 1.335 Tm

45.0 1.335 45.0 1.335 13.85 24.2 499.4 532.7

= 0.1605 or 16.05% Moisture

Dry Fraction: 1 – Moisture Fraction 1 – 0.1604601 = 0.840 liters (g) H2O liters (g) H2O



## + liters °R ft3 in. Hg

liters (g) H2O liters (g) H2O



## + liters °R ft3 in. Hg 

# ( ( ) ) ( ( ( ) 

# ) ( ( )

( ) ( ) 

# ( )

( ( ) ) x



# ) x

x x x x

x 

# ) x

## APPENDIX C – QUALITY ASSURANCE ACTIVITIES

### Meter Box: Orifice Full Calibration

Biannual_90394_041311 Date: Orifice (#) K' Factor Prev. Calib. Date: 12/9/2010 Manufacturer: Apex Instruments 40 0.2336 Location: Littleton Lab Model: CI, VI 48 0.3435 Technician: JDG Tested By: EW 55 0.4575 Meter Serial No: 90394 63 0.5861 TRC Meter Box ID 90394 73 0.8085 Atm. Pressure (corr. In Hg): 24.18 uncorrected: 24.30 Critical Vacuum in Hg: 11 in. Hg. (required minimum) Prev. Calib Factor (Y): 1.0028

Orifice K' coefficient dH Time Vol (initial) Vol (final) Vol. Total Inlet Outlet Inlet Outlet Vacuum Initial Final Serial # (see above) (in. H2O) (min) (cu ft) (cu ft) (cu ft) (deg F) (deg F) (deg F) (deg F) (in Hg) (deg F) (deg F)

40 0.2336 0.20 18 687.117 692.597 5.48 70 70 70 70 16 69 70 48 0.3435 0.47 13 692.597 698.419 5.822 70 70 70 71 15 70 70 55 0.4575 0.87 9 698.419 703.800 5.381 71 71 71 71 14 70 70 63 0.5861 1.50 10 703.800 711.461 7.661 71 71 72 72 12 70 70 73 0.8085 2.85 7 711.461 718.785 7.324 72 72 72 72 10 70 70

Meter Box Dry Gas Meter Volume Volume Volume Volume Corrected Corrected Flow Corrected Corrected Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation

(cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) Pass/Fail

4.41 124.94 0.304 4.42 125.10 1.001 0.001 1.49 -0.18 * Average Y: 0.9999 **PASS** 4.69 132.79 0.448 4.69 132.80 1.000 0.000 1.628 -0.05 Ave. Y w/in 5% of previous value: YES 4.33 122.71 0.598 4.32 122.45 0.998 -0.002 1.695 0.02 6.18 174.87 0.766 6.16 174.29 0.997 -0.003 1.783 0.11 0.95 >= Y <= 1.05: PASS
5.92 167.70 1.046 5.94 168.30 1.004 0.004 1.789 0.11 ** Average dH: 1.678 **PASS** Criteria: * Y- ratio of the reading of the calibration meter (critical orifice) to the Meter Box DGM. Acceptable tolerance of individual values from the average is +/- 0.02. ** dH- the orifice differential pressure in inches of H2O that equates to 0.75 cfm of air flow at 68 F and 29.92 in Hg, acceptable tolerance of individual values from the average is +/- 0.2. Critical Orifice

Calibration Test Results 4/13/2011

Factor (Y) Calibration Dry Gas Meter Orifice

Factor (dH@)

Calibration

Meter Box Final Temperatures Reference Orifice Set

Initial Temperatures Ambient Temperatures

0 0.5

1 1.5

2 2.5

3

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00dH (in. H2O)

Flow Rate (cfm) 

## Differential Pressure vs. Flow Rate

### Meter Box: Orifice Full Calibration

Biannual_90394_120910 Date: Orifice (#) K' Factor Prev. Calib. Date: 6/4/10 Manufacturer: Apex Instruments 40 0.2336 Location: Littleton Lab Model: CI, VI 48 0.3435 Technician: JDG Tested By: EW 55 0.4575 Meter Serial No: 90394 63 0.5861 TRC Meter Box ID 90394 73 0.8085 Atm. Pressure (corr. In Hg): 24.14 uncorrected: 24.27 Critical Vacuum in Hg: 11 in. Hg. (required minimum) Prev. Calib Factor (Y): 0.9953

Orifice K' coefficient dH Time Vol (initial) Vol (final) Vol. Total Inlet Outlet Inlet Outlet Vacuum Initial Final Serial # (see above) (in. H2O) (min) (cu ft) (cu ft) (cu ft) (deg F) (deg F) (deg F) (deg F) (in Hg) (deg F) (deg F)

40 0.2336 0.20 25 251.200 258.788 7.588 73 69 71 72 16 71 71 48 0.3435 0.47 14 258.800 265.066 6.266 71 72 72 73 15 71 71 55 0.4575 0.87 10 265.100 271.065 5.965 71 73 72 73 13 71 71 63 0.5861 1.50 7 271.100 276.440 5.34 71 73 72 73 12 71 71 73 0.8085 2.85 5 277.200 282.437 5.237 72 73 72 73 10 71 71

Meter Box Dry Gas Meter Volume Volume Volume Volume Corrected Corrected Flow Corrected Corrected Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation

(cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) Pass/Fail

6.09 172.37 0.304 6.12 173.28 1.005 0.002 1.50 -0.18 * Average Y: 1.0028 **PASS** 5.02 142.26 0.448 5.04 142.68 1.003 0.000 1.623 -0.06 Ave. Y w/in 5% of previous value: YES 4.79 135.52 0.596 4.79 135.74 1.002 -0.001 1.695 0.02 4.29 121.56 0.763 4.30 121.73 1.001 -0.001 1.788 0.11 0.95 >= Y <= 1.05: PASS
4.23 119.64 1.047 4.24 119.94 1.003 0.000 1.797 0.12 ** Average dH: 1.680 **PASS** Criteria: * Y- ratio of the reading of the calibration meter (critical orifice) to the Meter Box DGM. Acceptable tolerance of individual values from the average is +/- 0.02. ** dH- the orifice differential pressure in inches of H2O that equates to 0.75 cfm of air flow at 68 F and 29.92 in Hg, acceptable tolerance of individual values from the average is +/- 0.2. Meter Box Final Temperatures Reference Orifice Set

Initial Temperatures Ambient Temperatures

Critical Orifice

Calibration Test Results 12/9/2010

Factor (Y) Calibration Dry Gas Meter Orifice

Factor (dH@)

Calibration

0 0.5

1 1.5

2 2.5

3

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00dH (in. H2O)

Flow Rate (cfm) 

## Differential Pressure vs. Flow Rate

### Dry Gas Meter Calibration

WORKING METER REFERENCE METER Date: Location: Littleton Lab Calibration Date: 11/3/2010 Technician: JDG Location: Austin Texas Lab Meter Serial No: 9215 Technician: KRH TRC DGM ID 9215 Meter Serial No: 56048 Prev. Calib Factor (Y): 0.9972 TRC DGM ID 56048 P bar (in Hg) uncorrected: 24.300 24.358 Calib. Factor (Y): 0.9650

REFERENCE METER Corr. Vol @ Calibration Time Start Temp Stop Temp Vol (initial) Vol (final) Vol. Total Meter Rate EPA STP

Run # (min) (deg F) (deg F) (cu ft) (cu ft) (cu ft) (cu•ft /min) (cu ft)

1 8 69 70 729.266 732.433 3.056 0.3820 2.443 2 8 70 70 732.433 735.601 3.057 0.3821 2.442 3 10 70 70 735.601 739.529 3.791 0.3791 3.028 4 13 70 70 739.529 744.926 5.208 0.4006 4.160 5 17 70 70 744.926 750.654 5.528 0.3251 4.415

WORKING METER Corr. Vol @ Calculated
Calibration Time Start Temp Stop Temp Vol (initial) Vol (final) Vol. Total Meter Rate EPA STP DGM Factor

Run # (min) (deg F) (deg F) (cu ft) (cu ft) (cu ft) (cu•ft /min) (cu ft) (Y)

1 8 69 70 824.486 827.542 3.056 0.382 2.443 1.0001 

### * Average Y: 0.9900

2 8 70 70 827.542 830.678 3.136 0.392 2.505 0.9748 3 10 70 70 830.628 834.436 3.808 0.381 3.042 0.9954 Ave. Y between 0.95 and 1.05: PASS 4 13 70 70 834.436 839.700 5.264 0.405 4.205 0.9894 Ind. Y values +/- 0.02 from Ave.: PASS
5 17 70 70 839.700 845.281 5.581 0.328 4.458 0.9904 Ave. Y w/in 5% of previous value: YES Criteria: * Y- ratio of the reading of the reference meter to the working DGM. Acceptable tolerance of individual values from the average is +/- 0.02, with a value between 0.95 and 1.05.

JDG Calibration Test Results 4/13/2011

Dry Gas Meter (DGM Factor)

### Dry Gas Meter Calibration

WORKING METER REFERENCE METER Date: Location: Littleton Lab Calibration Date: 11/3/2010 Technician: JAW Location: Austin Texas Lab Meter Serial No: 9215 Technician: KRH TRC DGM ID 9215 Meter Serial No: 56048 Prev. Calib Factor (Y): 1.0160 TRC DGM ID 56048 P bar (in Hg) uncorrected: 24.510 24.570 Calib. Factor (Y): 0.9650

REFERENCE METER Corr. Vol @ Calibration Time Start Temp Stop Temp Vol (initial) Vol (final) Vol. Total Meter Rate EPA STP

Run # (min) (deg F) (deg F) (cu ft) (cu ft) (cu ft) (cu•ft /min) (cu ft)

1 8 69 71 437.565 445.109 7.280 0.9100 5.865 2 8 70 71 445.109 452.370 7.007 0.8759 5.640 3 10 70 70 452.370 458.662 6.072 0.6072 4.892 4 13 70 69 458.662 464.359 5.498 0.4229 4.433 5 17 69 72 464.359 469.670 5.125 0.3015 4.125

WORKING METER Corr. Vol @ Calculated
Calibration Time Start Temp Stop Temp Vol (initial) Vol (final) Vol. Total Meter Rate EPA STP DGM Factor

Run # (min) (deg F) (deg F) (cu ft) (cu ft) (cu ft) (cu•ft /min) (cu ft) (Y)

1 8 69 72 337.182 344.513 7.331 0.916 5.901 0.9940 

### * Average Y: 0.9972

2 8 71 74 344.513 351.563 7.050 0.881 5.653 0.9976 3 10 72 74 351.563 357.685 6.122 0.612 4.905 0.9974 Ave. Y between 0.95 and 1.05: PASS 4 13 72 75 357.685 363.244 5.559 0.428 4.449 0.9964 Ind. Y values +/- 0.02 from Ave.: PASS
5 17 74 75 363.244 368.406 5.162 0.304 4.124 1.0003 Ave. Y w/in 5% of previous value: YES Criteria: * Y- ratio of the reading of the reference meter to the working DGM. Acceptable tolerance of individual values from the average is +/- 0.02, with a value between 0.95 and 1.05.

JAW Calibration Test Results 12/7/2010

Dry Gas Meter (DGM Factor)

# Barometer Calibration Check

90995419_BarometerCal_041311 Date: 4/1/2010 Lab Standard Barometer
Location: TRC Littleton Lab Manufacturer: Princo


### Technician: JAW Type: Fortin Type Mercurial 

### Manufacturer: VWR Units: in. Hg and mm Hg 

### Type: Digital ID Number: NOVA 453x


### Units: in Hg Lab Assignment.: 90995419



## Laboratory Standard Barometer
Uncorrected (Observed) Lab Barometer Reading 24.46 in. Hg Temperature of Lab Barometer 69 °F Temperature Correction ( + or -) -0.089 unitless Lattitude Correction ( + or -) -0.013 unitless Temperature Corrected Laboratory Barometer Reading 24.371 in. Hg Temperature & Latitude Corrected Laboratory Barometer Re 

## 24.358 in. Hg Corrected Laboaratory Barometer Reading 619 mm Hg Corrected Laboaratory Barometer Reading 825 mb Corrected Laboaratory Barometer Reading 5551 ft



## Digital Barometer
Field Barometer Reading (temperature compensated) 

## 24.38 in. Hg



## Calibration Test Results
*Difference (in Hg) 

## -0.022

Pass/Fail 

## PASS

Acceptance Criteria Agreement within 0.1 in. Hg or 2.5 mm Hg.Dry Gas Meter Calibration

WORKING METER REFERENCE METER Date: Location: Littleton Lab Calibration Date: 11/3/10 Technician: JDG Location: Austin Texas Lab Meter Serial No: 9215 Technician: KRH TRC DGM ID 9215 Meter Serial No: 56048 Prev. Calib Factor (Y): 0.9972 TRC DGM ID 56048 P bar (in Hg) uncorrected: 24.300 24.358 Calib. Factor (Y): 0.9650

REFERENCE METER Corr. Vol @ Calibration Time Start Temp Stop Temp Vol (initial) Vol (final) Vol. Total Meter Rate EPA STP

Run # (min) (deg F) (deg F) (cu ft) (cu ft) (cu ft) (cu•ft /min) (cu ft)

1 8 69 70 729.266 732.433 3.056 0.3820 2.443 2 8 70 70 732.433 735.601 3.057 0.3821 2.442 3 10 70 70 735.601 739.529 3.791 0.3791 3.028 4 13 70 70 739.529 744.926 5.208 0.4006 4.160 5 17 70 70 744.926 750.654 5.528 0.3251 4.415

WORKING METER Corr. Vol @ Calculated Calibration Time Start Temp Stop Temp Vol (initial) Vol (final) Vol. Total Meter Rate EPA STP DGM Factor

Run # (min) (deg F) (deg F) (cu ft) (cu ft) (cu ft) (cu•ft /min) (cu ft) (Y)

1 8 69 70 824.486 827.542 3.056 0.382 2.443 1.0001 * Average Y: 0.9900

2 8 70 70 827.542 830.678 3.136 0.392 2.505 0.9748 3 10 70 70 830.628 834.436 3.808 0.381 3.042 0.9954 Ave. Y between 0.95 and 1.05: PASS 4 13 70 70 834.436 839.700 5.264 0.405 4.205 0.9894 Ind. Y values +/- 0.02 from Ave.: PASS
5 17 70 70 839.700 845.281 5.581 0.328 4.458 0.9904 Ave. Y w/in 5% of previous value: YES Criteria: * Y- ratio of the reading of the reference meter to the working DGM. Acceptable tolerance of individual values from the average is +/- 0.02, with a value between 0.95 and 1.05.

JDG Calibration Test Results 4/13/11

Dry Gas Meter (DGM Factor)Dry Gas Meter Calibration

WORKING METER REFERENCE METER Date: Location: Littleton Lab Calibration Date: 11/3/10 Technician: JAW Location: Austin Texas Lab Meter Serial No: 9215 Technician: KRH TRC DGM ID 9215 Meter Serial No: 56048 Prev. Calib Factor (Y): 1.0160 TRC DGM ID 56048 P bar (in Hg) uncorrected: 24.510 24.570 Calib. Factor (Y): 0.9650

REFERENCE METER Corr. Vol @ Calibration Time Start Temp Stop Temp Vol (initial) Vol (final) Vol. Total Meter Rate EPA STP

Run # (min) (deg F) (deg F) (cu ft) (cu ft) (cu ft) (cu•ft /min) (cu ft)

1 8 69 71 437.565 445.109 7.280 0.9100 5.865 2 8 70 71 445.109 452.370 7.007 0.8759 5.640 3 10 70 70 452.370 458.662 6.072 0.6072 4.892 4 13 70 69 458.662 464.359 5.498 0.4229 4.433 5 17 69 72 464.359 469.670 5.125 0.3015 4.125

WORKING METER Corr. Vol @ Calculated Calibration Time Start Temp Stop Temp Vol (initial) Vol (final) Vol. Total Meter Rate EPA STP DGM Factor

Run # (min) (deg F) (deg F) (cu ft) (cu ft) (cu ft) (cu•ft /min) (cu ft) (Y)

1 8 69 72 337.182 344.513 7.331 0.916 5.901 0.9940 * Average Y: 0.9972

2 8 71 74 344.513 351.563 7.050 0.881 5.653 0.9976 3 10 72 74 351.563 357.685 6.122 0.612 4.905 0.9974 Ave. Y between 0.95 and 1.05: PASS 4 13 72 75 357.685 363.244 5.559 0.428 4.449 0.9964 Ind. Y values +/- 0.02 from Ave.: PASS
5 17 74 75 363.244 368.406 5.162 0.304 4.124 1.0003 Ave. Y w/in 5% of previous value: YES Criteria: * Y- ratio of the reading of the reference meter to the working DGM. Acceptable tolerance of individual values from the average is +/- 0.02, with a value between 0.95 and 1.05.

JAW Calibration Test Results 12/7/10

Dry Gas Meter (DGM Factor)

### Meter Box: Orifice Full Calibration

Date: Set Used: Brass Orifice (#) K' Factor 7/7/2011 Reference Orifice Set ( ) Prev. Calib. Date: Manufacturer: 5/12/2011 Location: TRC Albuquerque Model: Technician: JCC Tested By: Meter Serial No: 997368 Meter Box ID: 610203 Meter Box ID: Atm. Pressure (corr. In Hg): 24.85 Atm. Pressure (corr. In Hg):
Critical Vacuu m + 2 in Hg: 14 in Hg (required minimum) Critical Vacuum + 2 in Hg: in. Hg. (required minimum) Prev Calib Factor (Y): 0 9815 Prev. Calib Factor (Y): . I iti l T t Fi l T t A bi t T t

O ifi K' ffi i t dH Ti V l (i iti l) V l (fi l) VlTtl Ilt O tl t Ilt O tl t V I iti l Fi l Initial Temperatures Final Temperatures Ambient Temperatures Orifice K' coefficient dH Time Vol (initial) Vol (final) Vol. Total Inlet Outlet Inlet Outlet Vacuum Initial Final S i l# ( b) (i H2O) ( i) ( ft) ( ft) ( ft) (d F) (d F) (d F) (d F) (i H ) (d F) (d F) era see aove) (in. H2O) mn cu cu cu eg eg eg eg n g eg eg

40 0.2388 0.20 20.0 263.918 270.307 6.389 84 84 86 86 21.0 89 91
48 0.3515 0.48 21.0 270.307 280.112 9.805 87 87 89 88 20.0 91 91 270.307 280.112 55 0.4578 0.87 15.0 280.112 289.333 9.221 90 88 91 89 18.7 91 91 280.112 289.333 63 0.5940 1.50 10.0 289.333 297.275 7.942 91 90 92 90 17.5 91 91 289.333 297.275

Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice Meter Box Dry Gas Meter Volume Volume Volume Volume Critical Orifice Dry Gas Meter Orifice Calibration Calibration Volume Volume Volume Volume Corrected Corrected Flow Corrected Corrected Factor (Y) Factor (dH@) Calibration Calibration Corrected Corrected Flow Corrected Corrected V ( td) V ( td) R t V ( td) V ( td) V l V i ti V l V i ti Factor (Y) Factor (dH@) Meter Box Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il Meter Box C lib ti T t R lt (cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) Pass/Fail Calibration Test Results

5.14 145.60 0.319 5.06 143.30 0.984 -0.004 1.433 -0.16 * Average Y: 0.9887 PASS Average Y:
7.86 222.51 0.467 7.81 221.28 0.994 0.006 1.574 -0.02 Ave. Y w/in 5% of previous value: YES Ave. Y w/in 5% of previous value: 7 37 208 83 0 615 7 27 205 86 0 986 -0 003 1 670 0 07 . . . . . . . . . 6 35 179 79 0 794 6 29 178 07 0 990 0 002 1 705 0 11 0 95 >= Y <= 1 05: PASS . . . . . . . . . 0.95 >= Y <= 1.05: ** Average dH: 1 595 PASS ** Average dH: .
C it i rera: * Y- ratio of the reading of the calibration meter (critical orifice) to the Meter Box DGM. Acceptable tolerance of individual values from the average is +/- 0.02. ** dH- the orifice differential pressure in inches of H2O that equates to 0.75 cfm of air flow at 68 F and 29.92 in Hg, acceptable tolerance of individual values from the average is +/- 0.2.



### Diff ti l P Fl R t Differential Pressure vs. Flow Rate

1.6

1.4

1 2 .

1O)H2

0 8. O)

.(in. H2OH (in. HdH (in.dH (

0.6d

0.4

0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm)

### Meter Box: Orifice Full Calibration

Date: Set Used: BRASS Orifice (#) K' Factor 7/8/2011 Reference Orifice Set ( ) Prev. Calib. Date: Manufacturer: 5/12/2011 Location: TRC Albuquerque Model: Technician: JCC Tested By: Meter Serial No: 978517 Meter Box ID: 610204 Meter Box ID: Atm. Pressure (corr. In Hg): 24.85 Atm. Pressure (corr. In Hg):
Critical Vacuu m + 2 in Hg: 14 in Hg (required minimum) Critical Vacuum + 2 in Hg: in. Hg. (required minimum) Prev Calib Factor (Y): 1 0058 Prev. Calib Factor (Y): . I iti l T t Fi l T t A bi t T t

O ifi K' ffi i t dH Ti V l (i iti l) V l (fi l) VlTtl Ilt O tl t Ilt O tl t V I iti l Fi l Initial Temperatures Final Temperatures Ambient Temperatures Orifice K' coefficient dH Time Vol (initial) Vol (final) Vol. Total Inlet Outlet Inlet Outlet Vacuum Initial Final S i l# ( b) (i H2O) ( i) ( ft) ( ft) ( ft) (d F) (d F) (d F) (d F) (i H ) (d F) (d F) era see aove) (in. H2O) mn cu cu cu eg eg eg eg n g eg eg

40 0.2388 0.23 20.0 305.478 311.747 6.269 97 96 97 96 21.3 94 94 48 0.3515 0.52 21.0 311.747 321.403 9.656 97 96 98 97 20.0 94 95 55 0.4578 0.9 20.0 321.403 333.525 12.122 98 97 99 98 19.5 95 95 321.403 333.525 63 0.5940 1.6 10.0 333.525 341.382 7.857 99 98 100 98 18.0 95 96 333.525 341.382

Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice Meter Box Dry Gas Meter Volume Volume Volume Volume Critical Orifice Dry Gas Meter Orifice Calibration Calibration Volume Volume Volume Volume Corrected Corrected Flow Corrected Corrected Factor (Y) Factor (dH@) Calibration Calibration Corrected Corrected Flow Corrected Corrected Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation Factor (Y) Factor (dH@) Meter Box Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il Meter Box C lib ti T t R lt (cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) Pass/Fail Calibration Test Results

4.94 139.93 0.313 5.04 142.79 1.020 0.004 1.582 -0.10 * Average Y: 1.0167 PASS Average Y:
7.61 215.52 0.460 7.79 220.58 1.023 0.007 1.653 -0.02 Ave. Y w/in 5% of previous value: YES Ave. Y w/in 5% of previous value: 9.55 270.38 0.606 9.66 273.48 1.011 -0.005 1.686 0.01 6.19 175.37 0.786 6.26 177.34 1.011 -0.005 1.786 0.11 0.95 >= Y <= 1.05: PASS 0.95 >= Y <= 1.05: ** Average dH: 1 677 PASS ** Average dH: .
Criteria: * Y ti f th di f th lib ti t ( iti l ifi ) t th M t B DGM A t bl t l f i di id l l f th i +/ 0 02 * Y- ratio of the reading of the calibration meter (critical orifice) to the Meter Box DGM. Acceptable tolerance of individual values from the average is +/- 0.02. ** dH th ifi diff ti l i i h f H2O th t t t 0 75 f f i fl t 68 F d 29 92 i H t bl t l f i di id l l f th i / 0 2 ** dH- the orifice differential pressure in inches of H2O that equates to 0.75 cfm of air flow at 68 F and 29.92 in Hg, acceptable tolerance of individual values from the average is +/- 0.2.



### Diff ti l P Fl R t Differential Pressure vs. Flow Rate

1.8

1 6 .

1.4

1.2

1O)H2O).(inH2O

0.8H (in. HdH (in.dH (

0 6d

0.6

0 4 .

0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm)

### Meter Box: Orifice Full Calibration

Date: Set Used: BRASS Orifice (#) K' Factor 7/8/2011 Reference Orifice Set ( ) Prev. Calib. Date: Manufacturer: 5/12/2011 Location: TRC Albuquerque Model: Technician: JCC Tested By: Meter Serial No: 978517 Meter Box ID: 610204 Meter Box ID: Atm. Pressure (corr. In Hg): 24.85 Atm. Pressure (corr. In Hg):
Critical Vacuu m + 2 in Hg: 14 in Hg (required minimum) Critical Vacuum + 2 in Hg: in. Hg. (required minimum) Prev Calib Factor (Y): 1 0058 Prev. Calib Factor (Y): . I iti l T t Fi l T t A bi t T t

O ifi K' ffi i t dH Ti V l (i iti l) V l (fi l) VlTtl Ilt O tl t Ilt O tl t V I iti l Fi l Initial Temperatures Final Temperatures Ambient Temperatures Orifice K' coefficient dH Time Vol (initial) Vol (final) Vol. Total Inlet Outlet Inlet Outlet Vacuum Initial Final S i l# ( b) (i H2O) ( i) ( ft) ( ft) ( ft) (d F) (d F) (d F) (d F) (i H ) (d F) (d F) era see aove) (in. H2O) mn cu cu cu eg eg eg eg n g eg eg

40 0.2388 0.23 20.0 305.478 311.747 6.269 97 96 97 96 21.3 94 94 48 0.3515 0.52 21.0 311.747 321.403 9.656 97 96 98 97 20.0 94 95 55 0.4578 0.9 20.0 321.403 333.525 12.122 98 97 99 98 19.5 95 95 321.403 333.525 63 0.5940 1.6 10.0 333.525 341.382 7.857 99 98 100 98 18.0 95 96 333.525 341.382

Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice Meter Box Dry Gas Meter Volume Volume Volume Volume Critical Orifice Dry Gas Meter Orifice Calibration Calibration Volume Volume Volume Volume Corrected Corrected Flow Corrected Corrected Factor (Y) Factor (dH@) Calibration Calibration Corrected Corrected Flow Corrected Corrected Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation Factor (Y) Factor (dH@) Meter Box Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il Meter Box C lib ti T t R lt (cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) Pass/Fail Calibration Test Results

4.94 139.93 0.313 5.04 142.79 1.020 0.004 1.582 -0.10 * Average Y: 1.0167 PASS Average Y:
7.61 215.52 0.460 7.79 220.58 1.023 0.007 1.653 -0.02 Ave. Y w/in 5% of previous value: YES Ave. Y w/in 5% of previous value: 9.55 270.38 0.606 9.66 273.48 1.011 -0.005 1.686 0.01 6.19 175.37 0.786 6.26 177.34 1.011 -0.005 1.786 0.11 0.95 >= Y <= 1.05: PASS 0.95 >= Y <= 1.05: ** Average dH: 1 677 PASS ** Average dH: .
Criteria: * Y ti f th di f th lib ti t ( iti l ifi ) t th M t B DGM A t bl t l f i di id l l f th i +/ 0 02 * Y- ratio of the reading of the calibration meter (critical orifice) to the Meter Box DGM. Acceptable tolerance of individual values from the average is +/- 0.02. ** dH th ifi diff ti l i i h f H2O th t t t 0 75 f f i fl t 68 F d 29 92 i H t bl t l f i di id l l f th i / 0 2 ** dH- the orifice differential pressure in inches of H2O that equates to 0.75 cfm of air flow at 68 F and 29.92 in Hg, acceptable tolerance of individual values from the average is +/- 0.2.



### Diff ti l P Fl R t Differential Pressure vs. Flow Rate

1.8

1 6 .

1.4

1.2

1O)H2O).(inH2O

0.8H (in. HdH (in.dH (

0 6d

0.6

0 4 .

0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm)

### Meter Box: Orifice Full Calibration

Date: Set Used: BRASS Orifice (#) K' Factor 10/13/2011 Reference Orifice Set ( ) Prev. Calib. Date: Manufacturer: 7/8/2011 Location: TRC Albuquerque Model: Technician: JCC Tested By: Meter Serial No: 978517 Meter Box ID: 610204 Meter Box ID: Atm. Pressure (corr. In Hg): 25.02 Atm. Pressure (corr. In Hg):
Critical Vacuu m + 2 in Hg: 14 in Hg (required minimum) Critical Vacuum + 2 in Hg: in. Hg. (required minimum) Prev Calib Factor (Y): 1 0058 Prev. Calib Factor (Y): . I iti l T t Fi l T t A bi t T t

O ifi K' ffi i t dH Ti V l (i iti l) V l (fi l) VlTtl Ilt O tl t Ilt O tl t V I iti l Fi l Initial Temperatures Final Temperatures Ambient Temperatures Orifice K' coefficient dH Time Vol (initial) Vol (final) Vol. Total Inlet Outlet Inlet Outlet Vacuum Initial Final S i l# ( b) (i H2O) ( i) ( ft) ( ft) ( ft) (d F) (d F) (d F) (d F) (i H ) (d F) (d F) era see aove) (in. H2O) mn cu cu cu eg eg eg eg n g eg eg

40 0.2388 0.21 20.0 511.612 517.632 6.020 74 73 80 75 10.0 74 75 48 0.3515 0.47 16.0 517.432 524.528 7.096 80 75 86 77 9.0 75 75 55 0.4578 0.78 15.0 524.228 532.877 8.649 85 77 89 78 9.0 75 76 524.228 532.877 63 0.5940 1.3 18.0 532.228 545.710 13.482 88 77 94 80 7.2 76 76 532.228 545.710

Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice Meter Box Dry Gas Meter Volume Volume Volume Volume Critical Orifice Dry Gas Meter Orifice Calibration Calibration Volume Volume Volume Volume Corrected Corrected Flow Corrected Corrected Factor (Y) Factor (dH@) Calibration Calibration Corrected Corrected Flow Corrected Corrected Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation Factor (Y) Factor (dH@) Meter Box Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il Meter Box C lib ti T t R lt (cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) Pass/Fail Calibration Test Results

4.96 140.58 0.301 5.17 146.37 1.041 -0.007 1.445 0.01 * Average Y: 1.0485 PASS Average Y:
5.81 164.61 0.444 6.08 172.25 1.046 -0.002 1.467 0.04 Ave. Y w/in 5% of previous value: YES Ave. Y w/in 5% of previous value: 7.06 199.80 0.577 7.43 210.26 1.052 0.004 1.419 -0.01 10.96 310.49 0.749 11.56 327.29 1.054 0.006 1.392 -0.04 0.95 >= Y <= 1.05: PASS 0.95 >= Y <= 1.05: ** Average dH: 1 431 PASS ** Average dH: .
Criteria: * Y ti f th di f th lib ti t ( iti l ifi ) t th M t B DGM A t bl t l f i di id l l f th i +/ 0 02 * Y- ratio of the reading of the calibration meter (critical orifice) to the Meter Box DGM. Acceptable tolerance of individual values from the average is +/- 0.02. ** dH th ifi diff ti l i i h f H2O th t t t 0 75 f f i fl t 68 F d 29 92 i H t bl t l f i di id l l f th i / 0 2 ** dH- the orifice differential pressure in inches of H2O that equates to 0.75 cfm of air flow at 68 F and 29.92 in Hg, acceptable tolerance of individual values from the average is +/- 0.2.



### Diff ti l P Fl R t Differential Pressure vs. Flow Rate

1.4

1 2 .

1

0.8O)H2. O)(in. H2O

0 6H (in. H

0.6dH (in.dH (

0.4

0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm)

### Meter Box: Orifice Full Calibration

Date: Set Used: Brass Orifice (#) K' Factor 10/13/2011 Reference Orifice Set ( ) Prev. Calib. Date: Manufacturer: 8/1/2011 Location: TRC Albuquerque Model: Technician: JCC Tested By: Meter Serial No: 90598 Meter Box ID: 90598 Meter Box ID: Atm. Pressure (corr. In Hg): 24.98 Atm. Pressure (corr. In Hg):
Critical Vacuu m + 2 in Hg: 14 in Hg (required minimum) Critical Vacuum + 2 in Hg: in. Hg. (required minimum) Prev Calib Factor (Y): 1 0150 Prev. Calib Factor (Y): . I iti l T t Fi l T t A bi t T t

O ifi K' ffi i t dH Ti V l (i iti l) V l (fi l) VlTtl Ilt O tl t Ilt O tl t V I iti l Fi l Initial Temperatures Final Temperatures Ambient Temperatures Orifice K' coefficient dH Time Vol (initial) Vol (final) Vol. Total Inlet Outlet Inlet Outlet Vacuum Initial Final S i l# ( b) (i H2O) ( i) ( ft) ( ft) ( ft) (d F) (d F) (d F) (d F) (i H ) (d F) (d F) era see aove) (in. H2O) mn cu cu cu eg eg eg eg n g eg eg

40 0.2388 0.26 15.0 984.014 988.647 4.633 68 68 69 68 17.0 60 61
48 0.3515 0.55 11.0 988.647 993.632 4.985 69 68 69 68 14.0 62 62 988.647 993.632 55 0.4578 0.96 11.0 993.632 1,000.165 6.533 69 68 71 69 13.0 62 63 993.632 1,000.165 63 0.5940 1.70 10.0 1000.165 1,007.792 7.627 71 68 71 69 11.5 63 64 1000.165 1,007.792

Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice Meter Box Dry Gas Meter Volume Volume Volume Volume Critical Orifice Dry Gas Meter Orifice Calibration Calibration Volume Volume Volume Volume Corrected Corrected Flow Corrected Corrected Factor (Y) Factor (dH@) Calibration Calibration Corrected Corrected Flow Corrected Corrected V ( td) V ( td) R t V ( td) V ( td) V l V i ti V l V i ti Factor (Y) Factor (dH@) Meter Box Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il Meter Box C lib ti T t R lt (cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) Pass/Fail Calibration Test Results

3.87 109.52 0.309 3.92 111.08 1.014 0.000 1.723 -0.04 * Average Y: 1.0138 PASS Average Y:
4.16 117.89 0.453 4.23 119.68 1.015 0.001 1.702 -0.06 Ave. Y w/in 5% of previous value: YES Ave. Y w/in 5% of previous value: 5 45 154 46 0 594 5 50 155 78 1 009 -0 005 1 754 0 00 . . . . . . . . . 6 38 180 55 0 763 6 48 183 63 1 017 0 003 1 855 0 10 0 95 >= Y <= 1 05: PASS . . . . . . . . . 0.95 >= Y <= 1.05: ** Average dH: 1 758 PASS ** Average dH: .
C it i rera: * Y- ratio of the reading of the calibration meter (critical orifice) to the Meter Box DGM. Acceptable tolerance of individual values from the average is +/- 0.02. ** dH- the orifice differential pressure in inches of H2O that equates to 0.75 cfm of air flow at 68 F and 29.92 in Hg, acceptable tolerance of individual values from the average is +/- 0.2.



### Diff ti l P Fl R t Differential Pressure vs. Flow Rate

1.8

1 6 .

1.4

1.2

1O)H2O).(inH2O

0.8H (in. HdH (in.dH (

0 6d

0.6

0 4 .

0 0.2

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm) 0 0.2 0.4

0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Flow Rate (cfm)

## APPENDIX D – CALIBRATION CERTIFICATIONS

## APPENDIX E – LOGGED DATA RECORDS

## Bottles 9.99 20.9
CE SSB
Zero 0 Zero 0.02 Span 20.95 Bias 9.83
Bias 9.98
Start Run 1930 Stop Run 2030
Source Date Time Run O2 %
Unit 2 4/7/2011 1935 1 7.98
Unit 2 4/7/2011 1940 1 7.99
Unit 2 4/7/2011 1945 1 8.01
Unit 2 4/7/2011 1950 1 8.02
Unit 2 4/7/2011 1955 1 7.88
Unit 2 4/7/2011 2000 1 7.98
Unit 2 4/7/2011 2005 1 8.10
Unit 2 4/7/2011 2010 1 8.00
Unit 2 4/7/2011 2015 1 8.01 SSB Zero Avg
Unit 2 4/7/2011 2020 1 7.88 0.0250000000
Unit 2 4/7/2011 2025 1 7.89 SSB Bias Avg
Unit 2 4/7/2011 2030 1 7.87 9.86 Average 7.9675
SSB Corrected average 8.059598
Zero 0.03
Bias 9.89
Start Run 2100 Stop Run 2200
Source Date Time Run O2 %
Unit 2 4/7/2011 2105 2 7.78
Unit 2 4/7/2011 2110 2 8.06
Unit 2 4/7/2011 2115 2 8.22
Unit 2 4/7/2011 2120 2 8.48
Unit 2 4/7/2011 2125 2 9.00
Unit 2 4/7/2011 2130 2 8.90
Unit 2 4/7/2011 2135 2 9.00
Unit 2 4/7/2011 2140 2 8.78
Unit 2 4/7/2011 2145 2 8.30 SSB Zero Avg
Unit 2 4/7/2011 2150 2 8.38 0.0155000000
Unit 2 4/7/2011 2155 2 8.47 SSB Bias Avg
Unit 2 4/7/2011 2200 2 8.30 9.82 Average 8.4725
SSB Corrected average 8.60838
Zero 0.00
Bias 9.75
Start Run 2205 Stop Run 2305
Source Date Time Run O2 %
Unit 2 4/7/2011 2210 3 8.22
Unit 2 4/7/2011 2215 3 8.27
Unit 2 4/7/2011 2220 3 8.86

## Unit 2 4/7/2011 2225 3 8.76
Unit 2 4/7/2011 2230 3 8.80
Unit 2 4/7/2011 2235 3 9.10
Unit 2 4/7/2011 2240 3 9.18
Unit 2 4/7/2011 2245 3 8.91
Unit 2 4/7/2011 2250 3 8.82 SSB Zero Avg
Unit 2 4/7/2011 2255 3 8.97 0.0755000000
Unit 2 4/7/2011 2300 3 9.23 SSB Bias Avg
Unit 2 4/7/2011 2305 3 8.36 9.95 Average 8.79
SSB Corrected average 8.807606
Zero 0.15
Bias 10.15

## Bottles 9.99 20.9
CE SSB
Zero -0.01 Zero -0.03 Span 20.95 Bias 9.97
Bias 9.98
Start Run 1010 Stop Run 1110
Source Date Time Run O2 %
Unit 3 4/7/2011 1015 1 6.30
Unit 3 4/7/2011 1020 1 6.31
Unit 3 4/7/2011 1025 1 6.21
Unit 3 4/7/2011 1030 1 6.32
Unit 3 4/7/2011 1035 1 6.39
Unit 3 4/7/2011 1040 1 6.41
Unit 3 4/7/2011 1045 1 5.99
Unit 3 4/7/2011 1050 1 6.15
Unit 3 4/7/2011 1055 1 6.18 SSB Zero Avg
Unit 3 4/7/2011 1060 1 5.92 -0.030
Unit 3 4/7/2011 1065 1 5.80 SSB Bias Avg
Unit 3 4/7/2011 1110 1 5.88 9.425 Average 6.155
SSB Corrected average 6.528429
Zero -0.03
Bias 8.88
Start Run 1135 Stop Run 1235
Source Date Time Run O2 %
Unit 3 4/7/2011 1140 2 5.89
Unit 3 4/7/2011 1145 2 5.93
Unit 3 4/7/2011 1150 2 5.90
Unit 3 4/7/2011 1155 2 5.93
Unit 3 4/7/2011 1160 2 5.94
Unit 3 4/7/2011 1165 2 5.92
Unit 3 4/7/2011 1170 2 5.95
Unit 3 4/7/2011 1175 2 5.93
Unit 3 4/7/2011 1180 2 5.90 SSB Zero Avg
Unit 3 4/7/2011 1185 2 5.92 -0.030
Unit 3 4/7/2011 1190 2 5.93 SSB Bias Avg
Unit 3 4/7/2011 1235 2 6.10 9.25 Average 5.936667
SSB Corrected average 6.416739
Zero -0.03
Bias 9.62
Start Run 1300 Stop Run 1400
Source Date Time Run O2 %
Unit 3 4/7/2011 1305 3 6.00
Unit 3 4/7/2011 1310 3 6.05
Unit 3 4/7/2011 1315 3 6.10

## Unit 3 4/7/2011 1320 3 6.00
Unit 3 4/7/2011 1325 3 6.15
Unit 3 4/7/2011 1330 3 6.20
Unit 3 4/7/2011 1335 3 6.23
Unit 3 4/7/2011 1340 3 6.18
Unit 3 4/7/2011 1345 3 6.20 SSB Zero Avg
Unit 3 4/7/2011 1350 3 6.15 -0.035
Unit 3 4/7/2011 1355 3 6.21 SSB Bias Avg
Unit 3 4/7/2011 1400 3 6.20 9.74 Average 6.139167
SSB Corrected average 6.306876
Zero -0.04
Bias 9.85

## Bottles 9.99 20.9
CE SSB
Zero 0.05 Zero -0.01 Span 20.98 Bias 9.82
Bias 10.01
Start Run 905 Stop Run 1005
Source Date Time Run O2 %
Unit 4 4/6/2011 910 1 4.94
Unit 4 4/6/2011 915 1 4.93
Unit 4 4/6/2011 920 1 4.87
Unit 4 4/6/2011 925 1 4.86
Unit 4 4/6/2011 930 1 4.88
Unit 4 4/6/2011 935 1 4.87
Unit 4 4/6/2011 940 1 4.99
Unit 4 4/6/2011 945 1 5.00
Unit 4 4/6/2011 950 1 4.89 SSB Zero Avg
Unit 4 4/6/2011 955 1 4.94 -0.0200000000
Unit 4 4/6/2011 960 1 4.98 SSB Bias Avg
Unit 4 4/6/2011 1005 1 4.96 9.78 Average 4.925833
SSB Corrected average 5.051815
Zero -0.03
Bias 9.74
Start Run 1035 Stop Run 1135
Source Date Time Run O2 %
Unit 4 4/6/2011 1040 2 4.90
Unit 4 4/6/2011 1045 2 4.98
Unit 4 4/6/2011 1050 2 4.89
Unit 4 4/6/2011 1055 2 4.88
Unit 4 4/6/2011 1060 2 4.92
Unit 4 4/6/2011 1065 2 4.95
Unit 4 4/6/2011 1070 2 4.90
Unit 4 4/6/2011 1075 2 4.87
Unit 4 4/6/2011 1080 2 4.97 SSB Zero Avg
Unit 4 4/6/2011 1085 2 5.00 -0.0300000000
Unit 4 4/6/2011 1090 2 4.89 SSB Bias Avg
Unit 4 4/6/2011 1135 2 4.88 9.72 Average 4.919167
SSB Corrected average 5.081144
Zero -0.03
Bias 9.7
Start Run 1205 Stop Run 1305
Source Date Time Run O2 %
Unit 4 4/6/2011 1210 3 4.85
Unit 4 4/6/2011 1215 3 4.92
Unit 4 4/6/2011 1220 3 4.91

## Unit 4 4/6/2011 1225 3 4.92
Unit 4 4/6/2011 1230 3 5.00
Unit 4 4/6/2011 1235 3 4.87
Unit 4 4/6/2011 1240 3 5.00
Unit 4 4/6/2011 1245 3 4.90
Unit 4 4/6/2011 1250 3 4.88 SSB Zero Avg
Unit 4 4/6/2011 1255 3 4.84 -0.0350000000
Unit 4 4/6/2011 1260 3 4.93 SSB Bias Avg
Unit 4 4/6/2011 1305 3 5.02 9.76 Average 4.92
SSB Corrected average 5.063762
Zero -0.04
Bias 9.82

## Bottles 9.99 20.9
CE SSB
Zero 0.01 Zero 0.02 Span 20.9 Bias 9.94
Bias 9.97
Start Run 1400 Stop Run 1500
Source Date Time Run O2 %
Unit 5 4/5/2011 1405 1 6.23
Unit 5 4/5/2011 1410 1 6.12
Unit 5 4/5/2011 1415 1 6.15
Unit 5 4/5/2011 1420 1 6.2
Unit 5 4/5/2011 1425 1 6.17
Unit 5 4/5/2011 1430 1 6.32
Unit 5 4/5/2011 1435 1 6.16
Unit 5 4/5/2011 1440 1 6.13
Unit 5 4/5/2011 1445 1 6.08 SSB Zero Avg
Unit 5 4/5/2011 1450 1 6.15 0.0050000000
Unit 5 4/5/2011 1455 1 6.13 SSB Bias Avg
Unit 5 4/5/2011 1500 1 6.15 9.895 Average 6.165
SSB Corrected average 6.209828
Zero -0.01
Bias 9.85
Start Run 1600 Stop Run 1700
Source Date Time Run O2 %
Unit 5 4/5/2011 1605 2 6.16
Unit 5 4/5/2011 1610 2 6.13
Unit 5 4/5/2011 1615 2 6.23
Unit 5 4/5/2011 1620 2 6.12
Unit 5 4/5/2011 1625 2 6.08
Unit 5 4/5/2011 1630 2 6.15
Unit 5 4/5/2011 1635 2 6.23
Unit 5 4/5/2011 1640 2 6.11
Unit 5 4/5/2011 1645 2 6.13 SSB Zero Avg
Unit 5 4/5/2011 1650 2 6.06 -0.0050000000
Unit 5 4/5/2011 1655 2 6.16 SSB Bias Avg
Unit 5 4/5/2011 1700 2 6.11 9.815 Average 6.139167
SSB Corrected average 6.238018
Zero 0.00
Bias 9.78
Start Run 1800 Stop Run 1900
Source Date Time Run O2 %
Unit 5 4/5/2011 1805 3 6.05
Unit 5 4/5/2011 1810 3 6.03
Unit 5 4/5/2011 1815 3 6.1

## Unit 5 4/5/2011 1820 3 6.18
Unit 5 4/5/2011 1825 3 6.09
Unit 5 4/5/2011 1830 3 6.08
Unit 5 4/5/2011 1835 3 6.16
Unit 5 4/5/2011 1840 3 6.14
Unit 5 4/5/2011 1845 3 6.1 SSB Zero Avg
Unit 5 4/5/2011 1850 3 6.13 0.0050000000
Unit 5 4/5/2011 1855 3 6.09 SSB Bias Avg
Unit 5 4/5/2011 1900 3 6.08 9.78 Average 6.165
SSB Corrected average 6.282885
Zero 0.01
Bias 9.78

### Run averages corrected for bias **Operator: JSH Plant Name: APS**  **Location: Unit 5 Air Preheater Inlet O2 CO2**  **Run % %**  **1 6.33 13.15 2 4.02 15.32** 

### Calibration Error Test at Run 1 . STRATA Version 3.2 **O2 CO2**

**% % 9/30/11 12:22:55 0.15 -0.02**  **9/30/11 12:23:55 1.33 1.17 9/30/11 12:24:55 27.29 18.27**  **9/30/11 12:25:55 20.44 19.93 9/30/11 12:26:55 11.01 11.18** 

**Calibration Error Test at Run 1 Operator: JSH**  **Plant Name: APS Location: Unit 5 Air Preheater Outlet**  **Reference Cylinder Numbers Zero Low-range Mid-range High-range**  **O2 SX48388**  **CC137800 CC189787 CO2 SX48388**  **CC137800 CC189787**

**Date/Time 9/30/11 12:27:16 PASSED Analyte**  **O2 CO2 Units**  **% % Zero Ref Cyl**  **0 0 Zero Avg**  **-0.02 -0.02 Zero Error% 0.1 0.1**  **Low Ref Cyl Low Avg**  **Low Error% Mid Ref Cyl 11.01 11.15**  **Mid Avg 10.91 11.18**  **Mid Error% 0.4 0.1**  **High Ref Cyl 21.3 21.39 High Avg**  **21.03 21.42 High Error% 1.1 0.1** 

### Test Run 1 Begin. STRATA Version 3.2 **Operator: JSH Plant Name: APS**  **Location: Unit 5 Air Preheater Outlet O2 CO2** 

**% % Begin calculating run averages**  **9/30/11 12:28:29 10.85 11.13 9/30/11 12:29:29 10.86 11.08**  **9/30/11 12:30:29 15.82 6.19 9/30/11 12:31:29 8.50 11.73**  **9/30/11 12:32:29 6.06 13.07 9/30/11 12:33:29 6.44 12.78**  **Average of Test Run O2 CO2**  **% % 9/30/11 12:33:48 6.25 12.93**  **Test Run 1 End**

### Final System Bias Check for Run 1 . STRATA Version 3.2 **O2 CO2**

**% %**

**Final System Bias Check for Run 1 Operator: JSH**  **Plant Name: APS Location: Unit 5 Air Preheater Outlet**  **Reference Cylinder Numbers Zero Span**  **O2 SX48388 CC137800**  **CO2 SX48388 CC137800**

**Date/Time 9/30/11 12:33:53 PASSED Analyte**  **O2 CO2 Units**  **% % Zero Ref Cyl**  **0 0 Zero Cal**  **-0.02 -0.02 Zero Avg**  **0.08 0.22 Zero Bias%**  **0.0 0.0 Zero Drift%**  **0.0 0.0 Span Ref Cyl 11.01 11.15**  **Span Cal 10.91 11.18**  **Span Avg 10.89 11.01**  **Span Bias% 0.0 0.0**  **Span Drift% 0.0 0.0** 

**Ini Zero Avg -0.02 -0.02**  **Ini Span Avg 10.91 11.18**  **Run Avg 6.25 12.93**  **Co 0.00 0.00**  **Cm 0.00 0.00**  **Correct Avg 6.33 13.15** 

### Test Run 2 Begin. STRATA Version 3.2 **Operator: JSH Plant Name: APS**  **Location: Unit 5 Air Preheater Inlet O2 CO2** 

**% % 9/30/11 14:07:04 10.35 10.03**  **9/30/11 14:08:04 3.73 14.95 Begin calculating run averages**  **9/30/11 14:09:26 3.64 15.13 9/30/11 14:10:26 3.92 15.07**  **Average of Test Run O2 CO2**  **% % 9/30/11 14:11:14 3.98 14.95**  **Test Run 2 End**

### Final System Bias Check for Run 2 . STRATA Version 3.2 **O2 CO2**

**% % 9/30/11 14:13:50 1.51 2.70**  **9/30/11 14:14:50 5.52 6.53**

**Final System Bias Check for Run 2 Operator: JSH**  **Plant Name: APS Location: Unit 5 Air Preheater Inlet**  **Reference Cylinder Numbers Zero Span**  **O2 SX48388 CC137800**  **CO2 SX48388 CC137800**

**Date/Time 9/30/11 14:15:00 PASSED Analyte**  **O2 CO2 Units**  **% % Zero Ref Cyl**  **0 0 Zero Cal**  **-0.02 -0.02 Zero Avg**  **0.07 0.32 Zero Bias%**  **0.4 1.3 Zero Drift%**  **0.3 1.3 Span Ref Cyl 11.01 11.15**  **Span Cal 10.91 11.18**  **Span Avg 10.87 10.99**  **Span Bias% 0.2 0.8**  **Span Drift% 0.0 0.0** 

**Ini Zero Avg 0.08 0.22**  **Ini Span Avg 10.89 11.01**  **Run Avg 3.98 14.95**  **Co 0.04 0.27**  **Cm 10.88 11.00**  **Correct Avg 4.02 15.32** 

## APPENDIX F – UNIT OPERATIONAL DATA

### 5GJ5NETMW NET MWATTS
5FFXFUELFLOW FUEL FLOW
5AAVO2NET90AVG O2 SELECTED TOTAL AVERAGE
5RAVWETO2VAL UNIT 5 % O2 WET
5RAVAVGFLOW UNIT 5 % KSCFM
5RAVSO2PPM1MIN SO2 PPM 1MIN

5GJ5NETMW 5FFXFUELFLOW 5AAVO2NET90A 5RAVWETO2VAL 5RAVAVGFLOW 5RAVSO2PPM1MIN 05-Apr-11 14:00:00 745.3 63.9 2.31 5.41 1827.53 104.8 05-Apr-11 14:02:00 746.8 63.8 2.32 6.01 1833.54 104.6 05-Apr-11 14:04:00 747.4 63.7 2.29 5.54 1831.58 0.0 05-Apr-11 14:06:00 745.1 63.7 2.34 5.43 1828.22 106.0 05-Apr-11 14:08:00 744.5 63.6 2.34 5.41 1824.85 106.3 05-Apr-11 14:10:00 745.3 63.8 2.37 5.40 1821.49 106.6 05-Apr-11 14:12:00 745.1 63.7 2.38 5.39 1818.13 106.9 05-Apr-11 14:14:00 745.3 64.0 2.35 5.47 1814.77 107.2 05-Apr-11 14:16:00 746.8 64.0 2.25 15.71 1811.40 107.0 05-Apr-11 14:18:00 746.8 63.6 2.17 5.49 1808.04 32.3 05-Apr-11 14:20:00 746.1 63.3 2.25 5.48 1795.68 75.5 05-Apr-11 14:22:00 745.3 63.1 2.28 5.46 1779.46 107.1 05-Apr-11 14:24:00 744.6 63.1 2.30 5.45 1763.23 107.1 05-Apr-11 14:26:00 744.2 63.3 2.28 5.44 1760.63 107.1 05-Apr-11 14:28:00 745.1 63.3 2.26 5.42 1761.26 107.2 05-Apr-11 14:30:00 744.8 63.5 2.33 5.41 1761.88 107.2 05-Apr-11 14:32:00 742.9 63.6 2.46 6.28 1762.51 107.2 05-Apr-11 14:34:00 744.1 64.0 2.36 5.54 1763.13 0.0 05-Apr-11 14:36:00 745.0 63.8 2.39 5.44 1763.76 106.3 05-Apr-11 14:38:00 741.9 64.2 2.43 5.41 1764.38 106.3 05-Apr-11 14:40:00 744.7 64.2 2.33 5.50 1766.02 106.2 05-Apr-11 14:42:00 746.7 64.2 2.29 5.48 1768.08 106.2 05-Apr-11 14:44:00 744.0 64.1 2.36 5.45 1770.14 106.2 05-Apr-11 14:46:00 747.3 64.1 2.25 13.21 1772.21 106.1 05-Apr-11 14:48:00 746.5 63.9 2.31 5.52 1774.27 28.3 05-Apr-11 14:50:00 746.8 63.8 2.39 5.40 1776.33 76.0 05-Apr-11 14:52:00 747.6 63.8 2.27 5.49 1778.39 105.6 05-Apr-11 14:54:00 746.8 63.8 2.27 5.47 1780.45 105.5 05-Apr-11 14:56:00 746.9 63.8 2.47 5.42 1782.51 105.4 05-Apr-11 14:58:00 745.4 63.7 2.27 5.39 1784.57 105.3 05-Apr-11 15:00:00 747.0 63.9 2.27 5.38 1786.63 105.2 05-Apr-11 15:02:00 746.0 63.7 2.37 6.56 1788.70 105.1 05-Apr-11 15:04:00 746.2 63.7 2.37 5.47 1790.76 0.0 05-Apr-11 15:06:00 746.8 63.8 2.26 5.46 1792.70 105.5 05-Apr-11 15:08:00 745.3 63.7 2.39 5.45 1794.53 105.6 05-Apr-11 15:10:00 743.8 63.8 2.29 5.44 1796.37 105.6 05-Apr-11 15:12:00 745.3 63.9 2.28 5.44 1798.20 105.7 05-Apr-11 15:14:00 745.9 63.8 2.48 5.43 1800.04 105.7 05-Apr-11 15:16:00 745.3 64.0 2.37 10.10 1801.87 105.8 05-Apr-11 15:18:00 745.5 63.8 2.28 5.62 1803.71 31.3 05-Apr-11 15:20:00 747.5 63.5 2.32 5.44 1805.55 76.7 05-Apr-11 15:22:00 744.6 63.4 2.31 5.40 1807.38 104.4 05-Apr-11 15:24:00 746.0 63.2 2.19 5.39 1793.62 104.1 05-Apr-11 15:26:00 744.5 63.2 2.42 5.39 1777.69 103.8 05-Apr-11 15:28:00 744.6 63.4 2.26 5.51 1778.56 103.5 05-Apr-11 15:30:00 744.4 63.3 2.29 5.46 1779.44 103.2 05-Apr-11 15:32:00 744.6 63.6 2.33 6.92 1780.32 104.4

### 05-Apr-11 15:34:00 744.7 63.7 2.44 5.47 1781.20 0.0 05-Apr-11 15:36:00 743.1 63.9 2.25 5.46 1782.08 104.7 05-Apr-11 15:38:00 744.4 64.0 2.46 5.44 1782.96 104.8 05-Apr-11 15:40:00 743.8 64.1 2.47 5.43 1783.84 104.9 05-Apr-11 15:42:00 744.3 64.2 2.28 5.42 1784.72 104.9 05-Apr-11 15:44:00 746.7 64.1 2.30 5.40 1785.59 105.0 05-Apr-11 15:46:00 744.7 63.9 2.35 6.55 1786.47 105.1 05-Apr-11 15:48:00 745.3 63.9 2.30 5.47 1787.35 29.0 05-Apr-11 15:50:00 746.1 63.8 2.35 5.46 1788.23 78.1 05-Apr-11 15:52:00 745.3 63.8 2.30 5.44 1792.44 104.5 05-Apr-11 15:54:00 745.0 63.8 2.31 5.42 1798.37 104.3 05-Apr-11 15:56:00 745.3 63.9 2.36 5.40 1804.31 104.1 05-Apr-11 15:58:00 745.0 63.9 2.35 5.40 1810.24 103.9 05-Apr-11 16:00:00 746.1 63.9 2.32 5.42 1816.17 103.7 05-Apr-11 16:02:00 745.8 63.8 2.33 7.64 1822.11 103.5 05-Apr-11 16:04:00 745.6 63.8 2.22 5.43 1828.04 0.0 05-Apr-11 16:06:00 745.3 63.8 2.17 5.41 1827.27 104.0 05-Apr-11 16:08:00 744.3 63.8 2.23 5.39 1825.15 101.1 05-Apr-11 16:10:00 745.1 64.0 2.31 5.37 1823.03 98.2 05-Apr-11 16:12:00 745.8 63.9 2.32 5.35 1820.91 95.3 05-Apr-11 16:14:00 745.3 64.0 2.18 5.33 1818.79 92.4 05-Apr-11 16:16:00 746.8 63.9 2.32 5.47 1816.67 91.7 05-Apr-11 16:18:00 745.5 63.7 2.24 5.65 1814.55 30.6 05-Apr-11 16:20:00 744.6 63.8 2.23 5.46 1812.44 64.6 05-Apr-11 16:22:00 744.8 63.6 2.40 5.42 1810.32 90.9 05-Apr-11 16:24:00 746.5 63.6 2.19 5.49 1808.20 91.0 05-Apr-11 16:26:00 744.4 63.6 2.23 5.39 1806.08 91.0 05-Apr-11 16:28:00 745.2 63.8 2.33 5.38 1811.85 91.1 05-Apr-11 16:30:00 746.5 63.7 2.22 5.45 1827.62 91.2 05-Apr-11 16:32:00 744.4 63.8 2.24 8.60 1822.40 91.3 05-Apr-11 16:34:00 744.4 64.0 2.45 5.50 1817.18 0.0 05-Apr-11 16:36:00 744.0 64.2 2.33 5.44 1811.96 90.5 05-Apr-11 16:38:00 746.1 64.1 2.11 5.38 1806.74 90.8 05-Apr-11 16:40:00 745.5 64.1 2.37 5.33 1801.52 91.2 05-Apr-11 16:42:00 746.0 63.9 2.21 5.48 1796.30 91.5 05-Apr-11 16:44:00 746.1 63.8 2.24 5.43 1791.08 91.8 05-Apr-11 16:46:00 747.5 63.6 2.25 5.38 1785.86 92.2 05-Apr-11 16:48:00 747.5 63.6 2.10 5.53 1781.85 30.2 05-Apr-11 16:50:00 745.3 63.6 2.27 5.31 1782.04 66.1 05-Apr-11 16:52:00 743.8 63.7 2.29 5.36 1782.23 92.3 05-Apr-11 16:54:00 746.6 63.7 2.14 5.41 1782.42 92.3 05-Apr-11 16:56:00 746.0 63.8 2.18 5.39 1782.61 92.4 05-Apr-11 16:58:00 744.0 63.8 2.31 5.33 1782.80 92.4 05-Apr-11 17:00:00 745.3 63.8 2.19 5.44 1782.98 92.5 05-Apr-11 17:02:00 746.0 63.8 2.23 10.41 1783.17 91.3 05-Apr-11 17:04:00 745.3 63.6 2.36 5.34 1783.36 0.0 05-Apr-11 17:06:00 747.3 63.6 2.24 5.38 1783.55 91.5 05-Apr-11 17:08:00 745.3 63.5 2.27 5.39 1783.74 91.8 05-Apr-11 17:10:00 743.0 63.5 2.34 5.38 1783.92 92.0 05-Apr-11 17:12:00 745.3 63.6 2.29 5.37 1784.11 92.3 05-Apr-11 17:14:00 746.7 63.5 2.27 5.36 1784.30 92.6 05-Apr-11 17:16:00 746.1 63.7 2.18 5.35 1784.49 89.4 05-Apr-11 17:18:00 746.8 63.7 2.22 5.61 1784.68 25.5 05-Apr-11 17:20:00 743.8 63.5 2.22 5.39 1784.87 61.2 05-Apr-11 17:22:00 745.4 63.6 2.42 5.45 1785.05 87.6

### 05-Apr-11 17:24:00 746.8 63.5 2.17 5.52 1785.24 87.8 05-Apr-11 17:26:00 744.0 63.4 2.22 5.42 1785.43 88.0 05-Apr-11 17:28:00 744.8 63.5 2.23 5.38 1785.62 88.2 05-Apr-11 17:30:00 745.3 63.5 2.33 5.42 1793.11 88.5 05-Apr-11 17:32:00 746.1 63.4 2.31 12.13 1779.16 87.6 05-Apr-11 17:34:00 746.1 63.5 2.39 5.43 1765.22 0.0 05-Apr-11 17:36:00 746.1 63.6 2.22 5.41 1751.52 88.0 05-Apr-11 17:38:00 745.6 63.4 2.06 5.40 1752.60 88.0 05-Apr-11 17:40:00 741.5 63.5 2.24 5.38 1753.68 88.0 05-Apr-11 17:42:00 744.5 63.6 2.34 5.38 1754.77 87.9 05-Apr-11 17:44:00 743.7 64.0 2.31 5.40 1755.85 87.9 05-Apr-11 17:46:00 744.2 64.1 2.27 5.41 1756.93 87.9 05-Apr-11 17:48:00 745.4 64.2 2.33 5.65 1758.01 24.9 05-Apr-11 17:50:00 744.9 64.2 2.30 5.46 1759.10 62.2 05-Apr-11 17:52:00 744.5 64.1 2.27 5.44 1760.18 88.0 05-Apr-11 17:54:00 744.2 64.2 2.32 5.42 1761.26 87.9 05-Apr-11 17:56:00 745.0 64.2 2.20 5.40 1762.35 87.9 05-Apr-11 17:58:00 745.7 64.0 2.29 5.38 1763.43 87.8 05-Apr-11 18:00:00 744.9 64.0 2.30 5.40 1764.51 87.8 05-Apr-11 18:02:00 745.3 64.0 2.22 15.04 1766.79 86.6 05-Apr-11 18:04:00 745.3 64.0 2.20 5.38 1771.08 0.0 05-Apr-11 18:06:00 744.6 64.1 2.28 5.41 1775.36 87.8 05-Apr-11 18:08:00 746.0 64.3 2.17 5.44 1779.65 87.9 05-Apr-11 18:10:00 746.8 64.0 2.26 5.44 1783.94 88.1 05-Apr-11 18:12:00 745.3 64.2 2.32 5.43 1788.22 88.3 05-Apr-11 18:14:00 745.4 64.2 2.31 5.42 1792.51 88.4 05-Apr-11 18:16:00 745.3 64.3 2.22 5.43 1796.79 88.6 05-Apr-11 18:18:00 746.5 64.0 2.12 5.62 1801.08 26.9 05-Apr-11 18:20:00 747.0 63.8 2.22 5.41 1804.30 63.4 05-Apr-11 18:22:00 744.9 63.8 2.20 5.42 1806.19 88.5 05-Apr-11 18:24:00 743.8 63.7 2.34 5.44 1808.08 88.4 05-Apr-11 18:26:00 745.0 63.9 2.25 5.46 1809.97 88.4 05-Apr-11 18:28:00 743.8 63.9 2.35 5.47 1811.86 88.4 05-Apr-11 18:30:00 743.8 64.1 2.25 5.49 1813.75 88.3 05-Apr-11 18:32:00 745.2 64.2 2.26 18.49 1815.64 88.3 05-Apr-11 18:34:00 743.9 64.3 2.24 5.41 1817.53 0.0 05-Apr-11 18:36:00 744.4 64.3 2.31 5.41 1819.42 88.3 05-Apr-11 18:38:00 745.3 64.4 2.33 5.41 1821.31 88.4 05-Apr-11 18:40:00 745.5 64.3 2.23 5.42 1823.20 88.4 05-Apr-11 18:42:00 744.0 64.4 2.35 5.42 1825.09 88.5 05-Apr-11 18:44:00 743.9 64.5 2.27 5.42 1826.98 88.5 05-Apr-11 18:46:00 744.5 64.4 2.21 5.43 1828.87 88.6 05-Apr-11 18:48:00 745.2 64.6 2.30 5.66 1830.76 25.5 05-Apr-11 18:50:00 746.7 64.5 2.23 5.50 1798.74 0.0 05-Apr-11 18:52:00 746.3 64.5 2.18 5.47 1799.16 89.1 05-Apr-11 18:54:00 746.7 64.3 2.24 5.43 1804.61 89.0 05-Apr-11 18:56:00 746.8 63.9 2.34 5.42 1810.99 88.9 05-Apr-11 18:58:00 745.3 63.9 2.28 5.42 1844.59 88.9 05-Apr-11 19:00:00 745.7 64.1 2.26 5.42 1878.18 88.84GJ5NETMW 4FFXFUELFLOW 4AAVO2NET90AVG 4RAVWETO2VAL 4RAVSTACKFLOW 4RAVSO2PPM1MIN 06-Apr-11 09:00:00 787.1 64.0 2.51 4.37 1711.98 75.5 06-Apr-11 09:02:00 785.2 64.0 2.33 5.25 1673.27 75.8 06-Apr-11 09:04:00 784.4 64.0 2.39 4.44 1677.63 31.2 06-Apr-11 09:06:00 784.8 64.1 2.39 4.29 1671.22 47.4 06-Apr-11 09:08:00 784.4 64.1 2.45 4.38 1715.26 75.7 06-Apr-11 09:10:00 785.2 64.1 2.47 4.38 1620.38 75.8 06-Apr-11 09:12:00 786.8 64.0 2.40 4.41 1668.32 75.8 06-Apr-11 09:14:00 787.6 64.0 2.41 4.36 1700.07 75.9 06-Apr-11 09:16:00 787.2 64.0 2.40 4.30 1702.54 76.0 06-Apr-11 09:18:00 784.0 64.0 2.51 17.05 1719.94 76.1 06-Apr-11 09:20:00 787.0 64.1 2.40 4.52 1714.15 0.0 06-Apr-11 09:22:00 786.0 64.2 2.50 4.35 1663.96 75.1 06-Apr-11 09:24:00 783.2 64.6 2.48 4.44 1735.49 75.2 06-Apr-11 09:26:00 785.0 64.6 2.45 4.43 1694.89 75.2 06-Apr-11 09:28:00 784.2 64.7 2.34 4.41 1737.53 75.3 06-Apr-11 09:30:00 785.0 64.7 2.54 4.40 1734.43 75.3 06-Apr-11 09:32:00 788.1 64.7 2.26 7.20 1716.67 75.4 06-Apr-11 09:34:00 787.3 64.2 2.36 4.49 1695.19 31.0 06-Apr-11 09:36:00 785.8 64.1 2.43 4.37 1665.61 47.0 06-Apr-11 09:38:00 786.9 64.0 2.24 4.32 1693.94 75.1 06-Apr-11 09:40:00 787.4 64.0 2.47 4.33 1699.41 75.1 06-Apr-11 09:42:00 784.0 63.9 2.61 4.33 1688.99 75.2 06-Apr-11 09:44:00 786.2 63.9 2.40 4.33 1713.01 75.3 06-Apr-11 09:46:00 785.8 63.9 2.63 4.34 1720.61 75.3 06-Apr-11 09:48:00 786.3 63.9 2.32 18.07 1689.30 75.4 06-Apr-11 09:50:00 785.8 63.9 2.54 4.32 1673.08 0.0 06-Apr-11 09:52:00 785.6 63.9 2.51 4.33 1724.30 45.7 06-Apr-11 09:54:00 785.6 63.9 2.44 4.38 1664.80 75.5 06-Apr-11 09:56:00 784.8 63.9 2.53 4.39 1688.70 75.6 06-Apr-11 09:58:00 787.2 64.0 2.47 4.36 1655.07 75.7 06-Apr-11 10:00:00 786.3 64.0 2.40 4.33 1665.37 75.8 06-Apr-11 10:02:00 784.0 64.0 2.48 4.30 1692.69 76.0 06-Apr-11 10:04:00 785.6 64.0 2.45 4.56 1656.20 76.1 06-Apr-11 10:06:00 786.3 64.1 2.55 4.39 1716.23 0.0 06-Apr-11 10:08:00 784.8 64.1 2.55 4.32 1703.45 74.2 06-Apr-11 10:10:00 786.2 64.1 2.36 4.36 1702.76 74.3 06-Apr-11 10:12:00 785.6 64.1 2.39 4.36 1711.88 74.4 06-Apr-11 10:14:00 786.3 64.2 2.38 4.35 1697.16 74.4 06-Apr-11 10:16:00 784.8 64.2 2.52 4.35 1698.60 74.5 06-Apr-11 10:18:00 784.8 64.2 2.43 20.25 1685.18 74.6 06-Apr-11 10:20:00 785.6 64.2 2.37 4.43 1687.32 28.3 06-Apr-11 10:22:00 784.8 64.3 2.57 4.32 1683.18 46.9 06-Apr-11 10:24:00 783.9 64.3 2.59 4.42 1674.89 74.1 06-Apr-11 10:26:00 782.0 64.2 2.52 4.39 1662.28 74.1 06-Apr-11 10:28:00 787.6 63.9 2.33 4.37 1682.70 74.2 06-Apr-11 10:30:00 783.1 63.9 2.45 4.35 1671.53 74.3 06-Apr-11 10:32:00 781.9 64.2 2.42 5.24 1696.15 74.3 06-Apr-11 10:34:00 783.3 64.2 2.43 4.63 1711.42 74.4 06-Apr-11 10:36:00 785.5 64.2 2.50 4.40 1715.79 0.0 06-Apr-11 10:38:00 785.8 64.1 2.41 4.33 1710.56 74.1 06-Apr-11 10:40:00 783.2 64.0 2.51 4.35 1668.61 74.2 06-Apr-11 10:42:00 784.8 64.1 2.43 4.37 1674.09 74.3 06-Apr-11 10:44:00 781.9 64.1 2.59 4.30 1669.94 74.4 06-Apr-11 10:46:00 785.9 64.2 2.31 4.42 1688.72 74.5 06-Apr-11 10:48:00 786.5 64.2 2.29 20.20 1678.13 74.5 06-Apr-11 10:50:00 785.2 64.2 2.40 4.30 1678.10 28.1 06-Apr-11 10:52:00 783.3 64.2 2.35 4.36 1671.14 45.006-Apr-11 10:54:00 783.9 64.2 2.43 4.39 1721.95 73.3 06-Apr-11 10:56:00 784.0 64.2 2.41 4.31 1707.75 73.2 06-Apr-11 10:58:00 784.2 64.2 2.35 4.35 1717.72 73.2 06-Apr-11 11:00:00 785.3 64.2 2.43 4.36 1677.66 73.2 06-Apr-11 11:02:00 784.5 64.2 2.45 4.30 1712.78 73.1 06-Apr-11 11:04:00 784.0 64.2 2.39 4.66 1707.63 73.1 06-Apr-11 11:06:00 784.6 64.2 2.36 4.41 1702.82 0.0 06-Apr-11 11:08:00 787.1 64.2 2.45 4.33 1708.65 73.5 06-Apr-11 11:10:00 783.5 64.2 2.43 4.28 1680.29 73.8 06-Apr-11 11:12:00 783.5 64.3 2.43 4.28 1679.35 74.1 06-Apr-11 11:14:00 782.1 64.8 2.44 4.28 1724.51 74.4 06-Apr-11 11:16:00 784.1 64.8 2.55 4.29 1700.70 74.8 06-Apr-11 11:18:00 784.0 64.7 2.44 19.88 1711.07 75.1 06-Apr-11 11:20:00 784.8 64.5 2.39 4.43 1708.87 27.7 06-Apr-11 11:22:00 785.6 64.4 2.36 4.37 1695.28 46.4 06-Apr-11 11:24:00 784.8 64.3 2.35 4.31 1651.33 72.7 06-Apr-11 11:26:00 784.8 64.2 2.54 4.25 1693.30 72.7 06-Apr-11 11:28:00 780.8 64.3 2.46 4.36 1694.81 72.7 06-Apr-11 11:30:00 783.1 64.8 2.33 4.35 1711.45 72.7 06-Apr-11 11:32:00 786.4 64.7 2.48 4.25 1696.53 72.7 06-Apr-11 11:34:00 784.8 64.6 2.40 4.74 1701.79 72.7 06-Apr-11 11:36:00 786.4 64.5 2.28 4.41 1701.08 0.0 06-Apr-11 11:38:00 787.2 64.4 2.49 4.30 1697.95 74.1 06-Apr-11 11:40:00 786.4 64.3 2.40 4.28 1738.39 74.3 06-Apr-11 11:42:00 786.4 64.3 2.37 4.34 1695.66 74.5 06-Apr-11 11:44:00 782.6 64.4 2.48 4.32 1695.75 74.7 06-Apr-11 11:46:00 786.4 64.4 2.45 4.31 1702.47 74.9 06-Apr-11 11:48:00 785.7 64.4 2.45 19.80 1700.12 75.1 06-Apr-11 11:50:00 786.8 64.5 2.39 4.47 1739.71 28.9 06-Apr-11 11:52:00 785.6 64.5 2.51 4.34 1679.74 45.6 06-Apr-11 11:54:00 787.2 64.5 2.63 4.35 1707.55 74.7 06-Apr-11 11:56:00 787.5 64.4 2.42 4.31 1675.86 74.3 06-Apr-11 11:58:00 786.7 64.3 2.47 4.24 1721.61 73.8 06-Apr-11 12:00:00 784.6 64.3 2.49 4.29 1675.45 73.4 06-Apr-11 12:02:00 785.8 64.3 2.50 4.36 1675.63 72.9 06-Apr-11 12:04:00 786.4 64.3 2.35 4.86 1731.33 72.5 06-Apr-11 12:06:00 787.5 64.3 2.44 4.30 1656.96 0.0 06-Apr-11 12:08:00 786.2 64.3 2.48 4.27 1693.35 73.3 06-Apr-11 12:10:00 785.9 64.7 2.50 4.27 1686.48 73.1 06-Apr-11 12:12:00 786.9 64.6 2.54 4.27 1686.39 72.8 06-Apr-11 12:14:00 788.3 64.2 2.49 4.28 1706.67 72.6 06-Apr-11 12:16:00 786.5 64.2 2.55 4.28 1714.58 72.3 06-Apr-11 12:18:00 786.3 64.2 2.29 19.10 1673.14 72.1 06-Apr-11 12:20:00 784.8 64.3 2.53 4.35 1706.13 29.8 06-Apr-11 12:22:00 784.5 64.3 2.56 4.36 1654.14 47.0 06-Apr-11 12:24:00 788.0 64.3 2.54 4.30 1670.55 72.2 06-Apr-11 12:26:00 788.0 64.4 2.54 4.21 1684.88 72.0 06-Apr-11 12:28:00 786.4 64.6 2.39 4.28 1694.36 71.9 06-Apr-11 12:30:00 784.0 64.8 2.30 4.27 1685.70 71.7 06-Apr-11 12:32:00 785.6 64.9 2.61 5.27 1685.78 71.6 06-Apr-11 12:34:00 786.6 64.8 2.50 4.96 1663.60 71.4 06-Apr-11 12:36:00 789.2 64.4 2.46 4.38 1629.00 0.0 06-Apr-11 12:38:00 786.8 64.5 2.49 4.27 1682.05 69.1 06-Apr-11 12:40:00 785.2 64.5 2.55 4.24 1651.79 69.5 06-Apr-11 12:42:00 787.9 64.5 2.45 4.23 1690.06 69.9 06-Apr-11 12:44:00 788.5 64.5 2.32 4.25 1717.72 70.3 06-Apr-11 12:46:00 787.0 64.4 2.52 4.26 1657.19 70.7 06-Apr-11 12:48:00 785.6 64.3 2.44 17.93 1671.70 71.0 06-Apr-11 12:50:00 787.0 64.4 2.60 4.47 1708.19 27.0 06-Apr-11 12:52:00 787.0 64.4 2.43 4.25 1680.03 43.606-Apr-11 12:54:00 785.9 64.5 2.45 4.28 1687.24 70.5 06-Apr-11 12:56:00 786.8 64.5 2.62 4.30 1696.25 70.3 06-Apr-11 12:58:00 784.8 64.6 2.53 4.23 1666.76 70.1 06-Apr-11 13:00:00 785.6 64.6 2.49 4.36 1692.06 69.9 06-Apr-11 13:02:00 785.6 64.7 2.41 4.34 1707.65 69.7 06-Apr-11 13:04:00 786.0 64.7 2.64 5.29 1724.01 69.4 06-Apr-11 13:06:00 785.0 64.7 2.40 4.33 1694.34 0.0 06-Apr-11 13:08:00 786.9 64.7 2.42 4.36 1693.13 69.0 06-Apr-11 13:10:00 786.2 64.6 2.53 4.28 1687.60 69.3 06-Apr-11 13:12:00 788.8 64.5 2.38 4.27 1699.85 69.6 06-Apr-11 13:14:00 783.5 64.4 2.52 4.28 1688.55 69.9 06-Apr-11 13:16:00 785.6 64.4 2.53 4.30 1698.22 70.2 06-Apr-11 13:18:00 786.7 64.4 2.42 15.69 1698.53 70.5 06-Apr-11 13:20:00 787.1 64.4 2.45 4.33 1667.38 27.1 06-Apr-11 13:22:00 786.2 64.5 2.57 4.26 1684.46 41.5 06-Apr-11 13:24:00 785.7 64.5 2.48 4.27 1701.89 69.6 06-Apr-11 13:26:00 788.0 64.5 2.48 4.27 1713.21 69.7 06-Apr-11 13:28:00 788.4 64.6 2.49 4.22 1704.77 69.9 06-Apr-11 13:30:00 785.6 64.7 2.53 4.22 1709.43 70.03GJ5NETMWATT 3FFVTOTLFUELFL 3AAVSELO2 3RAVO2PERCENT 3RAVSTKGASFLOW 3RAVSO2PPM1MIN 07-Apr-11 10:10:00 220.6 65.2 2.72 6.02 2575582 69.23 07-Apr-11 10:12:00 221.3 65.3 2.71 5.89 2568136 68.76 07-Apr-11 10:14:00 222.1 65.6 2.70 5.94 2520963 68.29 07-Apr-11 10:16:00 223.4 64.3 2.74 5.85 2516869 67.83 07-Apr-11 10:18:00 221.6 64.4 2.66 6.17 2535008 67.36 07-Apr-11 10:20:00 219.7 64.0 2.70 17.98 2479595 66.89 07-Apr-11 10:22:00 217.7 64.6 2.55 5.84 2431710 14.93 07-Apr-11 10:24:00 219.5 65.6 2.69 6.12 2499652 47.15 07-Apr-11 10:26:00 220.3 65.6 2.70 5.95 2537378 62.40 07-Apr-11 10:28:00 221.5 65.5 2.66 5.90 2531069 62.64 07-Apr-11 10:30:00 222.3 65.6 2.71 5.98 2528536 62.87 07-Apr-11 10:32:00 223.4 65.5 2.73 5.96 2517881 63.10 07-Apr-11 10:34:00 221.8 64.1 2.79 6.11 2499155 63.34 07-Apr-11 10:36:00 220.1 63.4 2.62 6.02 2450715 63.57 07-Apr-11 10:38:00 219.5 65.1 2.61 5.92 2431554 22.96 07-Apr-11 10:40:00 220.3 65.7 2.67 6.07 2570878 59.62 07-Apr-11 10:42:00 222.1 65.6 2.59 5.80 2546848 60.19 07-Apr-11 10:44:00 222.5 65.6 2.70 5.82 2501305 60.75 07-Apr-11 10:46:00 221.8 64.4 2.87 6.00 2516256 61.32 07-Apr-11 10:48:00 221.5 64.6 2.70 6.03 2475825 61.88 07-Apr-11 10:50:00 221.4 64.4 2.74 19.95 2451708 62.45 07-Apr-11 10:52:00 219.6 64.8 2.58 5.88 2415805 14.65 07-Apr-11 10:54:00 219.8 65.7 2.81 6.03 2483768 50.17 07-Apr-11 10:56:00 220.6 65.3 2.72 6.05 2544523 56.99 07-Apr-11 10:58:00 221.6 65.4 2.64 5.95 2502917 57.21 07-Apr-11 11:00:00 221.9 65.4 2.80 5.92 2504463 57.42 07-Apr-11 11:02:00 222.3 64.2 2.89 5.96 2517161 57.64 07-Apr-11 11:04:00 220.1 64.5 2.72 7.34 2451146 57.85 07-Apr-11 11:06:00 219.5 64.3 2.67 5.98 2430106 58.07 07-Apr-11 11:08:00 220.0 65.1 2.73 5.96 2442563 21.97 07-Apr-11 11:10:00 221.0 65.0 2.69 6.05 2527872 57.31 07-Apr-11 11:12:00 221.6 65.1 2.70 5.99 2521152 56.58 07-Apr-11 11:14:00 220.8 65.1 2.71 5.90 2508303 55.85 07-Apr-11 11:16:00 220.5 65.1 2.75 5.99 2484736 55.12 07-Apr-11 11:18:00 220.6 63.7 2.67 6.08 2494080 54.38 07-Apr-11 11:20:00 220.6 63.5 2.65 19.96 2443459 53.65 07-Apr-11 11:22:00 217.1 64.0 2.50 5.95 2426936 32.97 07-Apr-11 11:24:00 218.9 64.8 2.92 6.14 2510344 42.18 07-Apr-11 11:26:00 219.4 64.5 2.81 6.01 2557839 55.39 07-Apr-11 11:28:00 220.7 64.8 2.70 6.09 2489584 55.49 07-Apr-11 11:30:00 220.0 64.9 2.58 5.86 2473365 55.59 07-Apr-11 11:32:00 220.8 65.0 2.69 5.89 2499042 55.69 07-Apr-11 11:34:00 221.3 63.8 2.77 5.92 2515081 55.79 07-Apr-11 11:36:00 220.3 63.9 2.69 6.17 2508912 55.88 07-Apr-11 11:38:00 217.0 64.3 2.68 5.97 2457744 6.32 07-Apr-11 11:40:00 219.7 65.5 2.77 5.96 2490661 53.91 07-Apr-11 11:42:00 221.0 65.5 2.72 5.92 2537753 53.92 07-Apr-11 11:44:00 221.5 65.8 2.74 5.86 2537563 53.94 07-Apr-11 11:46:00 222.3 65.6 2.77 5.95 2537496 53.96 07-Apr-11 11:48:00 222.4 65.4 2.64 5.94 2510489 53.97 07-Apr-11 11:50:00 221.3 63.9 2.84 19.85 2458033 53.99 07-Apr-11 11:52:00 220.5 64.2 2.57 5.96 2414945 33.58 07-Apr-11 11:54:00 219.5 64.4 2.58 5.85 2448248 41.63 07-Apr-11 11:56:00 219.9 64.7 2.68 5.91 2496594 53.98 07-Apr-11 11:58:00 220.7 65.1 2.56 5.94 2473453 53.61 07-Apr-11 12:00:00 222.2 65.1 2.64 5.79 2492634 53.24 07-Apr-11 12:02:00 222.2 65.0 2.73 5.85 2484222 52.88 07-Apr-11 12:04:00 223.1 64.9 2.80 5.89 2451370 52.51 07-Apr-11 12:06:00 221.6 63.9 2.80 6.20 2477760 52.1407-Apr-11 12:08:00 219.9 63.3 2.61 5.87 2403789 6.46 07-Apr-11 12:10:00 219.8 64.0 2.69 5.94 2420222 51.86 07-Apr-11 12:12:00 221.1 64.8 2.78 5.88 2511806 51.50 07-Apr-11 12:14:00 221.5 65.0 2.73 5.84 2593482 51.13 07-Apr-11 12:16:00 221.8 65.0 2.77 5.85 2556397 50.76 07-Apr-11 12:18:00 221.6 65.0 2.75 5.89 2480578 50.40 07-Apr-11 12:20:00 221.6 63.0 2.85 19.65 2460953 50.03 07-Apr-11 12:22:00 219.4 63.2 2.57 6.05 2446216 31.12 07-Apr-11 12:24:00 218.5 63.9 2.11 5.82 2401941 37.50 07-Apr-11 12:26:00 218.4 62.5 2.87 5.80 2396254 43.75 07-Apr-11 12:28:00 217.9 63.1 2.94 5.99 2500312 36.61 07-Apr-11 12:30:00 220.9 66.2 2.94 6.02 2618058 29.46 07-Apr-11 12:32:00 220.8 63.9 3.53 6.22 2699428 22.32 07-Apr-11 12:34:00 221.6 63.3 2.83 6.23 2577488 15.18 07-Apr-11 12:36:00 220.6 64.6 2.72 6.23 2431106 8.04 07-Apr-11 12:38:00 219.5 64.9 2.54 5.76 2412432 0.89 07-Apr-11 12:40:00 220.3 65.1 2.69 5.83 2490681 2.11 07-Apr-11 12:42:00 220.0 65.4 2.64 5.94 2506617 4.53 07-Apr-11 12:44:00 223.0 64.9 2.64 5.66 2469085 6.95 07-Apr-11 12:46:00 221.8 65.4 2.70 5.71 2490670 9.37 07-Apr-11 12:48:00 221.6 65.1 2.71 5.88 2523389 11.78 07-Apr-11 12:50:00 222.3 64.1 2.72 19.31 2474492 14.20 07-Apr-11 12:52:00 218.8 63.5 2.51 5.86 2420841 16.62 07-Apr-11 12:54:00 220.3 64.5 2.61 5.77 2399155 19.03 07-Apr-11 12:56:00 220.2 65.1 2.62 5.82 2476994 21.45 07-Apr-11 12:58:00 221.7 64.8 2.62 5.86 2520878 23.87 07-Apr-11 13:00:00 221.8 65.0 2.59 5.64 2497743 26.29 07-Apr-11 13:02:00 221.6 62.8 2.93 5.87 2506912 28.70 07-Apr-11 13:04:00 220.1 63.6 2.65 5.93 2498238 31.12 07-Apr-11 13:06:00 220.0 63.7 2.59 5.95 2442030 33.54 07-Apr-11 13:08:00 219.9 63.9 2.48 5.79 2412659 4.35 07-Apr-11 13:10:00 220.3 64.3 2.69 5.82 2464939 5.67 07-Apr-11 13:12:00 219.6 65.2 2.79 5.86 2505916 12.14 07-Apr-11 13:14:00 221.3 64.6 2.68 5.90 2508544 18.62 07-Apr-11 13:16:00 223.5 64.6 2.57 5.93 2497769 25.09 07-Apr-11 13:18:00 221.9 63.0 2.73 5.97 2477333 31.57 07-Apr-11 13:20:00 219.9 62.8 2.63 19.23 2436846 38.04 07-Apr-11 13:22:00 219.0 63.3 2.57 5.80 2402516 26.82 07-Apr-11 13:24:00 218.7 64.4 2.73 5.90 2511626 30.52 07-Apr-11 13:26:00 219.6 64.7 2.85 6.01 2623251 42.68 07-Apr-11 13:28:00 220.2 64.9 2.64 5.81 2598149 44.94 07-Apr-11 13:30:00 221.5 64.7 2.72 5.90 2510415 47.20 07-Apr-11 13:32:00 222.0 63.8 2.86 5.87 2489860 49.46 07-Apr-11 13:34:00 220.6 63.3 2.92 6.09 2496898 51.72 07-Apr-11 13:36:00 219.8 63.4 2.67 6.17 2420267 53.98 07-Apr-11 13:38:00 218.0 64.0 2.49 5.83 2432203 6.90 07-Apr-11 13:40:00 220.3 64.4 2.75 6.01 2512037 54.71 07-Apr-11 13:42:00 220.3 64.5 2.72 5.88 2498959 56.53 07-Apr-11 13:44:00 220.7 64.7 2.80 5.88 2496979 58.35 07-Apr-11 13:46:00 221.8 64.4 2.81 5.94 2529497 60.18 07-Apr-11 13:48:00 220.3 63.9 2.85 6.01 2534704 62.00 07-Apr-11 13:50:00 220.1 62.7 2.72 18.99 2457740 63.82 07-Apr-11 13:52:00 218.5 63.8 2.50 5.71 2384686 17.11 07-Apr-11 13:54:00 219.4 64.8 2.67 5.93 2456615 49.42 07-Apr-11 13:56:00 219.9 65.1 2.86 6.04 2558640 64.31 07-Apr-11 13:58:00 222.4 65.0 2.72 6.00 2595584 64.98 07-Apr-11 14:00:00 223.6 64.8 2.69 5.76 2551220 65.662GJ5NETMWATT 2FFVTOTLFUELFL 2AAVSELO2 2RAVO2PERCENT 2RAVSTKGASFLOW 2RAVSO2PPM1MIN 07-Apr-11 19:00:00 170.7 57.41 5.45 7.92 2073120 57.3 07-Apr-11 19:02:00 172.7 57.87 5.33 8.02 2075785 57.0 07-Apr-11 19:04:00 172.7 57.17 5.39 7.71 2082304 56.6 07-Apr-11 19:06:00 171.3 56.60 5.79 8.09 2070829 56.2 07-Apr-11 19:08:00 169.7 56.93 5.41 19.66 2053391 52.8 07-Apr-11 19:10:00 169.6 57.35 5.45 8.26 2030544 10.8 07-Apr-11 19:12:00 169.4 58.17 5.58 8.00 2061664 45.4 07-Apr-11 19:14:00 170.2 57.90 5.41 7.78 2088017 56.8 07-Apr-11 19:16:00 171.3 58.08 5.24 7.78 2093920 55.4 07-Apr-11 19:18:00 173.7 57.34 5.27 7.69 2096864 54.0 07-Apr-11 19:20:00 172.1 56.73 5.57 8.00 2082125 52.7 07-Apr-11 19:22:00 171.4 55.87 5.72 8.05 2055186 52.3 07-Apr-11 19:24:00 169.1 56.68 5.69 8.39 2036019 52.7 07-Apr-11 19:26:00 169.4 57.88 5.50 7.94 2034112 0.0 07-Apr-11 19:28:00 169.8 58.30 5.40 7.97 2062400 57.0 07-Apr-11 19:30:00 171.0 57.73 5.40 7.91 2095069 56.4 07-Apr-11 19:32:00 172.0 57.56 5.50 7.88 2101408 55.8 07-Apr-11 19:34:00 172.9 57.38 5.64 8.04 2091141 55.3 07-Apr-11 19:36:00 172.2 57.21 5.61 8.14 2080095 54.7 07-Apr-11 19:38:00 170.9 56.87 5.66 19.34 2074921 53.2 07-Apr-11 19:40:00 168.9 56.73 5.91 8.16 2054752 12.4 07-Apr-11 19:42:00 169.5 57.88 5.44 8.17 2052970 43.9 07-Apr-11 19:44:00 170.2 57.73 5.29 7.82 2078390 57.2 07-Apr-11 19:46:00 171.8 57.58 5.39 8.17 2101069 58.5 07-Apr-11 19:48:00 172.6 57.43 5.39 7.82 2074656 59.8 07-Apr-11 19:50:00 172.2 57.25 5.71 8.21 2076435 61.1 07-Apr-11 19:52:00 170.7 57.49 5.62 8.08 2058058 59.7 07-Apr-11 19:54:00 169.3 57.72 5.61 8.32 2050028 58.8 07-Apr-11 19:56:00 169.6 57.99 5.53 7.95 2054016 0.0 07-Apr-11 19:58:00 171.0 58.21 5.28 7.87 2076944 62.6 07-Apr-11 20:00:00 170.9 58.44 5.55 8.02 2094197 63.2 07-Apr-11 20:02:00 173.1 58.07 5.36 7.94 2095151 63.7 07-Apr-11 20:04:00 171.9 56.67 5.73 8.15 2093792 64.3 07-Apr-11 20:06:00 171.7 56.93 5.63 8.03 2048672 64.8 07-Apr-11 20:08:00 169.3 57.19 5.83 17.10 2027219 63.2 07-Apr-11 20:10:00 169.4 57.43 5.48 7.98 2063673 14.4 07-Apr-11 20:12:00 169.6 57.46 5.67 7.99 2093486 54.8 07-Apr-11 20:14:00 170.1 57.49 5.43 8.05 2096677 68.6 07-Apr-11 20:16:00 172.7 57.51 5.39 7.89 2097165 67.0 07-Apr-11 20:18:00 171.9 57.54 5.61 7.97 2093056 65.5 07-Apr-11 20:20:00 171.4 57.71 5.55 8.15 2089041 63.9 07-Apr-11 20:22:00 171.2 57.89 5.50 8.00 2072622 62.1 07-Apr-11 20:24:00 169.2 58.08 5.55 8.70 2083426 60.9 07-Apr-11 20:26:00 170.2 58.18 5.48 8.02 2092822 0.0 07-Apr-11 20:28:00 170.1 57.98 5.45 8.00 2104248 64.2 07-Apr-11 20:30:00 170.9 57.79 5.45 7.92 2083805 63.8 07-Apr-11 20:32:00 172.5 57.49 5.62 7.74 2090688 63.4 07-Apr-11 20:34:00 172.5 57.05 5.51 8.12 2097896 63.1 07-Apr-11 20:36:00 170.8 57.10 5.64 8.10 2069312 62.7 07-Apr-11 20:38:00 170.1 57.38 5.65 14.67 2031331 57.4 07-Apr-11 20:40:00 169.6 57.92 5.67 8.00 2040361 13.5 07-Apr-11 20:42:00 169.9 58.16 5.44 7.81 2081835 45.1 07-Apr-11 20:44:00 170.4 58.02 5.56 7.93 2112652 58.6 07-Apr-11 20:46:00 170.5 57.88 5.64 7.96 2109957 58.9 07-Apr-11 20:48:00 172.9 57.74 5.50 7.80 2112292 59.2 07-Apr-11 20:50:00 172.8 57.53 5.69 8.01 2105783 59.4 07-Apr-11 20:52:00 171.7 56.91 5.64 7.95 2092251 59.7 07-Apr-11 20:54:00 171.5 57.13 5.47 8.88 2057040 56.8 07-Apr-11 20:56:00 169.6 57.34 5.53 7.96 2041722 0.007-Apr-11 20:58:00 169.4 57.77 5.61 8.02 2044436 54.6 07-Apr-11 21:00:00 170.5 58.10 5.53 7.76 2084794 55.0 07-Apr-11 21:02:00 170.6 57.97 5.53 8.04 2098458 55.4 07-Apr-11 21:04:00 172.9 57.85 5.58 8.03 2095562 55.9 07-Apr-11 21:06:00 172.1 57.73 5.72 8.01 2096096 56.3 07-Apr-11 21:08:00 170.9 57.60 5.60 11.14 2080216 54.9 07-Apr-11 21:10:00 170.2 57.76 5.65 8.07 2066081 14.6 07-Apr-11 21:12:00 169.6 57.99 5.77 8.14 2054016 45.2 07-Apr-11 21:14:00 168.9 58.27 5.48 8.01 2056971 57.1 07-Apr-11 21:16:00 169.5 58.61 5.49 8.02 2083104 57.5 07-Apr-11 21:18:00 170.8 58.68 5.58 7.90 2091632 57.9 07-Apr-11 21:20:00 171.4 58.40 5.40 7.79 2095412 58.3 07-Apr-11 21:22:00 172.1 58.06 5.79 7.98 2101134 59.5 07-Apr-11 21:24:00 172.1 57.62 5.43 8.95 2078464 57.5 07-Apr-11 21:26:00 171.4 57.75 5.58 8.03 2066823 0.0 07-Apr-11 21:28:00 170.3 58.01 5.76 8.06 2056253 59.7 07-Apr-11 21:30:00 169.8 58.69 5.57 7.93 2050871 58.5 07-Apr-11 21:32:00 169.0 58.68 5.38 7.85 2089683 57.3 07-Apr-11 21:34:00 170.3 58.53 5.64 8.02 2099059 56.0 07-Apr-11 21:36:00 170.9 58.38 5.40 7.83 2101769 54.8 07-Apr-11 21:38:00 172.9 57.43 5.82 11.04 2089535 56.0 07-Apr-11 21:40:00 172.2 57.67 5.56 8.22 2072202 14.1 07-Apr-11 21:42:00 169.1 57.92 5.71 8.02 2045891 46.7 07-Apr-11 21:44:00 169.6 58.54 5.52 7.85 2046231 59.0 07-Apr-11 21:46:00 170.0 59.32 5.42 7.92 2092692 58.3 07-Apr-11 21:48:00 171.3 59.10 5.41 7.76 2115277 57.6 07-Apr-11 21:50:00 172.7 58.87 5.43 7.77 2102274 56.8 07-Apr-11 21:52:00 172.1 58.73 5.62 7.97 2113134 56.9 07-Apr-11 21:54:00 171.1 58.80 5.63 9.12 2096927 54.3 07-Apr-11 21:56:00 169.7 58.87 5.54 8.16 2063247 0.0 07-Apr-11 21:58:00 169.7 58.94 5.45 7.89 2061796 55.6 07-Apr-11 22:00:00 169.4 59.02 5.75 8.15 2090173 55.0 07-Apr-11 22:02:00 170.1 59.01 5.64 8.02 2102665 54.4 07-Apr-11 22:04:00 172.1 58.78 5.64 8.07 2125888 53.8 07-Apr-11 22:06:00 172.2 58.55 5.68 8.02 2119808 53.2 07-Apr-11 22:08:00 171.3 58.57 5.73 10.60 2104183 52.1 07-Apr-11 22:10:00 170.6 58.74 5.72 8.17 2071616 12.3 07-Apr-11 22:12:00 168.7 58.91 5.57 8.06 2057088 39.6 07-Apr-11 22:14:00 169.1 59.18 5.58 7.99 2053280 51.1 07-Apr-11 22:16:00 170.4 59.65 5.50 7.85 2096548 51.0 07-Apr-11 22:18:00 170.8 59.41 5.43 7.98 2114554 51.0 07-Apr-11 22:20:00 172.3 59.17 5.58 8.02 2124263 50.9 07-Apr-11 22:22:00 171.2 58.82 5.71 8.22 2121173 51.1 07-Apr-11 22:24:00 170.6 58.47 5.52 9.58 2068255 48.7 07-Apr-11 22:26:00 170.2 58.61 5.57 7.92 2054240 0.0 07-Apr-11 22:28:00 168.8 58.79 5.50 8.06 2056199 52.1 07-Apr-11 22:30:00 168.7 58.96 5.48 7.89 2065108 52.3 07-Apr-11 22:32:00 169.2 59.64 5.47 7.95 2099919 52.5 07-Apr-11 22:34:00 171.2 59.41 5.47 7.89 2120414 52.8 07-Apr-11 22:36:00 172.8 59.08 5.40 7.87 2121397 53.0 07-Apr-11 22:38:00 170.8 59.16 5.59 8.11 2105501 51.6 07-Apr-11 22:40:00 170.5 59.25 5.53 8.07 2073578 10.9 07-Apr-11 22:42:00 169.8 59.34 5.72 8.03 2063968 40.0 07-Apr-11 22:44:00 170.1 59.43 5.53 7.99 2073662 52.3 07-Apr-11 22:46:00 168.6 59.57 5.65 8.15 2087828 52.9 07-Apr-11 22:48:00 169.6 59.52 5.42 8.00 2109133 53.5 07-Apr-11 22:50:00 170.5 59.41 5.47 7.98 2121637 54.0 07-Apr-11 22:52:00 172.9 59.31 5.46 7.82 2104503 53.1 07-Apr-11 22:54:00 171.8 59.21 5.47 10.11 2093489 53.5 07-Apr-11 22:56:00 171.6 59.14 5.71 8.12 2107047 0.007-Apr-11 22:58:00 170.8 59.28 5.70 8.24 2103697 60.0 07-Apr-11 23:00:00 170.6 59.41 5.62 7.94 2092041 58.5 07-Apr-11 23:02:00 169.4 59.55 5.64 8.20 2094216 57.0 07-Apr-11 23:04:00 169.1 59.69 5.66 8.13 2080124 55.5 07-Apr-11 23:06:00 169.6 60.35 5.63 8.07 2103023 54.0 07-Apr-11 23:08:00 170.9 60.12 5.34 13.70 2118208 55.0 07-Apr-11 23:10:00 173.7 59.82 5.40 7.90 2129552 15.7 07-Apr-11 23:12:00 171.6 58.55 5.73 8.03 2103621 49.0 07-Apr-11 23:14:00 171.1 58.87 5.53 7.98 2060028 61.0 07-Apr-11 23:16:00 169.9 59.20 5.59 8.11 2041098 58.5 07-Apr-11 23:18:00 169.5 59.46 5.66 8.18 2078277 56.1 07-Apr-11 23:20:00 168.5 59.71 5.69 8.13 2080800 53.7 07-Apr-11 23:22:00 170.4 60.32 5.53 7.98 2102753 51.7 07-Apr-11 23:24:00 171.1 60.12 5.53 11.29 2126240 53.8 07-Apr-11 23:26:00 172.0 59.92 5.52 8.00 2133005 0.0 07-Apr-11 23:28:00 172.1 59.55 5.64 8.11 2133027 62.3 07-Apr-11 23:30:00 171.4 59.18 5.71 8.10 2111360 60.7Unit1Unit1NetMWRelativeFuelFlowBoilerExit%O2Stack%O2KSCFHppmSO2netBTU/KWHStartTimeEndTime1GJ5NETMWATT1FFVTOTLFUELFL1aAVSELO21RAVO2PERCENT1RAVSTKGASFLOW1RAVSO2PPM1MIN1PA5HRA14‐Jun‐1110:00:0014‐Jun‐1111:00:00170.256.52.357.621,924,69142.710889.914‐Jun‐1111:00:0014‐Jun‐1112:00:00170.155.62.307.601,911,79915.510816.114‐Jun‐1112:00:0014‐Jun‐1113:00:00170.455.42.317.571,914,66049.910813.814‐Jun‐1113:00:0014‐Jun‐1114:00:00170.455.32.297.601,922,32736.410790.714‐Jun‐1114:00:0014‐Jun‐1115:00:00170.855.12.307.591,930,47141.410760.314‐Jun‐1115:00:0014‐Jun‐1116:00:00170.555.32.327.711,929,64938.610803.414‐Jun‐1116:00:0014‐Jun‐1117:00:00170.455.42.297.631,927,27939.010874.714‐Jun‐1117:00:0014‐Jun‐1118:00:00170.755.12.307.601,920,29038.010878.7Unit5Unit5NetMWRelativeFuelFlowBoilerExit%O2Stack%O2KSCFMppmSO2netBTU/KWHStartTimeEndTime5GJ5NETMW5FFXFUELFLOW5AAVO2NET90AVG5RAVWETO2VAL5RAVAVGFLOW5RAVSO2PPM1MIN5PA5HRA30‐Sep‐1109:00:0030‐Sep‐1110:00:00787.468.92.505.251,870.4240.09554.130‐Sep‐1110:00:0030‐Sep‐1111:00:00787.668.62.485.931,874.3152.19553.430‐Sep‐1111:00:0030‐Sep‐1112:00:00786.868.82.525.961,875.1149.59574.830‐Sep‐1112:00:0030‐Sep‐1113:00:00787.269.02.505.911,879.1446.99567.830‐Sep‐1113:00:0030‐Sep‐1114:00:00787.569.22.515.571,882.4840.49568.530‐Sep‐1114:00:0030‐Sep‐1115:00:00788.369.32.495.901,886.5346.79564.930‐Sep‐1115:00:0030‐Sep‐1116:00:00787.569.22.505.911,903.5246.59577.830‐Sep‐1116:00:0030‐Sep‐1117:00:00787.768.82.495.901,908.8845.59569.9

## APPENDIX G – LABORATORY ANALYSES DATA

# A NALYTICAL 

# R EPORT

C LIENT 

## : TRC E NVIRONMENTAL 

## , I NC



## . P ROJECT 

## :



# A NALYTICAL 

# S ERVICES 

# P ROVIDED 

# :



## SO3

(EPA M ETHOD 

### 8A)

Confirmation of Data Review:

To the best of my knowledge th is analytical data has been ch ecked thoroughly for completeness and the results presented are accurate, error-fr ee, legible, and have been performed and validated in accordance with the approved method(s).



## Date of Review: April 21, 2011

J. Bruce Nemet Quality Assurance Officer 178050: APS

### Client:
RFA #: Analysis:

H 2 

### O Blank < 0.089

UNIT 5 RUN 1 < 0.055 UNIT 5 RUN 2 < 0.057 UNIT 5 RUN 3 0.154

UNIT 4 RUN 1 0.080 UNIT 4 RUN 2 0.097 UNIT 4 RUN 3 < 0.065

UNIT 3 RUN 1 < 0.047 UNIT 3 RUN 2 < 0.049 UNIT 3 RUN 3 < 0.070

UNIT 2 RUN 1 0.080 UNIT 2 RUN 2 0.057 UNIT 2 RUN 3 0.074

Sample ID EPA Method 8A 178050 TRC, Inc

SO 3 

## Analyte(s) (mg) 

# Report Summary

* EPA Audits are reported in mg/DSCM SO2

### Client: RFA #: 178050 Date Received: 4/12/2011 Date Analyzed: 4/20/2011 Analyst: TCS Analysis: EPA Method 8A Analyte(s): SO3

Dionex ICS-2100 ion chromatogragh 25μl injection volume IonPac AS18 4x250mm Flow rate: 1.05 mls/min Eluent: 32mM KOH Temp: 30° C Suppressor current: 85 mA

0.887 mg/L SO 3



### Miscellaneous Comments Regarding Sample Analysis: (Note unusual catch weights, interferences, odd sample behavior, and steps taken to confirm unusual results. Also note any deviations from standard analytical procedures, together with justification and possible affect on results. Specify samples when applicable.) None See analytical data sheets for results of internal calibr ation verification standard results. All internal QC results within ±10 % limits.

See Analytical data sheets for results of sample spike analyses. All spik e results within 90% - 110% limits. Summary of Instrumentation:

Limits Of Quantification:

Summary Of QA Audit Sample Analysis:

Summary Sample Spike Analysis: TRC, Inc

DI H2O Impinger contents and rinses.

Samples were final volumed in the laboratory prior to analysis by ion chromatograghy. See data for dilution factors used in analysis. 

# Analytical Narrative

Sample Matrix & Components:

Summary of Sample Prep:Client: TRC, Inc
RFA #: 178050 Analysis: EPA Method 8A



## SO 3 

## Analytical Data Sheet

Standard Manufacturer: AccuSpec m 2 : -6.49E-05 R 2 : 0.9999827
Lot ID: SC8350362 m 1 :
b: -9.61E-03
SO4 - % Difference
Conc. Average % SO4 - from (mg/L) Inj. 1 Inj. 2 Area Diff. (mg/L) Actual

1.00 0.2466 0.2518 0.2492 2.09% 1.06 6.46% 5.00 1.1894 1.1950 1.1922 0.47% 4.95 -1.03% 10.0 2.4012 2.3964 2.3988 0.20% 9.93 -0.70% 20.0 4.8279 4.8615 4.8447 0.69% 20.1 0.35% 40.0 9.5492 9.6726 9.6109 1.28% 40.0 -0.03%

Standard Manufacturer: AccuSpec Lot ID: SC8350362 Average % Expected SO4 - Actual SO4 - % Inj. 1 Inj. 2 Area Diff. (mg/L) (mg/L) Diff.

ICV Standard 2.3994 2.4140 2.4067 0.61% 10.0 10.0 -0.37%

Average % Spike SO4 - Sample SO4 Calc. SO4 - % Sample I.D. Inj. 1 Inj. 2 Area Diff. (mg/L) (mg/L) (mg/L) Recovery

UNIT 2 RUN 3 1.3619 1.3608 1.3614 0.08% 5.65 1.42 5.71 98.9% Note: 1.0 mls of the above sample was spiked with 1.0 mls of a 10.0 ppm sulfate standard.

Sample SO 3 SAMPLE Inj. 1 Inj. 2 Average % Dilution SO4 - Volume Catch ID Area Area ND Area Diff. Factor ND (mg/L) (ml) ND (mg)

H2O Blank 0.0375 0.0373 < 0.2492 NA 1 < 1.065 100 < 0.089

UNIT 5 RUN 1 0.1365 0.1440 < 0.2492 NA 1 < 1.065 62 < 0.055 UNIT 5 RUN 2 0.2281 0.2501 < 0.2492 NA 1 < 1.065 64 < 0.057 UNIT 5 RUN 3 0.7239 0.7084 0.7162 2.16% 1 2.987 62 0.154

UNIT 4 RUN 1 0.3551 0.3542 0.3547 0.25% 1 1.498 64 0.080 UNIT 4 RUN 2 0.4973 0.4929 0.4951 0.89% 1 2.077 56 0.097 UNIT 4 RUN 3 0.2493 0.2455 < 0.2492 NA 1 < 1.065 73 < 0.065

UNIT 3 RUN 1 0.1739 0.1756 < 0.2492 NA 1 < 1.065 53 < 0.047 UNIT 3 RUN 2 0.1015 0.2351 < 0.2492 NA 1 < 1.065 55 < 0.049 UNIT 3 RUN 3 0.1894 0.1908 < 0.2492 NA 1 < 1.065 79 < 0.070

UNIT 2 RUN 1 0.3296 0.3300 0.3298 0.12% 1 1.396 69 0.080 UNIT 2 RUN 2 0.2752 0.2689 0.2721 2.32% 1 1.159 59 0.057 UNIT 2 RUN 3 0.3321 0.3379 0.3350 1.73% 1 1.418 63 0.074 

### Field Samples SO 4 

### Standard Calibration Curve

2.43E-01

Standard Areas



### Internal Calibration Verification

Matrix Spike

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 1 10 PPM AUDIT a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 15:15 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 1 4.10 Sulfate 18.001 2.3994

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -2.0 5.0 10.0 15.0 20.0 25.0 30.0 SO4 32mM #1 10 PPM AUDIT a ECD_1 μS

min1 - Sulfate - 4.103

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 2 DI H2O a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/21/2011 11:33 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 0.224 0.0375 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.200 -0.100 0.000 0.100 0.200 0.300 0.400 0.500 SO4 32mM #2 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.110

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 3 DI H2O b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/21/2011 11:42 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.10 Sulfate 0.262 0.0373 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.200 -0.100 0.000 0.100 0.200 0.300 0.400 0.500 SO4 32mM #3 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.100

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 4 U5-1 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 15:41 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.013 0.1365

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.60 -0.00 0.50 1.00 1.60 SO4 32mM #4 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 5 U5-1 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 15:51 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.069 0.1440

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.40 0.00 0.50 1.00 1.50 1.80 SO4 32mM #5 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 6 U5-2 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 16:01 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.716 0.2281

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.40 0.50 1.00 1.50 2.00 2.50 3.00 SO4 32mM #6 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 7 U5-2 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 16:10 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.886 0.2501

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 -0.00 0.50 1.00 1.50 2.00 2.50 3.00 SO4 32mM #7 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 8 U5-3 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 16:20 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 5.436 0.7239 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.0 2.0 4.0 6.0 9.0 SO4 32mM #8 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 9 U5-3 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 16:30 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.10 Sulfate 5.333 0.7084

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.00 1.25 2.50 3.75 5.00 6.25 8.00 SO4 32mM #9 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.103

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 10 U4-1 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 16:40 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 2.706 0.3551

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.00 2.00 3.00 4.50 SO4 32mM #10 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 11 U4-1 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 16:49 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.10 Sulfate 2.666 0.3542

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.00 2.00 3.00 4.00 SO4 32mM #11 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.103

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 12 U4-2 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 16:59 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 3.747 0.4973

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.00 2.00 3.00 4.00 5.00 6.00 SO4 32mM #12 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 13 U4-2 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 17:09 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 3.708 0.4929

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.00 2.00 3.00 4.00 5.00 6.00 SO4 32mM #13 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 14 U4-3 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 17:19 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.877 0.2493

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 -0.00 0.50 1.00 1.50 2.00 2.50 3.00 SO4 32mM #14 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 15 U4-3 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 17:29 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.855 0.2455

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 -0.00 0.50 1.00 1.50 2.00 2.50 3.00 SO4 32mM #15 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 16 U3-1 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 17:38 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.109 0.1739

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 0.50 1.00 1.50 1.80 SO4 32mM #16 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 17 U3-1 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 17:48 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.106 0.1756

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 0.50 1.00 1.50 1.80 SO4 32mM #17 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 18 U3-2 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 17:58 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.10 Sulfate 0.746 0.1015

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 -0.00 0.20 0.40 0.60 0.80 1.00 1.20 SO4 32mM #18 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.103

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 19 U3-2 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 18:08 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.704 0.2351

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 0.50 1.00 1.50 2.00 2.50 3.00 SO4 32mM #19 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.110

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 20 U3-3 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 18:18 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.316 0.1894

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 0.50 1.00 1.50 2.00 SO4 32mM #20 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.113

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 21 U3-3 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 18:27 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.318 0.1908

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 0.50 1.00 1.50 2.00 SO4 32mM #21 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 22 U2-1 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 18:37 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 2.324 0.3296

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 0.00 1.00 2.00 3.00 3.50 SO4 32mM #22 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.113

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 23 U2-1 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 18:47 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 2.324 0.3300

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 0.00 1.00 2.00 3.00 3.50 SO4 32mM #23 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 24 U2-2 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 18:57 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.992 0.2752

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 0.00 1.00 2.00 3.00 3.50 SO4 32mM #24 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:04 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 25 U2-2 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 19:06 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 1.954 0.2689

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 -0.00 0.50 1.00 1.50 2.00 2.50 3.00 SO4 32mM #25 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:05 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 26 U2-3 a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 19:16 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 2.269 0.3321

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 0.00 1.00 2.00 3.00 3.50 SO4 32mM #26 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:05 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 27 U2-3 b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 19:26 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 2.258 0.3379

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 0.00 1.00 2.00 3.00 3.50 SO4 32mM #27 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.107

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:05 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 28 SO3 MATRIX a

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 19:36 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.11 Sulfate 10.138 1.3619

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -2.0 2.5 5.0 7.5 10.0 12.5 16.0 SO4 32mM #28 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.110

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:05 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 29 SO3 MATRIX b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/20/2011 19:45 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 2 4.10 Sulfate 10.188 1.3608

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -2.0 2.5 5.0 7.5 10.0 12.5 16.0 SO4 32mM #29 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 4.103

### Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 4/21/2011 12:05 PM

Ilya-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 30 10 PPM AUDIT b

Sequence 

## ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor T y

pe: ASRS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartrid g e: EluGen-OH
Recording Time: 04/21/2011 11:52 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Hei g ht Area min μS μS*min 1 4.09 Sulfate 17.752 2.4140

0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -2.0 5.0 10.0 15.0 20.0 25.0 30.0 SO4 32mM #30 10 PPM AUDIT b ECD_1 μS

min1 - Sulfate - 4.093

# A NALYTICAL 

# R EPORT

C LIENT 

## : TRC E NVIRONMENTAL 

## , I NC



## . P ROJECT 

## :



# A NALYTICAL 

# S ERVICES 

# P ROVIDED 

# :

• 

## SO 3



### (EPA M ETHOD 

### 8)

Confirmation of Data Review:

To the best of my knowledge this analytical data has been checked thoroughly for completeness and the results presented are accurate, error-free, legible, and have been performed and validated in accordance with th e approved method(s).



## Date of Review: August 22, 2011

J. Bruce Nemet Quality Assurance Officer 182068: APS Four Corners

### Client:
RFA #: Analysis:

U1-RUN 1 0.089 U1-RUN 2 0.065 U1-RUN 3 < 0.051 Sample ID EPA Method 8A 182068: APS TRC, Inc.

SO 3 

## Analyte(s) (mg) 

# Report Summary

* EPA Audits are reported in mg/DSCM SO2

### Client: RFA #: 182068: APS Date Received: 8/19/2011 Date Analyzed: 8/19/2011 Analyst: TCS Analysis: EPA Method 8A Analyte(s): SO3

Dionex ICS-2100 ion chromatogragh 25μl injection volume IonPac AS18 4x250mm Flow rate: 1.05 mls/min Eluent: 32mM KOH Temp: 30° C Suppressor current: 85 mA

0.887 mg/L SO 3



### Miscellaneous Comments Regarding Sample Analysis: (Note unusual catch weights, interferences, odd sample behavior, and steps taken to confirm unusual results. Also note any deviations from standard analytical procedures, together with justification and possible affect on results. Specify samples when applicable.)

None See analytical data sheets for results of internal calibration verification standard results. All internal QC results within ±10 % limits.

See Analytical data sheets for results of sample spike analyses. All spike results within 90% - 110% limits. Summary of Instrumentation:

Limits Of Quantification:

Summary Of QA Audit Sample Analysis:

Summary Sample Spike Analysis: TRC, Inc.

H 2 

### O impinger contents and rinses

Samples were final volumed in the laboratory prior to analysis by ion chromatograghy. See data for dilution factors used in analysis. 

# Analytical Narrative

Sample Matrix & Components:

Summary of Sample Prep:Client: TRC, Inc.
RFA #: 182068: APS Analysis: EPA Method 8A



## SO 3 

## Analytical Data Sheet

Standard Manufacturer: AccuSpec m 2 : -6.49E-05 R 2 : 0.9999827

Lot ID: SC8350362 m 1 :
b: -9.61E-03
SO4 - % Difference
Conc. Average % SO4 - from (mg/L) Inj. 1 Inj. 2 Area Diff. (mg/L) Actual

1.00 0.2466 0.2518 0.2492 2.09% 1.06 6.46% 5.00 1.1894 1.1950 1.1922 0.47% 4.95 -1.03% 10.0 2.4012 2.3964 2.3988 0.20% 9.93 -0.70% 20.0 4.8279 4.8615 4.8447 0.69% 20.1 0.35% 40.0 9.5492 9.6726 9.6109 1.28% 40.0 -0.03%

Standard Manufacturer: AccuSpec

Lot ID: SC8350362 Average % Expected SO4 - Actual SO4 - %

Inj. 1 Inj. 2 Area Diff. (mg/L) (mg/L) Diff.

ICV Standard 2.4715 2.4850 2.4783 0.54% 10.0 10.3 2.59%

Average % Spike SO4 - Sample SO4 - Calc. SO4 - % Sample I.D. Inj. 1 Inj. 2 Area Diff. (mg/L) (mg/L) (mg/L) Recovery

U1-RUN 3 1.3788 1.3794 1.3791 0.04% 5.7 1.06 5.5 103.4%

Note: 1.0 mls of the above sample was spiked with

1.0 mls of a 10.0 ppm sulfate standard.

Sample SO 3 SAMPLE Inj. 1 Inj. 2 Average % Dilution SO4 - Volume Catch ID Area Area ND Area Diff. Factor ND (mg/L) (ml) ND (mg) 

### Field Samples SO 4 

### Standard Calibration Curve

2.43E-01

Standard Areas



### Internal Calibration Verification

Matrix Spike

U1-RUN 1 0.3634 0.3505 0.3570 3.61% 1 1.508 71 0.089 U1-RUN 2 0.2945 0.2888 0.2917 1.95% 1 1.239 63 0.065 U1-RUN 3 0.2389 0.2381 < 0.2492 NA 1 < 1.065 58 < 0.051

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 1 10 PPM A UDIT a

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 10:11 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 1 3.54 Sulfate 18.017 2.4715 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -2.0 5.0 10.0 15.0 20.0 25.0 30.0 SO4 32mM #1 10 PPM AUDIT a ECD_1 μS

min1 - Sulfate - 3.543

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 2 RUN 1 a

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 10:21 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.55 Sulfate 2.237 0.3634 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 0.00 1.00 2.00 3.00 3.50 SO4 32mM #2 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.550

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 3 RUN 1 b

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 10:31 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.55 Sulfate 2.148 0.3505 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 0.00 1.00 2.00 3.00 3.50 SO4 32mM #3 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.550

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 4 RUN 2 a

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 10:37 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.55 Sulfate 1.812 0.2945 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 0.50 1.00 1.50 2.00 2.50 3.00 SO4 32mM #4 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.553

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 5 RUN 2 b

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 10:44 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.55 Sulfate 1.796 0.2888 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 0.50 1.00 1.50 2.00 2.50 3.00 SO4 32mM #5 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.553

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 6 RUN 3 a

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 10:51 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.55 Sulfate 1.406 0.2389 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 0.50 1.00 1.50 2.00 2.50 SO4 32mM #6 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.553

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 7 RUN 3 b

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 10:58 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.55 Sulfate 1.398 0.2381 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.20 0.50 1.00 1.50 2.00 2.50 SO4 32mM #7 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.550

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 8 SO2 MA TRIX a

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 11:04 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.55 Sulfate 9.768 1.3788 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.0 2.5 5.0 7.5 10.0 12.5 16.0 SO4 32mM #8 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.550

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 9 SO2 MA TRIX b

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 11:11 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.55 Sulfate 9.866 1.3794 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.0 2.5 5.0 7.5 10.0 12.5 16.0 SO4 32mM #9 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.550

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 8/19/2011 11:25 AM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 10 10 PPM A UDIT b

Sequence 

## ICS2000\Methods\Sulfate

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 08/19/2011 11:18 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 1 3.55 Sulfate 18.006 2.4850 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -2.0 5.0 10.0 15.0 20.0 25.0 30.0 SO4 32mM #10 [modified by Resolution Analytics] ECD_1 μS

min1 - Sulfate - 3.550

# A NALYTICAL 

# R EPORT

C LIENT 

## : TRC E NVIRONMENTAL 

## , I NC



## . P ROJECT 

## :



# A NALYTICAL 

# S ERVICES 

# P ROVIDED 

# :

• 

## SO 3



### (EPA M ETHOD 

### 8)

Confirmation of Data Review:

To the best of my knowledge this analytical data has been checked thoroughly for completeness and the results presented are accurate, error-free, legible, and have been performed and validated in accordance with th e approved method(s).



## Date of Review: October 19, 2011

J. Bruce Nemet Quality Assurance Officer 182068: APS Four Corners

### Client:
RFA #: Analysis:

U5.R1.APH IN 3.899 U5.R2.APH IN 3.179 U5.R3.APH IN 4.065

U5.R1.APH OUT 0.423 U5.R2.APH OUT 0.330 U5.R3.APH OUT 0.242

U5.R1.Stack 0.362 U5.R2.Stack 0.251 U5.R3.Stack 0.198 Sample ID EPA Method 8A 182068 TRC, Inc.

SO 3 

## Analyte(s) (mg) 

# Report Summary

* EPA Audits are reported in mg/DSCM SO2

### Client: RFA #: 182068 Date Received: 10/11/2011 Date Analyzed: 10/18/2011 Analyst: TCS Analysis: EPA Method 8A Analyte(s): SO3

Dionex ICS-2100 ion chromatogragh 25μl injection volume IonPac AS18 4x250mm Flow rate: 1.05 mls/min Eluent: 32mM KOH Temp: 30° C Suppressor current: 85 mA

0.420 mg/L SO 3



### Miscellaneous Comments Regarding Sample Analysis: (Note unusual catch weights, interferences, odd sample behavior, and steps taken to confirm unusual results. Also note any deviations from standard analytical procedures, together with justification and possible affect on results. Specify samples when applicable.)

None See analytical data sheets for results of internal calibration verification standard results. All internal QC results within ±10 % limits.

See Analytical data sheets for results of sample spike analyses. All spike results within 90% - 110% limits. Summary of Instrumentation:

Limits Of Quantification:

Summary Of QA Audit Sample Analysis:

Summary Sample Spike Analysis: TRC, Inc.

H 2 

### O impinger contents and rinses

Samples were final volumed in the laboratory prior to analysis by ion chromatograghy. See data for dilution factors used in analysis. 

# Analytical Narrative

Sample Matrix & Components:

Summary of Sample Prep:Client: TRC, Inc.
RFA #: 182068 Analysis: EPA Method 8A



## SO 3 

## Analytical Data Sheet

Standard Manufacturer: Ultra m 2 : 2.07E-04 R 2 : 0.9999931

Lot ID: L00282 m 1 :
b: 1.02E-02
SO4 - % Difference
Conc. Average % SO4 - from (mg/L) Inj. 1 Inj. 2 Area Diff. (mg/L) Actual

0.500 0.1330 0.1281 0.1306 3.75% 0.504 0.74% 1.00 0.2612 0.2602 0.2607 0.38% 1.05 4.79% 5.00 1.1884 1.1958 1.1921 0.62% 4.93 -1.45% 20.0 4.8745 4.8780 4.8763 0.07% 20.0 0.13% 40.0 9.8562 9.9306 9.8934 0.75% 40.0 -0.01%

Standard Manufacturer: AccuStandard

Lot ID: 211055138 Average % Expected SO4 - Actual SO4 - %

Inj. 1 Inj. 2 Area Diff. (mg/L) (mg/L) Diff.

ICV Standard 2.3058 2.3366 2.3212 1.33% 10.0 9.60 -4.04%

Average % Spike SO4 - Sample SO4 - Calc. SO4 - % Sample I.D. Inj. 1 Inj. 2 Area Diff. (mg/L) (mg/L) (mg/L) Recovery

U5.R3.Stack 1.4498 1.4620 1.4559 0.84% 6.0 2.43 6.2 96.9%

Note: 1.0 mls of the above sample was spiked with

1.0 mls of a 10.0 ppm sulfate standard.

Sample SO 3 SAMPLE Inj. 1 Inj. 2 Average % Dilution SO4 - Volume Catch ID Area Area ND Area Diff. Factor ND (mg/L) (ml) ND (mg) 

### Field Samples SO 4 

### Standard Calibration Curve

2.39E-01

Standard Areas



### Internal Calibration Verification

Matrix Spike

U5.R1.APH IN 6.3498 6.5131 6.4315 2.54% 2 26.287 89 3.90 U5.R2.APH IN 5.1776 5.1515 5.1646 0.51% 2 21.192 90 3.18 U5.R3.APH IN 6.1160 6.0493 6.0827 1.10% 2 24.888 98 4.07

U5.R1.APH OUT 1.3143 1.2995 1.3069 1.13% 1 5.404 94 0.423 U5.R2.APH OUT 0.9623 0.9535 0.9579 0.92% 1 3.954 100 0.330 U5.R3.APH OUT 0.8909 0.9130 0.9020 2.45% 1 3.722 78 0.242

U5.R1.Stack 1.2604 1.2734 1.2669 1.03% 1 5.238 83 0.362 U5.R2.Stack 0.8584 0.8626 0.8605 0.49% 1 3.549 85 0.251 U5.R3.Stack 0.5866 0.5949 0.5908 1.40% 1 2.426 98 0.198

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 1 10 PPM A UDIT a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 10:00 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 1 3.43 Sulfate 13.315 2.3058 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -2.0 5.0 10.0 15.0 20.0 SO4 32mM #1 [modified by Resolution Analytics] ECD_1 μS

min1 - Sulfate - 3.427

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 2 AP H IN 1 a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 10:22 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 38.843 6.3498 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -5.0 10.0 20.0 30.0 40.0 50.0 60.0 SO4 32mM #2 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.430

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 3 AP H IN 1 b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 10:30 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 1 3.42 Sulfate 40.422 6.5131 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -5.0 10.0 20.0 30.0 40.0 50.0 60.0 SO4 32mM #3 [modified by Resolution Analytics] ECD_1 μS

min1 - Sulfate - 3.420

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 4 AP H IN 2 a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 10:38 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 31.295 5.1776 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -5.0 10.0 20.0 30.0 40.0 50.0 SO4 32mM #4 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.430

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 5 AP H IN 2 b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 10:46 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.42 Sulfate 31.071 5.1515 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -5.0 10.0 20.0 30.0 40.0 50.0 SO4 32mM #5 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.423

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 6 AP H IN 3 a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 10:53 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.42 Sulfate 37.152 6.1160 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -5.0 10.0 20.0 30.0 40.0 50.0 60.0 SO4 32mM #6 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.423

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 7 AP H IN 3 b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 11:01 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.42 Sulfate 36.674 6.0493 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -5.0 10.0 20.0 30.0 40.0 50.0 60.0 SO4 32mM #7 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.423

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 8 AP H OUT 1 a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 11:09 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 7.403 1.3143 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.0 2.0 4.0 6.0 8.0 10.0 12.0 SO4 32mM #8 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.427

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 9 AP H OUT 1 b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 11:17 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 7.352 1.2995 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.0 2.0 4.0 6.0 8.0 10.0 12.0 SO4 32mM #9 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.427

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 10 AP H OUT 2 a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 11:24 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 5.350 0.9623 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.00 1.25 2.50 3.75 5.00 6.25 8.00 SO4 32mM #10 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.430

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 11 AP H OUT 2 b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 11:32 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 5.299 0.9535 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.00 1.25 2.50 3.75 5.00 6.25 8.00 SO4 32mM #11 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.430

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 12 AP H OUT 3 a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 11:40 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 4.769 0.8909 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.00 2.00 3.00 4.00 5.00 6.00 7.00 SO4 32mM #12 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.433

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 13 AP H OUT 3 b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 11:48 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 4.958 0.9130 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.25 2.50 3.75 5.00 6.25 8.00 SO4 32mM #13 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.433

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 14 STA CK 1 a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 11:55 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 7.102 1.2604 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.0 2.0 4.0 6.0 8.0 10.0 12.0 SO4 32mM #14 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.430

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 15 STA CK 1 b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 12:03 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 7.128 1.2734 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.0 2.0 4.0 6.0 8.0 10.0 12.0 SO4 32mM #15 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.433

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 16 STA CK 2 a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 12:11 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 4.692 0.8584 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.00 2.00 3.00 4.00 5.00 6.00 7.00 SO4 32mM #16 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.433

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 17 STA CK 2 b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 12:19 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 4.711 0.8626 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.00 2.00 3.00 4.00 5.00 6.00 7.00 SO4 32mM #17 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.433

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 18 STA CK 3 a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 12:26 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 3.072 0.5866 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.00 2.00 3.00 4.00 5.00 SO4 32mM #18 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.433

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 19 STA CK 3 b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 12:34 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.44 Sulfate 3.127 0.5949 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -0.50 1.00 2.00 3.00 4.00 5.00 SO4 32mM #19 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.437

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 20 SO3 MA TRIX a

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 12:42 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 7.962 1.4498 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.0 2.0 4.0 6.0 8.0 10.0 12.0 SO4 32mM #20 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.433

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 21 SO3 MA TRIX b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 12:50 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 2 3.43 Sulfate 8.015 1.4620 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -1.0 2.0 4.0 6.0 8.0 10.0 12.0 SO4 32mM #21 [modified by Resolution Analytics] ECD_1 μS

min2 - Sulfate - 3.430

### Operator:Resolution Analy tics Timebase:ics2000 Sequence:SO4 32mM Page 1-1 10/19/2011 1:34 PM

Ily a-report test3/Integration Chromeleon (c) Dionex 1996-2006 Version 6.80 SR7 Build 2528 (148369) 

# 22 10 PPM A UDIT b

Sequence 

## ICS2000\JOBS\TRC\182068

Column: IonPac A S18 4x250mm Suppressor Type: AS RS_4mm Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH
Recording Time: 10/19/2011 12:57 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height Ar ea

min μS μS*min 1 3.43 Sulfate 12.933 2.3366 0.0 2.0 4.0 6.0 8.0 10.0 12.0 15.0 -2.0 5.0 10.0 15.0 20.0 SO4 32mM #22 [modified by Resolution Analytics] ECD_1 μS

min1 - Sulfate - 3.430