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 Project 
 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 Project 

Submitted to: 

U.S. Environmental Protection Agency Region 9 

75 Hawthorne Street 

San Francisco, CA 94105 

______________________________________________________________ 

Prepared By Robert R. Hall 

______________________________________________________________ 

Reviewed By Sara J. Head, QEP, and Ellen Dietrich 
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Contents 

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

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

1.2 Environmental Impact Review ............................................................................................. 1-1

1.3 Document Overview ............................................................................................................ 1-2

1.4 Applicant Information ........................................................................................................... 1-3

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

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

2.1 Project Overview .................................................................................................................. 2-1

2.2 Process Descriptions ........................................................................................................... 2-1

2.2.1 SCR System .......................................................................................................... 2-1

2.2.2 Dry Sorbent Injection System ............................................................................... 2-5

2.3 Construction Schedule......................................................................................................... 2-8

2.4 Operating Schedule ............................................................................................................. 2-8

2.5 Standard Industrial Classification Code .............................................................................. 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 Requirements .............................................................................................................. 3-6

3.4.1 Best Available Control Technology Requirements .............................................. 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) Tailoring Rule ............................................................................ 3-11

3.7 Title V – Major Source Operating Permit .......................................................................... 3-11

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

3.9 Regional Haze Rule and Guidelines for Best Available Retrofit Technology 

Determinations ................................................................................................................... 3-12
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3.10 Other Applicable or Potentially Applicable Regulations ................................................... 3-13

3.10.1 New Source Performance Standards – 40 CFR 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 Provisions ........................................................................................... 3-15

3.10.5 Risk Management Program ................................................................................ 3-15

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

4.1 Technical Approach ............................................................................................................. 4-1

4.1.1 Best Available Control Technology Definition ...................................................... 4-1

4.1.2 Previous BACT Determinations ........................................................................... 4-2

4.2 Four Corners SCR Retrofit Project BACT Determinations ................................................. 4-3

4.2.1 STEP 1 – Available Sulfuric Acid Mist Emission Control Alternatives ................ 4-3

4.2.2 STEP 2 – Eliminate Technically Infeasible Options ............................................ 4-4

4.2.3 STEP 3 – Rank Remaining Technologies by Control Effectiveness .................. 4-9

4.2.4 STEP 4 – Evaluate Most Effective Controls and Document Results ................ 4-10

4.2.5 STEP 5 – Select the Best Available Control Technology .................................. 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 Projected Emissions.................................................................................. 5-1

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

5.3 PSD Applicability .................................................................................................................. 5-2

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

7.0 References ....................................................................................................................... 7-1
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List of Appendices 

Appendix A Emission Calculations

Appendix B RBLC Clearinghouse Data

Appendix C Units 4 & 5 – Indirect Heat Exchanger H2SO4 CAM Plan

Appendix D H2SO4 Source Test Report

List of Figures 

Figure 1-1 Four Corners Power Plant Location .................................................................................. 1-5

Figure 2-1 SCR System Simplified Schematic Drawing ..................................................................... 2-2

Figure 2-2 Typical Dry Sorbent Injection Process Schematic ............................................................ 2-6

Figure 2-3 Location of Proposed Reagent Silos and Delivery Truck Routes .................................... 2-7

Figure 4-1 FCPP Air Pollution Control Equipment Block Flow Diagram .......................................... 4-17

Figure 6-1 Deposition Area for the ESA Analysis .............................................................................. 6-2

List of Tables 

Table 3-1 National Ambient Air Quality Standards ............................................................................ 3-2

Table 3-2 PSD Significant Emissions Thresholds ............................................................................. 3-4

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

Table 3-4 Allowable PSD Increments and Significant Impact Levels (μg/m3) .................................. 3-8

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

Table 4-1 Ranking of Technically Feasible H2SO4 Mist Control Technologies ................................ 4-9

Table 4-2 Detailed Overall H2SO4 Mist Emission Control Data....................................................... 4-10

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

Table 4-4 Wet ESP Annual Costs and Cost Effectiveness ............................................................. 4-13

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

Table 5-1 Projected Future Emission Calculation for Units 4 and 5 ................................................. 5-4 
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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 reductions 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 January 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 successive 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 expected 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 application 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 PSD permit due to significant emission increases for 

sulfuric acid (H2SO4) mist. Although this Project is located on the Navajo Nation, the Navajo Nation 

does not have PSD authority, and hence this application is being submitted 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 Amendment 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 ancillary 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. 
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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) proposes 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), supply low-sulfur coal to the 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) NEPA 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 ceasing 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 operations 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 H2SO4 mist predicted to occur once SCRs are installed is part 

of the ERA for species identified for this analysis. The ERA for this Project has been completed and 

submitted to OSM in October 2013. 

Associated with the EIS process, OSM is leading the effort to comply with Section 106 of the National 

Historic Preservation Act (NHPA), which requires that 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 coordination will be concurrent with the public 

comment periods for the EIS. There are no known eligible historic buildings or other structures that 

would be affected by the installation of SCR Systems on Units 4 and 5, based on existing available 

information. APS is working with OSM and the appropriate historic preservation officers to develop a 

Programmatic Agreement that will establish a formal process for future consultation and compliance, 

and to resolve how to address potential adverse effects on eligible historic properties as appropriate. 

1.3 Document Overview 

This PSD application addresses the permitting requirements 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 processes covered by this PSD application. Section 3 

discusses the regulatory setting for the Project. Section 4 presents the emissions anticipated from the 
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operation of the facility. Section 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/BACT/LAER Clearinghouse Data 

 Appendix C – Units 4 & 5 – Indirect Heat Exchanger – H2SO4 CAM Plan 

 Appendix D – H2SO4 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 5th 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 questions on this application includes: 

 Sara Head, Permitting Lead 

 AECOM 

 (805) 233-3995 

 sara.head@aecom.com 

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Figure 1-1 Four Corners Power Plant Location 
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2.0 Project Description 

2.1 Project Overview 

This FCPP SCR Retrofit Project involves the installation 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 SO2 to SO3 which results in increased 

sulfuric acid (H2SO4) mist, PM10, and PM2.5 emissions. In order to minimize H2SO4, PM10, and PM2.5

emission increases, APS proposes to install a dry sorbent injection (DSI) system using lime as the 

sorbent. The Project will be subject to PSD rules only for H2SO4. Emission reductions from the 

shutdown of Units 1, 2, and 3 will allow the Project to net out of PSD review for PM10 and PM2.5

emissions. 

New and affected emission sources associated 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 H2SO4 emissions; 

 Truck traffic will increase due to the delivery of reagent for the dry sorbent injection system 

resulting in increased fugitive emissions from paved plant roads; 

 Truck traffic will increase due to the delivery 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 system and silo will be installed; and 

 A new pneumatic urea pellet truck 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 detail below. Note, emission reductions associated 

with decreased truck traffic and material handling related 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 technology 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 emission depending upon the amount of catalyst. The 

NOx and ammonia reagent react to form nitrogen and water vapor. The reaction mechanisms are 
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very efficient, with a reagent stoichiometry of approximately 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 + 4NH3 +O2  4N2 + 6H2O (1) 

6NO + 4NH3  5N2 + 6H2O (2) 

2NO2 + 4NH3 + O2  3N2 + 6H2O (3) 

6NO2 + 8NH3  7N2 + 12H2O (4) 

NO + NO2 + 2NH3  2N2 + 3H2O (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 decomposition reaction. Vanadium pentoxide (V2O5) is the 

main active ingredient in an SCR catalyst. It is also responsible for the unwanted conversion of SO2

to SO3. Thus, efforts to reduce the SO2 to SO3 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) 
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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 distribution devices, catalyst, catalyst support structures, 

access doors, and soot blowers. An ammonia injection grid is located upstream of the SCR reactor, 

and the system can be designed with or without a flue gas bypass. The SCR reactor is typically 

elevated above and behind the air preheater and upstream of emissions control equipment; gas flow 

direction through the reactor is typically vertically downward for coal fired applications. 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 arrangement, where 

physically possible. 

The SCR reaction occurs within the temperature range of 550° to 850° F; the extremes are highly 

dependent on the fuel quality. The practical minimum 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 start-ups and allow the SCR systems to come on-line 

sooner so that they can make the required 30-day rolling 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 run above the MOT for at least twice as long as it 

operates below the MOT to eliminate fouling that accumulated. There must be a high probability that 

the Unit will be able to complete the startup before deciding to operate below the MOT. This could 

also impair the ability for the air preheater to remove SO3. The oxidation of SO2 to SO3 could also 

require moderate air preheater modifications, since the acid dew point temperature of the flue gas is 

directly related to SO3 concentration. As the SO3 concentration increases, the acid dew point of the 

flue gas increases, potentially increasing corrosion in downstream equipment or possibly requiring an 

increase in the air preheater gas outlet temperature or the addition of some flue gas treatment system 

to remove the SO3. 

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

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

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

the selection of ammonia type does affect all other subsystem components, including reagent storage, 

vaporization, injection control, and balance-of-plant requirements. This permit application addresses 

all three reagents as APS has not made a final decision on the SCR reagent to be used. 

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

requirements predominately relate to draft, auxiliary power, soot blowing steam, gas temperature, 

controls, ductwork, reactor footprint, and air preheater. 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 compensated 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 modification, the upgrade of the auxiliary power system might 

be necessary. Auxiliary power modifications may also be necessary for ammonia supply system 

requirements. 
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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 formation 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 SO3 in the flue gas. If the acid dew 

point has been increased to more than the exhaust temperature, 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 important is the right composition of the catalyst to 

minimize SO2 to SO3 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 emissions 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 this 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 used 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 approximately 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 Project, it will be received by truck and pumped to a 

pressurized storage tank. There will not be emissions 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 miles/round trip on paved roads. 

Approximately, 1,504 trucks per year will be required 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 Project, it will be received by truck and pumped to a 

pressurized storage tank. There will not be emissions from the pressurized tank. The only air 

emission sources will be truck travel on paved roads. 
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Aqueous ammonia delivery trucks will each travel 0.36 miles/round trip on paved roads. 

Approximately, 643 trucks per year will be required to meet the SCR anhydrous ammonia demand 

which is expected to be approximately 9,970 tpy. Each truck will weigh approximately 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 shown to be effective for acid gas control. 

Performance is affected by the following 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 sorbent is hydrated lime. If a sodium based reagent 

is used, sorbent consumption would be high due to reaction with SO2. APS has a lime-based wet 

scrubber to control SO2 and does not need DSI for SO2 control. Another reason for not using sodium 

is the possible occurrence of sodium bisulfate formation with adverse impacts on the air preheater. 

Lime will enable APS to continue to sell ash which would not be possible with the use of a sodium 

based reagent. Milling is typically used to maximize the performance of sodium based sorbents, but is 

not needed for the lime-based DSI system proposed by APS. 

Reactions of hydrated lime and acid 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 H2SO4 mist emissions. 

A typical dry sorbent injection system is shown Figure 2-2. 
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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 hydrated lime. Lime will be received by truck and 

pneumatically conveyed to a storage silo. The air emission 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 travel 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 diameter and 80 feet tall, including lime transport 

equipment beneath the silo. 

Figure 2-3 shows the location of the proposed silo(s) and the routes that have been assumed for the 

delivery trucks. 
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Figure 2-3 Location of Proposed Reagent Silos and Delivery Truck Routes 
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2.3 Construction Schedule 

In order to meet regulatory requirements, construction 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 temperature 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 classifying 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. Electric Services (Fossil fuel power generation) has been assigned major 

group code “49”. To provide more detailed identification 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 this system, this facility would be classified under 221112, Fossil fuel 

electric power generation. 
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3.0 Regulatory Setting 

This section presents a review of the air quality 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 Permits, but they have not been delegated authority to 

issue PSD permits. Because PSD authority has not 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 establish 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 Retrofit Project, a 

compliance demonstration for the NAAQS is required for only those regulated pollutants that will have 

a significant net emissions increase and for which there are NAAQS. As shown in Section 3.3, the net 

changes in emissions resulting from the Project will be significant only for sulfuric acid (H2SO4) mist. 

There are no NAAQS for this pollutant. 

The area in which a project is located affects which 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 classified as in attainment if the ambient air quality concentration for 

a specific pollutant, as measured by a monitor (or, as applicable, modeling) using defined reference 

methods, is below the standard concentration level 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 criteria pollutants/NAAQS for which EPA has issued a 

designation. 
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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/m3

) 

None 

1-hour (1) 35 ppm (40 μg/m3) 

Ozone (O3) 8-hour (2) 0.075 ppm (147 μg/m3) Same as Primary 

Nitrogen Dioxide 

(NO2) 

Annual 

(Arithmetic Average) 53 ppb (3) (100 μg/m3

) Same as Primary 

1-hour (4) 100 ppb (188 μg/m3) None 

Respirable 

Particulate Matter 

(PM10) 

24-hour (5) 150 μg/m3

 Same as Primary 

Fine Particulate 

Matter (PM2.5) 

Annual (6) 

(Arithmetic Average) 12.0 μg/m3

 Annual (6) 15.0 μg/m3

24-hour (7) 35 μg/m3 Same as Primary 

Sulfur Dioxide 

(SO2) 

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/m3

 Same as Primary 

Calendar Quarter Average 1.5 μg/m3 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 NO2 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 standards 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/m3

.

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.
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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 classified as non-attainment. The PSD program applies 

to significant increases of those pollutants for which the area is classified as attainment or 

unclassifiable. The PSD program only regulates emissions from major stationary sources of regulated 

air pollutants. 

Because the FCPP is located in an attainment area, 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 major 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 emissions increase of a NSR-regulated pollutant. The PSD significant 

emission thresholds are identified in Table 3-2. 

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

Project emission increases will be significant for PM10, PM2.5 and H2SO4. 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 project 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 period 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 pollutants are shown as NA (not applicable) since the 

netting step is not required. After netting, Project emission increases will be significant only for H2SO4

mist as shown in Table 3-3. Additional details on the emissions are presented in Section 5 and 

Appendix A, and an H2SO4 Source Test Report is provided in Appendix D. 
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Table 3-2 PSD Significant Emissions Thresholds 

Pollutant Emissions Threshold 

(tons per year [tpy]) 

Nitrogen Oxides (NOx) 40 

Sulfur Dioxide (SO2) 40 

Particulate Matter (PM) Filterable 25 

PM10 15 

PM2.5 10 

Volatile Organic Compounds (VOCs) 40 

CO 100 

H2SO4 7 

Fluorides 3 

Total Reduced Sulfur 10 

Lead (Pb) 0.60 

Greenhouse Gases as Carbon Dioxide equivalents (CO2e) 75,000 

Source: 40 CFR § 52.21. 
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60221977-460 Table 3-3 Four Corners Unit 4 and Unit 5 SCR Retrofit Project PSD Applicability 

Emission Source 

Description 

NOx

(tpy) 

SO2

(tpy) 

PM 

(tpy) 

PM10

(tpy) 

PM2.5

(tpy) 

CO 

(tpy) 

VOC 

(tpy) 

H2SO

(tpy) 

Unit 4 and 5 Baseline Emissions 24,029 8,373 644.2 801.3 550.0 1,444 5.787 14.1 Unit 4 and 5 Projected Future Emissions (a) 4,783 8,403 646.5 1,134.4 842.5 1,449 5.808 250.6 Unit 4 and Unit 5 Emission Change -19,247 30.0 2.3 333.1 292.4 5.2 0.021 236.5 New DSI Sorbent Truck Traffic 0.0 0.0 0.095 0.019 0.005 0.0 0.0 0.0 SCR Reagent Truck Traffic 0.0 0.0 0.087 0.017 0.004 0.0 0.0 0.0 New DSI Sorbent Material Handling 0.0 0.0 0.086 0.086 0.086 0.0 0.0 0.0 New SCR Reagent Material Handling 0.0 0.0 0.214 0.214 0.214 0.0 0.0 0.0 Total Project Emission Change -19,247 30.0 2.79 333.5 292.8 5.2 0.021 236.5 Major Source Threshold 100 100 100 100 100 100 100 100 PSD Threshold for Significant Net Emission Rate 40 40 25 15 10 100 40 7 PSD Netting Required No No No Yes Yes No No Yes Contemporaneous Projects - Auxiliary Boiler NA NA NA 0.96 0.96 NA NA 0.0 Contemporaneous Projects - Shutdown of Units 1, 2, and 3 NA NA NA -551.5 -421.8 NA NA -3.1 Total PSD Emission Change -19,247 30.0 2.79 -217.0 -128.1 5.2 0.021 233.4 PSD Applicable No No No No No No No Yes (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 i

particular project, that portion of the unit's emissions following the project that an existing unit could have accommodated during the consecutive 24-mbaseline actual emissions under paragraph (b)(48) of this section and that are also unrelated to the particular project, including any increased utilizatioSee details in Table A-3. NA = Not Applicable (contemporaneous projects only included for those pollutants which required a netting analysis).
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3.4 PSD Requirements 

The following sections provide a summary of the application requirements for projects subject to PSD. 

3.4.1 Best Available Control Technology Requirements 

The requirements for Best Available Control Technology (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 EPA as a framework or tool for the BACT process. 

More recently, EPA has published guidance 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 visible 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 Administrator, 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 combustion 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 combination 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 emission limit, BACT can also be a work practice standard in certain 

circumstances, typically if an emission limit is not feasible. One example is the specification of a 

particular control device in lieu of an emission limit. BACT limits are determined 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, but 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 determines 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 the conceptual stage and beyond the research and 
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development or pilot testing phase. The technology must have been demonstrated successfully on 

full-scale operations for a sufficient time to be considered 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 about 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 pollutant-by-pollutant basis. When establishing 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 analysis 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 affected 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-construction 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 impact levels provided in 40 CFR 52.21(i)(5). 

The Project is only subject to PSD for H2SO4 mist emissions. Since there are no ambient air quality 

standards for this pollutant, an analysis of existing air quality is not 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 exceeds 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 PM10, PM2.5, SO2, and NO2 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 other areas not designated as Class I areas. The PSD increments are 

shown in Table 3-4. 

The PSD regulations specifically provide for the use 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 Guideline on Air Quality Models (EPA 2005a). 

These guidelines allow for a stepped approach, where 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 levels (SILs), which are also presented in Table 3-4. If impacts 

are greater than the SILs, a cumulative incremental analysis of all PSD consuming sources is 
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required. The cumulative incremental air quality impacts to baseline air quality from all PSD sources 

significantly impacting an area are limited to the PSD increments listed in Table 3-4. 

The proposed Project is subject to PSD only for H2SO4. Since there are no PSD increments or 

significant impact levels for H2SO4, 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/m3

) 

Pollutant Averaging Time 

PSD Incrementsa Significant Impact 

Levelsa

Class I Class II Class Ib Class II 

PM10

Annual Arithmetic Mean 4 17 0.2 1 

24-hour Maximum 8 30 0.3 5 

PM2.5

Annual Arithmetic Mean 1 4 0.06 0.3 

24-hour Maximum 2 9 0.07 1.2 

SO2

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 

NO2 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 SO2 and NO2 are interim values specified by EPA (EPA 2010a and 2010b). 

Sources: 40CFR50; 40CFR52.21, 40CFR51.165 
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3.4.4 Additional Impact Analyses 

The additional impact analyses consist of three elements: 

1. Growth 

2. Soils and Vegetation Impacts 

3. Visibility Impairment 

The growth analysis projects air 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 within 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 net additional impacts. Rather than causing growth in the area, the 

Project will likely cause a decrease in employment 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 impacts due to growth of emissions 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 

 SO2 – 3,100 tpy decrease 

 PM – 650 tpy decrease 

 PM10 – 217 tpy decrease 

 PM2.5 – 128 tpy decrease 

Any effects on soils, vegetation, or visibility due to the potential 233 tpy increase in H2SO4 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 Quality 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. 
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These analyses are not required for this Project because the emissions of all pollutants except H2SO4 

mist will significantly decrease 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 deposition analyses due to the emissions decreases. 

3.5 Tribal New Source Review 

EPA approved the Tribal Minor NSR Program on August 31, 2011 (40 CFR Part 49). This program 

established a preconstruction permitting program for minor modifications at existing major sources, 

and establishes a minor source permitting 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 significance thresholds, the program identifies the 

requirements for air permitting, including a regulatory analysis, air quality impact analysis, and control 

equipment review. 

With respect to air quality, new and existing industrial sources are classified as either major or minor 

sources based on their potential to emit air contaminants. 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 H2SO4

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 permitting. However, net emission changes of other 

pollutant emissions which are below the major modification significant emissions 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 SO2 PM10 PM2.5 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.
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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 Deterioration and Title V Greenhouse Gas Tailoring Rule” (or in short form, 

GHG Tailoring Rule) to regulate the six GHG pollutants codified at 40 CFR Parts 51, 52, 70 and 71. 

Beginning January 2, 2011, GHGs are regulated New Source Review (NSR) pollutants under the PSD 

major source permitting program when they are emitted 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 (CO2e) will be considered a major source and any modification in amounts 

greater than 75,000 tpy of CO2e is required to undergo PSD permitting. 

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

 Carbon dioxide (CO2), 

 Nitrous oxide (N2O), 

 Methane (CH4), 

 Hydrofluorocarbons (HFCs), 

 Perfluorocarbons (PFCs), and 

 Sulfur hexafluoride (SF6). 

Only the first three of these six pollutants are combustion source related and will be emitted by the 

boilers at FCPP. The primary GHG of concern for this project is CO2, as the emission rates of CH4

and N2O are many orders of magnitude less than CO2. 

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 CO2e (not including the reduction from Units 1, 2 and 

3), which would not be considered a major modification because the emission increase is less than 

75,000 tpy. Therefore, this Project is not subject to PSD permitting for GHG emissions. The increase 

in CO2e 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 operating permit program. The Navajo Nation has 

incorporated the provisions of the federal program into the Navajo Nation Regulations at 4 NNR 11-2H. 

The major source thresholds with respect to the Navajo Nation Title V operating permit program for 

sources in attainment areas are the respective thresholds 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-ROP-05-07). APS is renewing the Title V permit to 

reflect current operations and regulatory requirements. 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. 
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3.8 Compliance Assurance Monitoring 

On October 27, 1997, EPA promulgated the Compliance Assurance Monitoring (CAM) Rule, 40 CFR 

Part 64, which addresses monitoring for certain emission units at major sources, thereby assuring that 

facility owners and operators conduct effective monitoring 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 emissions limitation or standard for the pollutant of concern; 

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

 The emission unit’s pre-control potential-to-emit (PTE) is greater than the applicable major 

source threshold. 

The CAM rule does not apply to emissions units/pollutants 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 H2SO4 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 H2SO4 mist will satisfy the CAM rule requirements. The 

proposed CAM plan for H2SO4 mist is included in Appendix C. 

3.9 Regional Haze Rule and Guidelines 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 Haze Rule that require emission controls known 

as best available retrofit technology, or BART, for industrial facilities emitting air pollutants that reduce 

visibility by causing or contributing to regional haze (EPA 2005b). 

The pollutants that reduce visibility include PM2.5, and compounds which contribute to PM2.5 formation, 

such as NOx, SOx, and under certain 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 visibility-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 previously have not been previously been subject to 

federal pollution control requirements for these pollutants. 

Under the 1999 Regional Haze Rule, states are required to set periodic goals for improving visibility in 

the 156 natural areas. As states work to reach these goals, they must develop regional haze 

implementation plans that contain enforceable measures 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). 
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States must consider a number of factors when determining 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 result from controlling the emissions. 

As discussed in Section 1, EPA promulgated a source-specific FIP requiring the FCPP to achieve 

emissions reductions required by the CAA’s BART provisions. EPA requires FCPP to reduce 

emissions of NOx and set emission limits for PM. For NOX 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 NOX emission rate. EPA also finalized an 

alternative emission control strategy 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 retained 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 down Units 1-3 and will install SCR 

on Units 4 and 5. 

3.10 Other Applicable or Potentially Applicable Regulations 

3.10.1 New Source Performance Standards – 40 CFR 60

The potential applicability of New Source Performance Standards (NSPS) is presented in the following 

subsections. Note, although there is some applicability of these standards to the FCPP (e.g., 

associated with the recently permitted auxiliary boiler), 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. The proposed modifications to Units 4 and 5 increase maximum hourly 

emissions of PM10, PM2.5, and H2SO4, but do not affect NSPS applicability 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 – Standards 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 the 
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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 Subparts for this Project. . 

3.10.1.3 NSPS Subpart OOO – Standards of Performance 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 H2SO4 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 the FCPP SCR Retrofit Project. 

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

National Emissions Standards for Hazardous Air Pollutants (NESHAP) are reflected in a requirement 

for Maximum Achievable Control Technology (MACT) standards, determined by EPA through an 

analysis of the best controlled sources in a category and 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 yet 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 testing, recordkeeping, monitoring, provides reference 

methods, and mandates general control device requirements for all other subparts as applicable. 

APS will comply with the Subpart 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, particulate matter (as a 

surrogate for non-mercury metals), and hydrogen chloride (HCl). In addition, the rule includes work 

practice standards to limit the emissions of organic air toxics, including dioxins and furans. 

Compliance with Subpart UUUUU is required by April 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 Amendments (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 case-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. 
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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 PM2.5, and ozone in non-attainment areas. CAIR required upwind states to revise their 

state rules to include measures to reduce NOx and SO2 emissions. CAIR was designed to rectify 

ozone and PM2.5 non-attainment and thus regulate SO2 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 promulgated CSAPR, 

which was vacated by a court. In its opinion, the court directed EPA to continue to enforce CAIR until 

the agency could finalize a replacement rule. Importantly, 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 CSAPR’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 aqueous ammonia with greater than 19% ammonia in 

the selective catalytic reduction system. If anhydrous ammonia or aqueous ammonia with greater 

than 19% ammonia is used to control NOx emissions 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 exceeding the threshold storage amount of anhydrous 

ammonia or aqueous ammonia with greater than 19% ammonia (10,000 lb) at the FCPP. 
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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 emissions by approximately 

19,200 tpy. The addition of SCR systems at FCPP will result in a significant emission increase of 

H2SO4 mist. Net emission increases for all other pollutants will be less than the PSD significant 

emission rates. 

The FCPP is located in an area that is either attainment or unclassified for all pollutants. Because the 

Project will result in significant emission increases of H2SO4 mist, the project will be subject to PSD for 

this pollutant, and a Best Available Control Technology (BACT) analysis is required for this pollutant. 

The only modified or new stationary sources which require BACT for H2SO4 mist: are: 

 Units 4 and 5 consisting of two 7,411 MMBtu/hr1

 pulverized coal fired boilers with emissions 

controlled by SCR, dry sorbent injection (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 emissions 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 case-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 production 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 application of best available control technology result 

in emissions of any pollutant which would exceed the emissions allowed by any applicable 

standard under 40 CFR parts 60 and 61. 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, operational standard, or combination thereof, 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. 
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requirement for the application of best available control 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 previous 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 transfer. 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 consideration, while the 

remaining control technologies are ranked by their performance levels, from the highest to the lowest 

performance level. The technically feasible control technologies are then evaluated on the basis of 

the associated economic, energy and non-air quality environmental impacts. If an alternative 

technology, starting with the highest performance level, is eliminated based on any of these criteria, 

the control technology with the next highest performance level is evaluated until a control technology 

qualifies as BACT. All evaluated control technologies 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 regulated pollutant under evaluation; 

STEP 2 - Eliminate technically infeasible or unavailable technology options; 

STEP 3 - Rank remaining control technologies by control effectiveness; 

STEP 4 - Evaluate most effective 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 used in these applications, the design and performance 

of each air pollution control technology, and the incentive for implementing the preferred control 

measures. 
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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 that hinder either identifying the control devices 

currently employed at the power plants or determining the performance levels actually achieved in 

practice by the control devices. The information 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; hence, 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 the BACT process), eliminate technically infeasible 

options (STEP 2), and to rank the remaining control technologies based on control effectiveness 

(STEP 3). 

4.2 Four Corners SCR Retrofit Project BACT Determinations 

As noted above, H2SO4 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 combustion are primarily sulfur dioxide (SO2), with a much lower 

quantity of sulfur trioxide (SO3) and gaseous sulfates. These compounds form as the organic and 

pyritic sulfur in the coal are oxidized 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 furnace 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 SO2 may be 

oxidized to form SO3. With the addition of SCR, additional SO3 will be formed because the catalyst 

will oxidize some of the SO2 to SO3. As the flue gas is cooled, SO3 reacts with water to form H2SO4. 

At temperatures below the acid dew point, H2SO4 will condense to form liquid H2SO4 (sulfuric acid 

mist). On Units 4 and 5, some of the H2SO4 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. 
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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 potential 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 Basin 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 source of the coal for the FCPP is a specific reserve 

of coal from the Navajo Mine sufficient to satisfy the plant’s fuel requirements through July 2031. 

Pursuant to the FCPP co-owners’ plant 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 agreement 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 project’s scope to evaluate coal from 

alternative sources in the BACT analysis.3

Because the FCPP is an existing plant fueled from coal derived from an adjacent mine, a 

consideration of alternative coal supplies would redefine the source, and therefore, may be eliminated 

from further consideration under STEP 1 of the BACT analysis.4

 

Furthermore, to burn low-sulfur Powder River Basin 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 increase 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 construct 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 analysis 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 source 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.”). 
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FCPP. The construction of such lines would not 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. Assuming 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 every 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 the 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. Such 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 adversely 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 inconsistent, 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 consideration as a control alternative at the FCPP. 

4.2.2.2 Fuel Washing 

As noted in EPA’s New Source Review Manual, a technology is not technically feasible if it is not 

commercially available.7

 “In general, a commercially available 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 available technology for the coal used by 

the FCPP. To date, coal washing to remove sulfur 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 technology for the FCPP and is rejected as being 

technically infeasible under STEP 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. 
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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 addition, 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 feasible, which it is not, the process would reduce 

fuel sulfur by less than 40% forcing its elimination as a control technology under the BACT analysis.9

Moreover, there are significant adverse environmental, energy, and economic impacts associated with 

coal washing. With respect to environmental impacts, an inherent consequence of coal washing (in 

addition to the use of scarce water supplies in a desert environment) is the generation of wastewater 

and solid waste streams. In respect to energy impacts, 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 lost due to the addition of water to the coal from 

the washing process. Finally, as for economics, substantial costs would be associated with 

constructing and operating the coal washing facility.10

Coal washing as a strategy to reduce SO3 emissions is not considered a technically feasible H2SO4

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 techniques 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 efficiency and may reduce emissions on a lb per MMBtu 

basis. To date, the production of processed fuels has been limited to a demonstration plant that 

began operation in Gillette, Wyoming in 2005. Although 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 the company is currently traded Over the Counter at 

$0.01 per share. 

Pre-combustion fuel processing is not applicable to the FCPP because 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 H2SO4 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 H2SO4 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.”). 
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4.2.2.4 Ammonia Injection 

Ammonia-based systems designed for H2SO4 control typically involve ammonia injection into the flue 

gas upstream of a cold-side electrostatic precipitator. Ammonia will react with SO3 in the flue gas to 

form ammonia salts, mainly ammonium sulfate [(NH4)2SO4] and ammonium bisulfate [NH4HSO4]. 

Ammonia salt formation is dependent upon flue gas temperature and reagent stoichiometric ratios. 

Flue gas temperatures at the inlet to a cold-side electrostatic 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 promote fly ash capture in a cold-side electrostatic 

precipitator. 

Ammonia injection for SO3 differs significantly from the use of ammonia for SCR. When used for 

SCR, ammonia is injected after the economizer where the flue gas temperature is approximately 650 

°F. After reacting with NOx, ammonia slip from the SCR is limited to approximately 10 ppmv. For 

control of SO3, 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 downstream 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 SO3 control on coal-fired units equipped with coldside electrostatic precipitators, an ammonia injection 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 ammonium bisulfate. In addition, even if technically feasible, ammonia 

injection is not expected to achieve lower emissions than dry sorbent injection. Based on technical 

feasibility issues and performance, ammonia injection 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 SO2 from coal-fired combustion gases. 

These devices also promote the removal of H2SO4 mist. Semi-dry scrubbing using a spray dryer 

absorber involves the introduction of hydrated lime slurry into a reaction tower where it reacts with 

SO2 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 ash, spray dryer absorber 

FGD systems produce a dry by-product that must be removed with the fly ash in the particulate control 

equipment. Therefore, a spray dryer absorber system must be located upstream of the unit’s 

particulate control device. On existing units equipped 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 existing air pollution control system. Therefore, a 

semi-dry FGD system would be considered as not technically feasible H2SO4 mist control technology 

for FCPP. 

Even if a spray dryer absorber FGD system is considered to be technically feasible, it does not offer 

any performance advantage over other technologies. Data from EPA’s RACT/BACT/LAER 

Clearinghouse, presented in Appendix B, show that H2SO4 mist emission limits for projects using this 

option are generally in the 0.0040 lb/MMBtu to 0.0075 lb/MMBtu range. The only project with both a 

spray dryer absorber FGD system and a wet FGD is the Duke Cliffside Unit 6 project which has a 

H2SO4 mist emission limit set at 0.0050 lb/MMBtu. 
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Based on technical feasibility issues and performance, 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 handling 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 micron particles used for dry injection of sodium 

compounds or hydrated lime. Although the use of a sodium-based reagent would 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 SO2

oxidation. Low conversion catalysts contain less vanadium pentoxide (V2O5) and therefore achieve 

lower SO2 oxidation at the expense of less NOx reduction. Suppliers have improved the low 

oxidation catalyst by using materials such as molybdenum and tungsten that reduce NOx while 

minimizing SO2 conversion, but they are not as effective as V2O5 for NOx control and SO2 oxidation 

is not completely mitigated. 

Catalyst vendors typically recommend a 2+1 (two initial layers plus one future layer) configuration 

on a coal-fired power plant. However, due to the 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 large 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 maldistribution issues. Maldistribution of flow will 

decrease the expected life of the catalyst because areas that are 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 structural 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 low alkalinity are all factors that adversely affect 

SCR performance. 

In order to limit NOx emissions to 0.098 lb/MMBtu, the FCPP will require 4 catalyst layers (3+1) with 

a 3-year catalyst replacement schedule. A low oxidation catalyst will be used to limit SO2 oxidation 

to 1% (0.25% per layer). With a high alkaline western subbituminous coal ash, a lower conversion 

rate might be possible, but Four Corner’s ash is not high alkaline. High alkaline western 

subbituminous coal ash contains 20 – 30% CaO plus 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.pdf
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Limiting SO2 oxidation to 0.5% might be technically feasible if the catalyst replacement schedule is 

reduced from every 3 years to every 2 years. For this analysis, limiting SO2 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 the SCR system but before the air preheater, or (3) 

after the air preheater. DSI systems consist of a storage 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 includes the effects of the 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 discussed further in Sections 4.2.1.4 and 4.2.1.5.

Table 4-1 Ranking of Technically Feasible H2SO4 Mist Control Technologies 

Control Technology 

Reduction from 

Baseline 

Emissions(a)

Emissions 

(lb/MMBtu) 

Emissions 

(ppmvd corrected 

to 3% O2) 

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 Catalyst (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 this BACT analysis to determine if it might be BACT, if 

achievable. 
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Table 4-2 Detailed Overall H2SO4 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 SO3 0.294% 0.294% 0.294% 

SO3 at Boiler Outlet 96.96 96.96 96.96 lb/hr 

Oxidation of SO2 to SO3 by SCR 0.50% 1.00% 1.00% 

SO3 added by SCR 164.67 329.34 329.34 lb/hr 

SO3 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% 

SO3 Emissions 55.74 90.82 90.82 lb/hr 

H2SO4 Emissions 68.28 111.26 111.26 lb/hr 

H2SO4 Emissions before Control 0.00461 0.00751 0.00751 lb/MMBtu 

Add on Control H2SO4 Efficiency, % 0% 42% 87% 

H2SO4 Emissions after control 0.00461 0.00435 0.00100 lb/MMBtu 

H2SO4 Emissions after control 1.6 1.5 0.3 

ppmvd 

corrected to 

3% O2

H2SO4 Emissions after control 68.3 64.5 14.8 lb/hr 

Overall H2SO4 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 control objectives and capturing sulfuric acid mist 

emissions. Wet electrostatic precipitation has been demonstrated as an effective control technology 

for sulfuric acid mist emissions from industrial applications with relatively 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 industry because of the high gas flow volumes and low acid mist 

concentrations associated with utility flue gas as well as the high cost of the corrosion resistant alloys 

that are required. 
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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 H2SO4 aerosols from the 

flue gas stream as a condensable particulate. Electrostatic 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 electrostatic precipitation system, the collecting electrodes 

are typically cleaned with a liquid wash. Particulate mass loading, particle size distribution, particulate 

electrical resistivity, and precipitator 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 control sulfuric acid mist emissions from boilers 

firing a high-sulfur bituminous coal and equipped with 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 electrostatic precipitation might limit 

H2SO4 mist emissions to 0.0010 lb/MMBtu. Although 0.0010 lb/MMBtu is used as an assumption in 

this BACT analysis, this emission rate might not be achievable. The two permit limits identified in this 

analysis, see Appendix B, are the Prairie State, Illinois project at 0.0050 lb/MMBtu and the Elm Road, 

Wisconsin project at 0.0100 lb/MMBtu, both with permit 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 H2SO4 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 electrostatic 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 H2SO4 acid mist emissions, 

based on maximum potential emissions, is 411.4 tpy. Therefore, the overall cost effectiveness is 

$178,000 per ton of H2SO4 acid mist emissions controlled. 

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

H2SO4 mist emissions at the FCPP. 
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Table 4-3 Wet ESP Capital Cost for One Unit (a)

Cost Item $ Remarks/Cost Basis 

CAPITAL COST

Direct Costs 

Purchased equipment costs 

WESP system includes casing, electrical 

t th bl & h t $41,208,000 Engineering estimate

Ash handling system $1,888,000 Engineering estimate

Booster fans $2,467,000 Engineering estimate

Electrical system upgrades $2,467,000 Engineering estimate

Ductwork $5,664,000 Engineering 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 Engineering 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 & Veatch 
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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 manpower

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 Costs 

Overhead $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. 
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4.2.4.2 Dry Sorbent Injection or SBS Injection 

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 the SCR system but before the 

air preheater, or (3) after the air preheater. DSI systems consist of a storage silo, compressors or 

blowers to transport the sorbent to the duct, and associated piping. SBS injection 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 include the concentration of acid gas species (SO3, SO2, 

and hydrochloric acid (HCl)) and temperature. Both sodium and calcium sorbents tend to first capture 

SO3, then HCl, followed by SO2. However, even when control of SO3 is the primary objective, HCl 

and SO2 may consume much of the reagent depending upon the selected reagent, pollutant 

concentrations and temperature. Sodium reagents have high SO3 reactivity, but they also readily 

react with both HCl and SO2. For power plants with existing wet FGD systems, such as the FCPP, 

reaction of sodium compounds with SO2 is an undesirable and expensive secondary effect. For SO3

control, injection of hydrated lime at a relatively low temperature can minimize the collection of SO2. 

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. Sorbacal® 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 mixing 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 (before or after the air preheater), required sorbent 

quantities and H2SO4 mist emission control performance. Based on these discussions, APS has 

determined that SBS or DSI can reduce H2SO4 mist emissions by 42% and H2SO4 mist emissions can 

be limited to 0.00435 lb/MMBtu, which is equivalent to 1.5 ppmvd corrected to 3% O2. Vendors 

expressed concerns and doubts about guaranteeing emissions below 1.5 ppmvd corrected to 3% O2

due to uncertainties about achieving this low concentration and demonstrating performance at FCPP. 

Although some facilities have shown emissions below 1.5 ppmvd corrected to 3% O2, the commercial 

guarantees have been 1.5 ppmvd corrected to 3% O2 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, the 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 compounds are very soluble in water and can create 

landfill leachate problems. 
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For the FCPP, a lime-based DSI system is the preferred H2SO4 mist emission control option. 

Achievable H2SO4 emissions are based on stack test results for the effect of combustion, the use of a 

low oxidation SCR catalyst with up to 4 layers, removal by the air preheater, removal by the fabric filter 

and wet scrubber, and increased removal by DSI as previously shown in Table 4-2. A low oxidation 

catalyst can be used in the SCR system to limit oxidation to 1%. The air preheater will remove 50% of 

the H2SO4 mist entering the unit and the fabric filter and wet scrubber system will provide 57.39% 

control. The addition of DSI will provide 42% additional 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 effect 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 DSI 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 available sorbents, sorbent injection points (before or 

after the air preheater), required sorbent quantities and H2SO4 mist emission control performance. 

Based on these discussions, APS has determined that DSI or SBS can reduce H2SO4 mist emissions 

by 42% and H2SO4 mist emissions can be limited to 0.00435 lb/MMBtu, which is equivalent to 1.5 

ppmvd corrected to 3% O2. 

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 SO2 to SO3 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 H2SO4

mist emissions to 1.6 ppmvd corrected to 3% O2. 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 compared 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 electrostatic precipitation is not BACT due to the very 

high cost effectiveness of approximately $178,000 per ton of sulfuric acid mist controlled As BACT, 

APS proposes the use of a low oxidation SCR catalyst, DSI, fabric filtration, and wet FGD to limit 

H2SO4 mist emissions to 0.00435 lb/MMBtu which is equivalent to 1.5 ppmvd corrected to 3% O2. 

The proposed H2SO4 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 widely due to many factors 

including boiler design, coal characteristics, SCR design and NOx control requirements, particulate 

control equipment type, SO2 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 should 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 SO2 and particulate control requirements in the most cost effective manner. 
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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 equipment. 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 fluidized bed combustion unit can be expected to provide 

lowerH2SO4 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 permitted 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 typically 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 not representative of how well the system will 

control emissions over time. 

Figure 4-1 presents a block flow diagram of the planned emission 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 

(NH3) for NOx control to be added to the SCR sooner in the start-up process. The SCR catalyst is 

ineffective without NH3 and NH3 cannot be added until the temperature is at a minimum to avoid 

ammonium bisulfate scaling of the SCR system. 

After the economizer and the injection of NH3, the flue gas passes through the SCR, where NOx 

reacts with NH3 and is converted to nitrogen (N2). The SCR also causes some SO2 to be converted to 

SO3. Flue gas from the SCR passes through the air preheater, where heat is recovered by heating 

the combustion air. Because the flue gas temperature drops as it passes through the air preheater, 

there is some ammonium bisulfate and/or H2SO4 mist deposition towards the back of the air 

preheater. 

After the air preheater, DSI emission control system will inject hydrated lime in order to control H2SO4

mist emissions. The hydrated lime used in the DSI system will react with SO3, and some SO2, 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 H2SO4 mist 

will be removed by the cake on the bag surfaces. 

Finally, the flue gas enters the wet flue gas desulfurization system. SO2 and some additional 

SO3/H2SO4 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. 
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Figure 4-1 FCPP Air Pollution Control Equipment Block Flow Diagram 

Atmosphere

(hydrated lime)

Wet Flue Gas 

Desulfurization

Stack Fabric Filter

Dry Sorbent Injection

Bypass

NH3 Injection

Coal Conveyor

Boiler Economizer

Air Preheater

(urea, 29%

aqueous NH3 or 

anhydrous NH3)

Selective Catalytic 

Reduction
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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 emissions 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 SO2, NOx, and CO2 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 PM10 and PM2.5 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 units (lb/MMBtu) and the baseline emissions in tons 

per year (tpy) for Units 4 and 5. Detailed baseline 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 shown in Appendix A, Table A-8. In addition, there 

will be a projected related increase in the utilization of Units 4 and 5 due to the additional power 

needed to operate the SCR system and occasional bypassing 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 parasitic power requirements. The emissions rates (lb/MMBtu) for all 

pollutants—other than NOx, H2SO4, PM10, and PM2.5—are not expected to be affected by the project. 

Therefore, projected emission rates are for the post-project period —other than NOx, H2SO4, PM10, 

and PM2.5—are the same as the baseline. The post-project NOx rate will be significantly lower after 

the project because the SCR is designed to reduce NOx. The post-project emission rates for H2SO4, 

PM10, and PM2.5 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 H2SO4 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 projected actual emissions under paragraph (b)(41) 

the operator shall exclude, in calculating 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-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. 

All of the post-project emissions, except for the emissions associated with the increased heat input 
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due to the parasitic power for the SCR and the increases in H2SO4, PM10, and PM2.5 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 increase in road traffic for delivery of these sorbents 

and reagents. 

The project will include a new silo for storage of hydrated 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 urea silos are small emission sources 

with low flow rates, at or below 5,000 acfm. The new silos will have bin vent filter/baghouses for 

control of PM10 and PM2.5 emissions. PM10 and PM2.5 emissions will be limited to 0.0050 gr/scf and 

this rate will result in maximum annual emissions 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 traffic will increase fugitive PM10 and PM2.5 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 PM10 and PM2.5 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 H2SO4 mist emissions. The increase in H2SO4

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

H2SO4 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. 
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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 

SO2 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 

PM10 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 

PM2.5 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 

H2SO4 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 CO2e 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, 2012
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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% 

SO2 Emission Rate 0.1722 lb/MMBtu Same as baseline, no Project related change 

SO2 Emissions 8,403.2 tpy Based on projected Future Fuel Use Excluding 

Demand Growth 

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

NOx 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 

PM10 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 

PM10 Emissions 1,288.9 tpy Total emissions 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 

PM10 Emissions 1,134.4 tpy Excluding non-Project related emissions 
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PM2.5 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 

PM2.5 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 

PM2.5 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 

CO2 Emission Rate 205.2 lb/MMBtu Same as baseline, no Project related change 

CO2 Emissions 10,013,236 tpy Based on projected Future Fuel Use Excluding 

Demand Growth 

CO2e Emission Rate 206.8 lb/MMBtu Same as baseline, no Project related change 

CO2eEmissions 10,094,124 tpy Based on projected Future Fuel Use Excluding 

Demand Growth 

(a) Projected actual emissions do not include exclusions allowed by 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 the particular project, that 

portion of the unit's emissions following the project that an existing unit 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. 

(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 emission rate are "unrelated to the particular project". 
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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 precipitation falls from July through September. The San Juan 

River basin in the part of this area in northwest New Mexico has the highest streamflow volume in the 

state, relying almost entirely on surface water (NRCS 2006). 

The soils of the San Juan River basin have been principally 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 valleys 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 affected was delineated using dispersion and deposition 

modeling for the EIS that is being prepared concurrently 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 drivers 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 contribute 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 predicted surface soil concentrations of the selected 

metals deposited on the soil were compared to the estimated existing soil concentrations derived from 

the PLUTO database for San Juan County, New Mexico (USGS 2012). The future surface soil 

concentrations of each metal calculated to accumulate over 25 years were computed (based on 

CALPUFF modeling) and compared to the corresponding 95th percent upper confidence limit (95UCL) 

of the soil concentrations derived from the PLUTO 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 concentration 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 discountable14. 

 

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. 
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Figure 6-1 Deposition Area for the ESA Analysis 
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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 Basins Semi-Desert Grassland (23%), Inter-Mountain 

Basins Mixed Salt Desert Scrub (20%), Colorado 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 occur within the Deposition Area. Based on the 

Habitat Model (AECOM 2013a) prepared in support 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 critical habitat for federally listed species 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 (most 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, 2008b, 2009). Soil acidity affects the chemical 

properties and leaching potential of metals because metals 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 result 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 Deposition Area. After taking into account the total 

deposition of all acid-generating compounds (H2SO4, SO2, 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 deposition 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 the 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 utilize no more than 3 percent of the ANC of the 
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60221977-460 April 2014

6-4

soil with the lowest potential to buffer the acid. It was concluded that the soil within the Deposition 

Area has the ability to accept much more acidic deposition than would be generated by FCPP 

emissions and would not be affected by Project emissions. Because the 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 would result from Project-related emissions. 

The future operations of Units 4 and 5 with SCRs were shown in the Draft EIS to be well below both 

the primary and secondary NAAQS for PM10 and PM2.5 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 PM10 and PM2.5 will not be exceeded due to future operations of Units 4 and 5, it can be 

concluded that the increase in H2SO4 mist along with the overall decrease in PM and other pollutant 

emissions will not adversely affect the environment or the populations and habitat of listed species 

within the Deposition Area. 
AECOM Environment 

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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 Agency (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/rulemaking/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 Guidelines for Best Available Retrofit Technology 

(BART) Determinations; Final Rule. 40 CFR Part 51.FRL–7925–9. U.S. Environmental Protection 

Agency, Research Triangle Park, North Carolina 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 Triangle Park, North Carolina 27711. 

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

EPA, 1990. New Source Review Workshop Manual. October, Draft. Accessed at 

http://www.epa.gov/NSR/ttnnsr01/gen/wkshpman.pdf 

FLAG, 2010. Federal Land Manager’s Air Quality Related Values Work Group (FLAG) Phase I Report 

– Revised (2010); Natural Resources Report NPS/NRPC/NRR-2010/232. Available at 

http://www.nature/nps.gov/air/pubs/pdf/flag/FLAG_2010.pdf 

NRCS, 2008a. Soil Survey Geographic (SSURGO) database for Shiprock Area, Parts of San Juan 

County, New Mexico and Apache County, Arizona. Soil 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. Department of Agriculture. Fort Worth, January 28. 

URL:http://SoilDataMart.nrcs.usda.gov/. 

NRCS, 2006. Land Resource Regions and Major Land Resource 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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Office of Surface Mining Reclamation and Enforcement, 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. Geochemistry 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 Calculations 
Appendix A Table of Contents

Emission Calculations

Table 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 5 Table 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 (DSI and 29% Aqueous Ammonia)Table A-5.2 Projected Emission Increase Calculation for Reagent Delivery (DSI and Urea Pellets)Table A-5.3 Projected Emission Increase Calculation for Reagent Delivery (DSI and 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 Source NSR 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 and Economizer Bypass
Table A‐1.1 Monthly Baseline Emissions

Month Unit ID SO2 Rate

 lb/MMBtu

SO2

tons

 NOx Rate

 lb/MMBtu

NOx

tons

PM

lb/MMBtu

PM

tons

PM10

lb/MMBtu

PM10

tons

PM2.5

lb/MMBtu

PM2.5

tons

H2SO4 

Mist

lb/MMBtu

H2SO4 

Mist

tons

CO

lb/MMBtu

CO

tons

VOCs

lb/MMBtu

January-10 Unit 4 0.1848 144.10 0.445 379.35 0.0070 5.46 0.0107 8.37 0.0080 6.24 0.00029 0.23 0.030 23.15 1.19E-04 

February-10 Unit 4 0.00 0.00 0.0070 0.00 0.0107 0.00 0.0080 0.00 0.00029 0.00 0.030 0.00 1.19E-04 

March-10 Unit 4 0.00 0.00 0.0070 0.00 0.0107 0.00 0.0080 0.00 0.00029 0.00 0.030 0.00 1.19E-04 

April-10 Unit 4 0.2654 203.75 0.306 293.61 0.0070 5.37 0.0107 8.24 0.0080 6.14 0.00029 0.22 0.030 22.79 1.19E-04 

May-10 Unit 4 0.1478 341.48 0.458 1,068.94 0.0070 16.17 0.0107 24.79 0.0080 18.48 0.00029 0.67 0.030 68.60 1.19E-04 

June-10 Unit 4 0.1668 378.63 0.472 1,084.01 0.0070 15.89 0.0107 24.36 0.0080 18.16 0.00029 0.66 0.030 67.41 1.19E-04 

July-10 Unit 4 0.1722 301.27 0.461 842.04 0.0070 12.24 0.0107 18.77 0.0080 13.99 0.00029 0.51 0.030 51.93 1.19E-04 

August-10 Unit 4 0.1501 217.88 0.443 699.18 0.0070 10.16 0.0107 15.58 0.0080 11.61 0.00029 0.42 0.030 43.11 1.19E-04 

September-10 Unit 4 0.1417 341.70 0.487 1,177.84 0.0070 16.88 0.0107 25.87 0.0080 19.29 0.00029 0.70 0.030 71.58 1.19E-04 

October-10 Unit 4 0.1535 362.08 0.472 1,119.62 0.0070 16.51 0.0107 25.31 0.0080 18.87 0.00029 0.68 0.030 70.04 1.19E-04 

November-10 Unit 4 0.2209 485.94 0.504 1,133.55 0.0070 15.40 0.0107 23.60 0.0080 17.60 0.00029 0.64 0.030 65.31 1.19E-04 

December-10 Unit 4 0.2290 315.90 0.429 631.11 0.0070 9.66 0.0107 14.80 0.0080 11.04 0.00029 0.40 0.030 40.96 1.19E-04 

January-11 Unit 4 0.1890 455.36 0.496 1,204.26 0.0110 26.50 0.0144 34.72 0.0101 24.38 0.00029 0.70 0.030 71.54 1.19E-04 

February-11 Unit 4 0.1853 363.68 0.452 921.03 0.0110 21.59 0.0144 28.29 0.0101 19.87 0.00029 0.57 0.030 58.28 1.19E-04 

March-11 Unit 4 0.1675 354.79 0.463 993.87 0.0110 23.30 0.0144 30.53 0.0101 21.44 0.00029 0.61 0.030 62.90 1.19E-04 

April-11 Unit 4 0.1877 442.93 0.481 1,138.34 0.0110 25.96 0.0144 34.01 0.0101 23.88 0.00029 0.68 0.030 70.07 1.19E-04 

May-11 Unit 4 0.1565 376.89 0.486 1,178.20 0.0110 26.48 0.0144 34.69 0.0101 24.37 0.00029 0.70 0.030 71.49 1.19E-04 

June-11 Unit 4 0.1544 360.04 0.498 1,172.06 0.0110 25.66 0.0144 33.61 0.0101 23.61 0.00029 0.68 0.030 69.26 1.19E-04 

July-11 Unit 4 0.1563 392.94 0.510 1,288.24 0.0110 27.66 0.0144 36.23 0.0101 25.44 0.00029 0.73 0.030 74.65 1.19E-04 

August-11 Unit 4 0.1557 345.56 0.474 1,094.55 0.0110 24.41 0.0144 31.98 0.0101 22.46 0.00029 0.64 0.030 65.89 1.19E-04 

September-11 Unit 4 0.1492 317.95 0.456 987.89 0.0110 23.44 0.0144 30.71 0.0101 21.57 0.00029 0.62 0.030 63.27 1.19E-04 

October-11 Unit 4 0.1866 149.75 0.471 395.98 0.0110 8.83 0.0144 11.57 0.0101 8.12 0.00029 0.23 0.030 23.83 1.19E-04 

November-11 Unit 4 0.2083 102.72 0.372 205.29 0.0110 5.43 0.0144 7.11 0.0101 4.99 0.00029 0.14 0.030 14.64 1.19E-04 

December-11 Unit 4 0.1643 403.49 0.445 1,092.24 0.0110 27.02 0.0144 35.40 0.0101 24.86 0.00029 0.71 0.030 72.93 1.19E-04 

January-12 Unit 4 0.1759 418.09 0.461 1,099.05 0.0260 61.79 0.0282 67.04 0.0181 42.94 0.00029 0.69 0.030 70.56 1.19E-04 

February-12 Unit 4 0.1850 413.10 0.464 1,039.45 0.0260 58.06 0.0282 63.00 0.0181 40.35 0.00029 0.65 0.030 66.31 1.19E-04 

March-12 Unit 4 0.1688 276.63 0.421 732.40 0.0260 42.60 0.0282 46.23 0.0181 29.61 0.00029 0.48 0.030 48.65 1.19E-04 

April-12 Unit 4 0.1446 182.69 0.450 598.36 0.0260 32.85 0.0282 35.65 0.0181 22.83 0.00029 0.37 0.030 37.52 1.19E-04 

May-12 Unit 4 0.1276 196.39 0.479 779.95 0.0260 40.02 0.0282 43.42 0.0181 27.81 0.00029 0.45 0.030 45.70 1.19E-04 

June-12 Unit 4 0.1142 225.12 0.501 1,016.08 0.0260 51.25 0.0282 55.61 0.0181 35.62 0.00029 0.57 0.030 58.53 1.19E-04 

July-12 Unit 4 0.1215 234.25 0.456 922.65 0.0260 50.13 0.0282 54.39 0.0181 34.84 0.00029 0.56 0.030 57.25 1.19E-04 

August-12 Unit 4 0.1131 175.75 0.491 820.87 0.0260 40.41 0.0282 43.84 0.0181 28.08 0.00029 0.45 0.030 46.14 1.19E-04 

September-12 Unit 4 0.1216 310.37 0.540 1,382.27 0.0260 66.38 0.0282 72.02 0.0181 46.13 0.00029 0.74 0.030 75.80 1.19E-04 

October-12 Unit 4 0.1384 367.72 0.533 1,421.44 0.0260 69.10 0.0282 74.98 0.0181 48.03 0.00029 0.77 0.030 78.92 1.19E-04 

November-12 Unit 4 0.1537 337.98 0.551 1,236.07 0.0260 57.16 0.0282 62.02 0.0181 39.73 0.00029 0.64 0.030 65.28 1.19E-04 

December-12 Unit 4 0.1858 468.80 0.540 1,366.60 0.0260 65.60 0.0282 71.18 0.0181 45.59 0.00029 0.73 0.030 74.91 1.19E-04 

January-13 Unit 4 0.1833 439.56 0.522 1,265.77 0.0040 9.59 0.0080 19.11 0.0064 15.37 0.00029 0.70 0.030 71.20 1.19E-04 

February-13 Unit 4 0.1639 291.84 0.552 1,018.10 0.0040 7.12 0.0080 14.19 0.0064 11.41 0.00029 0.52 0.030 52.87 1.19E-04 

March-13 Unit 4 0.1438 299.55 0.512 1,103.14 0.0040 8.33 0.0080 16.60 0.0064 13.35 0.00029 0.60 0.030 61.83 1.19E-04 

April-13 Unit 4 0.1225 79.66 0.465 305.60 0.0040 2.60 0.0080 5.18 0.0064 4.17 0.00029 0.19 0.030 19.31 1.19E-04 

May-13 Unit 4 0.1753 255.52 0.461 747.39 0.0040 5.83 0.0080 11.62 0.0064 9.34 0.00029 0.42 0.030 43.27 1.19E-04 

June-13 Unit 4 0.1471 347.03 0.518 1,236.89 0.0040 9.44 0.0080 18.80 0.0064 15.12 0.00029 0.68 0.030 70.05 1.19E-04 

July-13 Unit 4 0.1241 229.01 0.492 947.63 0.0040 7.38 0.0080 14.70 0.0064 11.83 0.00029 0.54 0.030 54.78 1.19E-04 

August-13 Unit 4 0.1275 308.93 0.497 1,210.29 0.0040 9.69 0.0080 19.31 0.0064 15.53 0.00029 0.70 0.030 71.92 1.19E-04 

September-13 Unit 4 0.1480 236.36 0.522 853.35 0.0040 6.39 0.0080 12.73 0.0064 10.24 0.00029 0.46 0.030 47.42 1.19E-04 

October-13 Unit 4 0.1551 280.62 0.548 1,017.72 0.0040 7.24 0.0080 14.42 0.0064 11.60 0.00029 0.52 0.030 53.73 1.19E-04 

November-13 Unit 4 0.1435 327.44 0.528 1,213.18 0.0040 9.13 0.0080 18.19 0.0064 14.63 0.00029 0.66 0.030 67.77 1.19E-04 

December-13 Unit 4 0.1869 221.05 0.512 645.35 0.0040 4.73 0.0080 9.43 0.0064 7.58 0.00029 0.34 0.030 35.13 1.19E-04 

January-10 Unit 5 0.1901 510.56 0.481 1,292.90 0.0080 21.49 0.0117 31.29 0.0085 22.91 0.00029 0.78 0.030 79.75 1.19E-04 

February-10 Unit 5 0.1825 432.94 0.503 1,192.64 0.0080 18.98 0.0117 27.63 0.0085 20.23 0.00029 0.69 0.030 70.43 1.19E-04 

March-10 Unit 5 0.1672 441.88 0.488 1,291.27 0.0080 21.15 0.0117 30.79 0.0085 22.55 0.00029 0.77 0.030 78.48 1.19E-04 

April-10 Unit 5 0.1804 449.87 0.480 1,221.96 0.0080 19.95 0.0117 29.06 0.0085 21.28 0.00029 0.72 0.030 74.05 1.19E-04 

May-10 Unit 5 0.1618 428.76 0.489 1,298.30 0.0080 21.20 0.0117 30.87 0.0085 22.60 0.00029 0.77 0.030 78.67 1.19E-04 

June-10 Unit 5 0.1857 287.06 0.471 772.95 0.0080 12.36 0.0117 18.01 0.0085 13.18 0.00029 0.45 0.030 45.89 1.19E-04 

July-10 Unit 5 0.1680 364.43 0.518 1,143.21 0.0080 17.35 0.0117 25.27 0.0085 18.50 0.00029 0.63 0.030 64.39 1.19E-04 

August-10 Unit 5 0.1366 268.06 0.501 988.14 0.0080 15.70 0.0117 22.86 0.0085 16.74 0.00029 0.57 0.030 58.25 1.19E-04 

September-10 Unit 5 0.1473 347.36 0.494 1,193.65 0.0080 18.86 0.0117 27.47 0.0085 20.11 0.00029 0.68 0.030 70.01 1.19E-04 

October-10 Unit 5 0.1708 432.56 0.505 1,285.85 0.0080 20.25 0.0117 29.50 0.0085 21.60 0.00029 0.73 0.030 75.17 1.19E-04 

November-10 Unit 5 0.2370 596.15 0.530 1,335.46 0.0080 20.12 0.0117 29.30 0.0085 21.46 0.00029 0.73 0.030 74.68 1.19E-04 

December-10 Unit 5 0.2197 476.56 0.490 1,090.30 0.0080 17.35 0.0117 25.27 0.0085 18.50 0.00029 0.63 0.030 64.41 1.19E-04 

January-11 Unit 5 0.2615 571.18 0.472 1,077.50 0.0100 21.84 0.0135 29.47 0.0096 20.95 0.00029 0.63 0.030 64.86 1.19E-04 

February-11 Unit 5 0.2430 540.97 0.470 1,052.13 0.0100 22.26 0.0135 30.03 0.0096 21.35 0.00029 0.65 0.030 66.10 1.19E-04 

March-11 Unit 5 0.2039 432.69 0.440 967.57 0.0100 21.22 0.0135 28.62 0.0096 20.35 0.00029 0.62 0.030 62.99 1.19E-04 

April-11 Unit 5 0.2460 127.66 0.460 242.51 0.0100 5.19 0.0135 7.00 0.0096 4.98 0.00029 0.15 0.030 15.41 1.19E-04 

May-11 Unit 5 0.2125 186.38 0.382 393.31 0.0100 8.77 0.0135 11.83 0.0096 8.41 0.00029 0.25 0.030 26.04 1.19E-04 

June-11 Unit 5 0.1737 356.92 0.455 971.58 0.0100 20.55 0.0135 27.73 0.0096 19.71 0.00029 0.60 0.030 61.02 1.19E-04 

July-11 Unit 5 0.1364 316.03 0.484 1,151.45 0.0100 23.16 0.0135 31.25 0.0096 22.21 0.00029 0.67 0.030 68.78 1.19E-04 
Table A‐1.1 Monthly Baseline Emissions

Month Unit ID SO2 Rate

 lb/MMBtu

SO2

tons

 NOx Rate

 lb/MMBtu

NOx

tons

PM

lb/MMBtu

PM

tons

PM10

lb/MMBtu

PM10

tons

PM2.5

lb/MMBtu

PM2.5

tons

H2SO4 

Mist

lb/MMBtu

H2SO4 

Mist

tons

CO

lb/MMBtu

CO

tons

VOCs

lb/MMBtu

August-11 Unit 5 0.1207 183.45 0.477 757.43 0.0100 15.19 0.0135 20.50 0.0096 14.57 0.00029 0.44 0.030 45.11 1.19E-04 

September-11 Unit 5 0.1452 351.51 0.504 1,239.08 0.0100 24.21 0.0135 32.66 0.0096 23.22 0.00029 0.70 0.030 71.88 1.19E-04 

October-11 Unit 5 0.2062 509.16 0.508 1,257.37 0.0100 24.69 0.0135 33.31 0.0096 23.68 0.00029 0.72 0.030 73.32 1.19E-04 

November-11 Unit 5 0.2189 547.63 0.514 1,286.26 0.0100 25.02 0.0135 33.75 0.0096 23.99 0.00029 0.73 0.030 74.28 1.19E-04 

December-11 Unit 5 0.2282 580.67 0.522 1,328.99 0.0100 25.44 0.0135 34.32 0.0096 24.40 0.00029 0.74 0.030 75.54 1.19E-04 

January-12 Unit 5 0.2235 577.32 0.518 1,339.21 0.0060 15.50 0.0098 25.34 0.0075 19.30 0.00029 0.75 0.030 76.70 1.19E-04 

February-12 Unit 5 0.2213 527.71 0.498 1,189.91 0.0060 14.31 0.0098 23.39 0.0075 17.81 0.00029 0.69 0.030 70.79 1.19E-04 

March-12 Unit 5 0.2142 443.34 0.479 1,026.49 0.0060 12.42 0.0098 20.30 0.0075 15.46 0.00029 0.60 0.030 61.45 1.19E-04 

April-12 Unit 5 0.2052 237.62 0.479 566.12 0.0060 6.95 0.0098 11.36 0.0075 8.65 0.00029 0.34 0.030 34.37 1.19E-04 

May-12 Unit 5 0.1773 254.49 0.427 631.29 0.0060 8.61 0.0098 14.08 0.0075 10.72 0.00029 0.42 0.030 42.62 1.19E-04 

June-12 Unit 5 0.1479 295.04 0.457 927.83 0.0060 11.97 0.0098 19.57 0.0075 14.90 0.00029 0.58 0.030 59.24 1.19E-04 

July-12 Unit 5 0.1192 307.53 0.475 1,233.96 0.0060 15.48 0.0098 25.30 0.0075 19.27 0.00029 0.75 0.030 76.59 1.19E-04 

August-12 Unit 5 0.1225 274.15 0.481 1,098.17 0.0060 13.42 0.0098 21.95 0.0075 16.71 0.00029 0.65 0.030 66.43 1.19E-04 

September-12 Unit 5 0.1384 338.74 0.497 1,230.92 0.0060 14.69 0.0098 24.01 0.0075 18.28 0.00029 0.71 0.030 72.67 1.19E-04 

October-12 Unit 5 0.1746 459.17 0.520 1,372.25 0.0060 15.78 0.0098 25.80 0.0075 19.65 0.00029 0.76 0.030 78.09 1.19E-04 

November-12 Unit 5 0.1991 413.35 0.485 1,023.64 0.0060 12.46 0.0098 20.37 0.0075 15.51 0.00029 0.60 0.030 61.64 1.19E-04 

December-12 Unit 5 0.1909 240.79 0.460 606.33 0.0060 7.57 0.0098 12.37 0.0075 9.42 0.00029 0.37 0.030 37.44 1.19E-04 

January-13 Unit 5 0.2218 527.81 0.461 1,117.90 0.0040 9.52 0.0080 18.96 0.0064 15.25 0.00029 0.69 0.030 70.64 1.19E-04 

February-13 Unit 5 0.2351 364.70 0.457 723.95 0.0040 6.20 0.0080 12.36 0.0064 9.94 0.00029 0.45 0.030 46.06 1.19E-04 

March-13 Unit 5 0.2069 413.48 0.476 972.50 0.0040 8.00 0.0080 15.93 0.0064 12.81 0.00029 0.58 0.030 59.35 1.19E-04 

April-13 Unit 5 0.1911 324.97 0.511 912.12 0.0040 6.80 0.0080 13.55 0.0064 10.90 0.00029 0.49 0.030 50.49 1.19E-04 

May-13 Unit 5 0.2035 364.28 0.483 898.05 0.0040 7.16 0.0080 14.27 0.0064 11.47 0.00029 0.52 0.030 53.15 1.19E-04 

June-13 Unit 5 0.1381 249.35 0.526 983.57 0.0040 7.22 0.0080 14.39 0.0064 11.58 0.00029 0.52 0.030 53.62 1.19E-04 

July-13 Unit 5 0.1299 192.02 0.514 791.24 0.0040 5.91 0.0080 11.78 0.0064 9.47 0.00029 0.43 0.030 43.88 1.19E-04 

August-13 Unit 5 0.1284 284.34 0.481 1,082.33 0.0040 8.86 0.0080 17.64 0.0064 14.19 0.00029 0.64 0.030 65.73 1.19E-04 

September-13 Unit 5 0.1515 235.98 0.478 767.80 0.0040 6.23 0.0080 12.41 0.0064 9.98 0.00029 0.45 0.030 46.24 1.19E-04 

October-13 Unit 5 0.2097 463.57 0.508 1,139.72 0.0040 8.84 0.0080 17.62 0.0064 14.17 0.00029 0.64 0.030 65.64 1.19E-04 

November-13 Unit 5 0.1862 393.72 0.533 1,129.19 0.0040 8.46 0.0080 16.85 0.0064 13.55 0.00029 0.61 0.030 62.77 1.19E-04 

December-13 Unit 5 0.1819 97.35 0.504 272.43 0.004 2.14 0.0080 4.27 0.0064 3.43 0.0002 0.16 9 0.030 15.89 1.19E-04 

Emission 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 1.1-5

Sulfuric 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 5

2010 0.0070 0.00802011 0.0110 0.01002012 0.0260 0.00602013 0.0040 0.0040

PM10, lb/MMBtuPM2.5, lb/MMBtu

CO2 plus CH4 at 0.0243 lb/MMBtu x 25 plus N2O at 0.00353 lb/MMBtu x 398 plus CO2 based on EPA's GHG Mandatory Reporting Rule
Heat Input SO2 NOx PM PM10 PM2.5 H2SO4 

Mist

CO VOCs Lead 

MMBtu/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr 

June-12 95,866,844 8,664 23,492 525.3 688.9 484.1 13.90 1,423 5.70 0.113 

July-12 96,456,714 8,602 23,577 543.3 706.8 494.9 13.99 1,432 5.74 0.114 

August-12 96,834,161 8,584 23,693 557.3 720.5 503.1 14.04 1,438 5.76 0.114 

September-12 97,066,130 8,564 23,814 580.0 741.8 515.6 14.07 1,441 5.78 0.115 

October-12 97,463,479 8,580 24,008 604.1 764.8 529.2 14.13 1,447 5.80 0.115 

November-12 97,023,072 8,415 23,903 621.1 779.5 537.3 14.07 1,440 5.77 0.114 

December-12 97,258,307 8,373 24,029 644.2 801.3 550.0 14.10 1,444 5.79 0.115 

January-13 97,441,675 8,344 24,080 629.6 788.2 542.7 14.13 1,447 5.80 0.115 

February-13 96,584,227 8,220 23,965 614.3 772.3 532.7 14.00 1,434 5.75 0.114 

March-13 96,425,554 8,182 24,022 600.2 759.0 524.9 13.98 1,431 5.74 0.114 

April-13 95,897,215 8,099 23,940 589.3 747.9 518.0 13.91 1,424 5.71 0.113 

May-13 95,859,909 8,128 23,977 578.2 737.6 512.1 13.90 1,423 5.70 0.113 

June-13 95,637,260 8,067 24,016 563.4 723.5 503.8 13.87 1,420 5.69 0.113 

July-13 94,129,363 7,923 23,665 544.6 703.0 490.6 13.65 1,397 5.60 0.111 

August-13 95,026,877 7,956 23,885 534.1 695.2 486.9 13.78 1,411 5.65 0.112 

September-13 93,629,227 7,857 23,583 516.6 676.1 474.6 13.58 1,390 5.57 0.110 

October-13 94,377,633 7,900 23,835 507.9 669.7 471.6 13.68 1,401 5.62 0.111 

November-13 95,778,966 7,935 24,260 501.5 666.8 471.2 13.89 1,422 5.70 0.113 

December-13 92,496,669 7,602 23,508 478.7 638.8 452.1 13.41 1,373 5.50 0.109 

Baseline emissions January 2011 through December 2012, MMBtu/yr and ton/yr

 8,373 97,258,307 24,029 644.2 801.3 550.0 14.10 1,444 5.79 0.115 

Baseline emissions January 2011 through December 2012, lb/MMBtu

 0.494 0.172 0.0132 0.0165 0.0113 0.00029 0.030 0.000119 2.36E-06 

Table A-1.2 Annual Average Emissions based on Rolling 24-Month Average - Units 4 and 5 

Month

(a) The expected start of construction is mid 2015 (approximately June 30, 2015. Therefore, the earliest allowable baseline period is July 2010 th
Table A‐1.1 Monthly Baseline Emissions

Month Unit ID SO2 Rate

 lb/MMBtu

SO2

tons

 NOx Rate

 lb/MMBtu

NOx

tons

PM

lb/MMBtu

PM

tons

PM10

lb/MMBtu

PM10

tons

PM2.5

lb/MMBtu

PM2.5

tons

H2SO4 

Mist

lb/MMBtu

H2SO4 

Mist

tons

CO

lb/MMBtu

CO

tons

VOCs

lb/MMBtu

VOC

ton

January-10 Unit 1 0.0733 46.17 0.776 494.26 0.0170 10.71 0.0162 10.21 0.0128 8.07 0.00014 0.09 0.030 18.71 1.19E-04 0

February-10 Unit 1 0.1174 66.88 0.753 435.04 0.0170 0.00 0.0162 9.23 0.0128 7.30 0.00014 0.08 0.030 16.91 1.19E-04 0

March-10 Unit 1 0.1141 75.37 0.768 517.89 0.0170 0.00 0.0162 10.71 0.0128 8.46 0.00014 0.09 0.030 19.62 1.19E-04 0

April-10 Unit 1 0.1392 68.05 0.760 386.87 0.0170 8.31 0.0162 7.92 0.0128 6.26 0.00014 0.07 0.030 14.51 1.19E-04 0

May-10 Unit 1 0.1626 105.81 0.781 515.78 0.0170 11.06 0.0162 10.55 0.0128 8.34 0.00014 0.09 0.030 19.32 1.19E-04 0

June-10 Unit 1 0.0690 44.86 0.808 526.61 0.0170 11.05 0.0162 10.53 0.0128 8.33 0.00014 0.09 0.030 19.30 1.19E-04 0

July-10 Unit 1 0.0875 51.99 0.766 459.41 0.0170 10.11 0.0162 9.64 0.0128 7.62 0.00014 0.08 0.030 17.65 1.19E-04 0

August-10 Unit 1 0.0993 66.34 0.757 514.76 0.0170 11.36 0.0162 10.83 0.0128 8.56 0.00014 0.09 0.030 19.83 1.19E-04 0

September-10 Unit 1 0.0891 54.61 0.796 488.41 0.0170 10.41 0.0162 9.93 0.0128 7.85 0.00014 0.09 0.030 18.19 1.19E-04 0

October-10 Unit 1 0.1523 93.31 0.778 493.17 0.0170 10.42 0.0162 9.93 0.0128 7.85 0.00014 0.09 0.030 18.20 1.19E-04 0

November-10 Unit 1 0.1569 99.74 0.788 514.00 0.0170 10.80 0.0162 10.30 0.0128 8.14 0.00014 0.09 0.030 18.87 1.19E-04 0

December-10 Unit 1 0.2295 153.53 0.789 532.24 0.0170 11.37 0.0162 10.84 0.0128 8.57 0.00014 0.09 0.030 19.86 1.19E-04 0

January-11 Unit 1 0.1840 89.44 0.714 377.19 0.0180 8.75 0.0169 8.22 0.0133 6.47 0.00014 0.07 0.030 14.43 1.19E-04 0

February-11 Unit 1 0.1155 64.96 0.747 446.85 0.0180 10.12 0.0169 9.51 0.0133 7.49 0.00014 0.08 0.030 16.69 1.19E-04 0

March-11 Unit 1 0.1244 76.37 0.780 488.27 0.0180 11.05 0.0169 10.39 0.0133 8.18 0.00014 0.09 0.030 18.22 1.19E-04 0

April-11 Unit 1 0.0920 42.71 0.756 365.55 0.0180 8.35 0.0169 7.85 0.0133 6.18 0.00014 0.06 0.030 13.78 1.19E-04 0

May-11 Unit 1 0.0767 43.30 0.786 451.44 0.0180 10.17 0.0169 9.56 0.0133 7.52 0.00014 0.08 0.030 16.77 1.19E-04 0

June-11 Unit 1 0.1167 68.74 0.789 473.04 0.0180 10.61 0.0169 9.97 0.0133 7.85 0.00014 0.08 0.030 17.50 1.19E-04 0

July-11 Unit 1 0.1371 76.89 0.759 441.95 0.0180 10.09 0.0169 9.49 0.0133 7.47 0.00014 0.08 0.030 16.65 1.19E-04 0

August-11 Unit 1 0.1467 92.30 0.749 489.33 0.0180 11.32 0.0169 10.64 0.0133 8.38 0.00014 0.09 0.030 18.68 1.19E-04 0

September-11 Unit 1 0.1047 61.71 0.742 450.80 0.0180 10.61 0.0169 9.97 0.0133 7.85 0.00014 0.08 0.030 17.50 1.19E-04 0

October-11 Unit 1 0.1908 46.80 0.744 189.17 0.0180 4.42 0.0169 4.15 0.0133 3.27 0.00014 0.03 0.030 7.28 1.19E-04 0

November-11 Unit 1 0.1420 4.82 0.435 24.27 0.0180 0.61 0.0169 0.57 0.0133 0.45 0.00014 0.00 0.030 1.01 1.19E-04 0

December-11 Unit 1 0.1177 63.38 0.754 420.07 0.0180 9.69 0.0169 9.11 0.0133 7.17 0.00014 0.08 0.030 15.98 1.19E-04 0

January-12 Unit 1 0.1074 65.44 0.797 487.01 0.0290 17.67 0.0247 15.06 0.0189 11.53 0.00014 0.09 0.030 18.09 1.19E-04 0

February-12 Unit 1 0.1111 51.67 0.733 365.49 0.0290 13.48 0.0247 11.50 0.0189 8.80 0.00014 0.07 0.030 13.81 1.19E-04 0

March-12 Unit 1 0.0756 31.66 0.755 327.47 0.0290 12.14 0.0247 10.36 0.0189 7.93 0.00014 0.06 0.030 12.43 1.19E-04 0

April-12 Unit 1 0.1010 6.10 0.532 42.37 0.0290 1.75 0.0247 1.49 0.0189 1.14 0.00014 0.01 0.030 1.79 1.19E-04 0

May-12 Unit 1 0.1012 40.62 0.741 316.01 0.0290 11.64 0.0247 9.92 0.0189 7.60 0.00014 0.06 0.030 11.91 1.19E-04 0

June-12 Unit 1 0.0866 52.00 0.779 474.28 0.0290 17.42 0.0247 14.85 0.0189 11.37 0.00014 0.08 0.030 17.83 1.19E-04 0

July-12 Unit 1 0.1276 69.55 0.742 417.01 0.0290 15.81 0.0247 13.48 0.0189 10.32 0.00014 0.08 0.030 16.18 1.19E-04 0

August-12 Unit 1 0.1819 92.74 0.745 403.29 0.0290 14.78 0.0247 12.61 0.0189 9.65 0.00014 0.07 0.030 15.14 1.19E-04 0

September-12 Unit 1 0.1737 89.03 0.742 399.54 0.0290 14.86 0.0247 12.67 0.0189 9.70 0.00014 0.07 0.030 15.22 1.19E-04 0

October-12 Unit 1 0.1938 135.32 0.810 565.27 0.0290 20.24 0.0247 17.26 0.0189 13.21 0.00014 0.10 0.030 20.73 1.19E-04 0

November-12 Unit 1 0.1747 90.36 0.775 410.00 0.0290 15.00 0.0247 12.79 0.0189 9.79 0.00014 0.07 0.030 15.35 1.19E-04 0

December-12 Unit 1 0.1676 110.88 0.779 522.77 0.0290 19.18 0.0247 16.36 0.0189 12.52 0.00014 0.09 0.030 19.64 1.19E-04 0

January-13 Unit 1 0.1710 86.76 0.721 400.19 0.0150 7.61 0.0148 7.50 0.0118 5.98 0.00014 0.07 0.030 15.07 1.19E-04 0

February-13 Unit 1 0.1784 99.74 0.808 450.82 0.0150 8.39 0.0148 8.27 0.0118 6.59 0.00014 0.08 0.030 16.60 1.19E-04 0

March-13 Unit 1 0.1494 85.63 0.750 441.93 0.0150 8.60 0.0148 8.48 0.0118 6.76 0.00014 0.08 0.030 17.02 1.19E-04 0

April-13 Unit 1 0.1668 96.02 0.770 453.36 0.0150 8.64 0.0148 8.52 0.0118 6.79 0.00014 0.08 0.030 17.10 1.19E-04 0

May-13 Unit 1 0.1711 115.11 0.757 511.75 0.0150 10.09 0.0148 9.95 0.0118 7.93 0.00014 0.09 0.030 19.97 1.19E-04 0

June-13 Unit 1 0.1756 95.58 0.735 411.88 0.0150 8.16 0.0148 8.05 0.0118 6.42 0.00014 0.08 0.030 16.16 1.19E-04 0

July-13 Unit 1 0.1860 90.85 0.768 384.42 0.0150 7.33 0.0148 7.22 0.0118 5.76 0.00014 0.07 0.030 14.50 1.19E-04 0

August-13 Unit 1 0.1912 3.27 0.734 13.23 0.0150 0.26 0.0148 0.25 0.0118 0.20 0.00014 0.00 0.030 0.51 1.19E-04 0

September-13 Unit 1 0.0150 0.00 0.0148 0.00 0.0118 0.00 0.00014 0.00 0.030 0.00 1.19E-04 0

October-13 Unit 1 0.0150 0.00 0.0148 0.00 0.0118 0.00 0.00014 0.00 0.030 0.00 1.19E-04 0

November-13 Unit 1 0.0150 0.00 0.0148 0.00 0.0118 0.00 0.00014 0.00 0.030 0.00 1.19E-04 0

December-13 Unit 1 0.0150 0.00 0.0148 0.00 0.0118 0.00 0.00014 0.00 0.030 0.00 1.19E-04 0

January-10 Unit 2 0.0682 48.99 0.660 475.58 0.0200 14.37 0.0183 13.18 0.0143 10.30 0.00014 0.10 0.030 21.33 1.19E-04 0

February-10 Unit 2 0.1349 86.73 0.650 417.98 0.0200 12.86 0.0183 11.79 0.0143 9.22 0.00014 0.09 0.030 19.09 1.19E-04 0

March-10 Unit 2 0.1419 82.98 0.626 384.62 0.0200 11.70 0.0183 10.73 0.0143 8.39 0.00014 0.08 0.030 17.37 1.19E-04 0

April-10 Unit 2 0.1520 61.82 0.658 269.11 0.0200 8.13 0.0183 7.46 0.0143 5.83 0.00014 0.06 0.030 12.08 1.19E-04 0

May-10 Unit 2 0.4936 23.84 0.340 28.61 0.0200 0.97 0.0183 0.89 0.0143 0.69 0.00014 0.01 0.030 1.43 1.19E-04 0

June-10 Unit 2 0.0485 31.70 0.653 427.50 0.0200 13.08 0.0183 12.00 0.0143 9.38 0.00014 0.09 0.030 19.42 1.19E-04 0

July-10 Unit 2 0.0859 48.76 0.611 356.58 0.0200 11.35 0.0183 10.41 0.0143 8.14 0.00014 0.08 0.030 16.85 1.19E-04 0

August-10 Unit 2 0.0864 47.70 0.627 350.94 0.0200 11.04 0.0183 10.13 0.0143 7.92 0.00014 0.08 0.030 16.39 1.19E-04 0

September-10 Unit 2 0.0682 44.43 0.647 421.51 0.0200 13.03 0.0183 11.95 0.0143 9.34 0.00014 0.09 0.030 19.34 1.19E-04 0

October-10 Unit 2 0.1249 71.30 0.648 374.77 0.0200 11.41 0.0183 10.47 0.0143 8.18 0.00014 0.08 0.030 16.95 1.19E-04 0

November-10 Unit 2 0.1305 83.10 0.658 418.72 0.0200 12.74 0.0183 11.68 0.0143 9.13 0.00014 0.09 0.030 18.91 1.19E-04 0

December-10 Unit 2 0.2260 141.16 0.668 424.20 0.0200 12.49 0.0183 11.46 0.0143 8.96 0.00014 0.09 0.030 18.55 1.19E-04 0

January-11 Unit 2 0.2057 134.63 0.670 450.55 0.0300 19.63 0.0254 16.65 0.0194 12.72 0.00014 0.09 0.030 19.43 1.19E-04 0

February-11 Unit 2 0.1102 56.81 0.667 352.59 0.0300 15.46 0.0254 13.11 0.0194 10.02 0.00014 0.07 0.030 15.30 1.19E-04 0

March-11 Unit 2 0.0974 65.93 0.682 461.94 0.0300 20.31 0.0254 17.23 0.0194 13.16 0.00014 0.09 0.030 20.10 1.19E-04 0

April-11 Unit 2 0.0875 56.12 0.677 437.08 0.0300 19.23 0.0254 16.31 0.0194 12.46 0.00014 0.09 0.030 19.03 1.19E-04 0

May-11 Unit 2 0.0608 40.48 0.674 449.65 0.0300 19.98 0.0254 16.94 0.0194 12.94 0.00014 0.09 0.030 19.77 1.19E-04 0
Table A‐1.1 Monthly Baseline Emissions

Month Unit ID SO2 Rate

 lb/MMBtu

SO2

tons

 NOx Rate

 lb/MMBtu

NOx

tons

PM

lb/MMBtu

PM

tons

PM10

lb/MMBtu

PM10

tons

PM2.5

lb/MMBtu

PM2.5

tons

H2SO4 

Mist

lb/MMBtu

H2SO4 

Mist

tons

CO

lb/MMBtu

CO

tons

VOCs

lb/MMBtu

VOC

ton

June-11 Unit 2 0.1082 45.73 0.629 278.54 0.0300 12.68 0.0254 10.75 0.0194 8.21 0.00014 0.06 0.030 12.55 1.19E-04 0

July-11 Unit 2 0.1274 87.96 0.655 452.13 0.0300 20.72 0.0254 17.57 0.0194 13.43 0.00014 0.10 0.030 20.51 1.19E-04 0

August-11 Unit 2 0.1284 82.72 0.643 419.43 0.0300 19.33 0.0254 16.39 0.0194 12.53 0.00014 0.09 0.030 19.13 1.19E-04 0

September-11 Unit 2 0.0835 57.33 0.655 449.51 0.0300 20.59 0.0254 17.46 0.0194 13.34 0.00014 0.10 0.030 20.38 1.19E-04 0

October-11 Unit 2 0.1976 104.23 0.634 347.24 0.0300 15.83 0.0254 13.42 0.0194 10.25 0.00014 0.07 0.030 15.66 1.19E-04 0

November-11 Unit 2 0.1631 113.26 0.633 439.68 0.0300 20.84 0.0254 17.67 0.0194 13.50 0.00014 0.10 0.030 20.62 1.19E-04 0

December-11 Unit 2 0.1063 69.28 0.631 416.95 0.0300 19.56 0.0254 16.59 0.0194 12.67 0.00014 0.09 0.030 19.36 1.19E-04 0

January-12 Unit 2 0.0622 32.17 0.641 338.52 0.0250 12.93 0.0219 11.32 0.0169 8.74 0.00014 0.07 0.030 15.36 1.19E-04 0

February-12 Unit 2 0.0972 33.26 0.637 226.13 0.0250 8.55 0.0219 7.49 0.0169 5.78 0.00014 0.05 0.030 10.16 1.19E-04 0

March-12 Unit 2 0.0715 47.78 0.682 455.10 0.0250 16.71 0.0219 14.63 0.0169 11.29 0.00014 0.09 0.030 19.85 1.19E-04 0

April-12 Unit 2 0.1412 28.01 0.582 119.68 0.0250 4.96 0.0219 4.34 0.0169 3.35 0.00014 0.03 0.030 5.89 1.19E-04 0

May-12 Unit 2 0.1028 44.83 0.657 296.01 0.0250 10.91 0.0219 9.55 0.0169 7.37 0.00014 0.06 0.030 12.95 1.19E-04 0

June-12 Unit 2 0.0673 42.06 0.670 418.44 0.0250 15.61 0.0219 13.67 0.0169 10.55 0.00014 0.09 0.030 18.54 1.19E-04 0

July-12 Unit 2 0.1078 62.85 0.654 392.14 0.0250 14.57 0.0219 12.76 0.0169 9.84 0.00014 0.08 0.030 17.30 1.19E-04 0

August-12 Unit 2 0.1903 92.32 0.654 329.68 0.0250 12.13 0.0219 10.62 0.0169 8.20 0.00014 0.07 0.030 14.41 1.19E-04 0

September-12 Unit 2 0.2128 94.22 0.654 304.54 0.0250 11.07 0.0219 9.69 0.0169 7.48 0.00014 0.06 0.030 13.15 1.19E-04 0

October-12 Unit 2 0.2087 143.67 0.694 477.46 0.0250 17.21 0.0219 15.07 0.0169 11.62 0.00014 0.10 0.030 20.44 1.19E-04 0

November-12 Unit 2 0.1611 71.92 0.662 309.53 0.0250 11.16 0.0219 9.77 0.0169 7.54 0.00014 0.06 0.030 13.26 1.19E-04 0

December-12 Unit 2 0.1908 111.78 0.653 392.25 0.0250 14.65 0.0219 12.82 0.0169 9.89 0.00014 0.08 0.030 17.39 1.19E-04 0

January-13 Unit 2 0.1702 93.13 0.636 366.98 0.0150 8.21 0.0148 8.09 0.0118 6.45 0.00014 0.08 0.030 16.24 1.19E-04 0

February-13 Unit 2 0.1783 93.65 0.703 373.56 0.0150 7.88 0.0148 7.77 0.0118 6.19 0.00014 0.07 0.030 15.59 1.19E-04 0

March-13 Unit 2 0.1666 91.01 0.694 384.56 0.0150 8.19 0.0148 8.08 0.0118 6.44 0.00014 0.08 0.030 16.22 1.19E-04 0

April-13 Unit 2 0.1853 106.98 0.659 402.06 0.0150 8.66 0.0148 8.54 0.0118 6.81 0.00014 0.08 0.030 17.14 1.19E-04 0

May-13 Unit 2 0.1729 110.73 0.716 460.38 0.0150 9.60 0.0148 9.47 0.0118 7.55 0.00014 0.09 0.030 19.01 1.19E-04 0

June-13 Unit 2 0.1670 74.88 0.717 326.87 0.0150 6.72 0.0148 6.63 0.0118 5.29 0.00014 0.06 0.030 13.31 1.19E-04 0

July-13 Unit 2 0.1525 95.11 0.696 439.71 0.0150 9.36 0.0148 9.23 0.0118 7.36 0.00014 0.09 0.030 18.52 1.19E-04 0

August-13 Unit 2 0.1787 86.63 0.631 333.85 0.0150 7.27 0.0148 7.17 0.0118 5.72 0.00014 0.07 0.030 14.39 1.19E-04 0

September-13 Unit 2 0.1797 102.53 0.676 386.00 0.0150 8.56 0.0148 8.44 0.0118 6.73 0.00014 0.08 0.030 16.94 1.19E-04 0

October-13 Unit 2 0.1661 102.63 0.672 422.22 0.0150 9.27 0.0148 9.14 0.0118 7.29 0.00014 0.09 0.030 18.35 1.19E-04 0

November-13 Unit 2 0.1677 101.99 0.671 407.61 0.0150 9.12 0.0148 8.99 0.0118 7.17 0.00014 0.09 0.030 18.05 1.19E-04 0

December-13 Unit 2 0.1637 99.56 0.664 405.53 0.0150 9.12 0.0148 9.00 0.0118 7.17 0.00014 0.09 0.030 18.06 1.19E-04 0

January-10 Unit 3 0.0646 63.61 0.573 568.52 0.0230 22.65 0.0205 20.16 0.0159 15.63 0.00014 0.14 0.030 29.24 1.19E-04 0

February-10 Unit 3 0.1195 102.94 0.578 499.48 0.0230 19.81 0.0205 17.63 0.0159 13.67 0.00014 0.12 0.030 25.57 1.19E-04 0

March-10 Unit 3 0.0937 73.52 0.570 457.43 0.0230 18.04 0.0205 16.06 0.0159 12.45 0.00014 0.11 0.030 23.29 1.19E-04 0

April-10 Unit 3 0.1126 109.00 0.573 554.80 0.0230 22.27 0.0205 19.82 0.0159 15.36 0.00014 0.14 0.030 28.74 1.19E-04 0

May-10 Unit 3 0.1361 129.64 0.578 549.69 0.0230 21.91 0.0205 19.50 0.0159 15.12 0.00014 0.13 0.030 28.29 1.19E-04 0

June-10 Unit 3 0.0514 43.06 0.587 493.99 0.0230 19.28 0.0205 17.15 0.0159 13.30 0.00014 0.12 0.030 24.88 1.19E-04 0

July-10 Unit 3 0.0697 54.37 0.572 458.20 0.0230 17.95 0.0205 15.97 0.0159 12.38 0.00014 0.11 0.030 23.17 1.19E-04 0

August-10 Unit 3 0.0792 63.94 0.559 473.94 0.0230 18.56 0.0205 16.52 0.0159 12.81 0.00014 0.11 0.030 23.96 1.19E-04 0

September-10 Unit 3 0.0911 85.78 0.574 547.42 0.0230 21.65 0.0205 19.27 0.0159 14.94 0.00014 0.13 0.030 27.95 1.19E-04 0

October-10 Unit 3 0.1619 142.88 0.591 537.87 0.0230 20.30 0.0205 18.07 0.0159 14.01 0.00014 0.12 0.030 26.21 1.19E-04 0

November-10 Unit 3 0.1775 127.56 0.583 441.21 0.0230 16.53 0.0205 14.71 0.0159 11.40 0.00014 0.10 0.030 21.34 1.19E-04 0

December-10 Unit 3 0.2728 218.29 0.598 490.09 0.0230 18.40 0.0205 16.38 0.0159 12.70 0.00014 0.11 0.030 23.76 1.19E-04 0

January-11 Unit 3 0.2998 155.32 0.571 309.70 0.0480 24.86 0.0382 19.80 0.0286 14.83 0.00014 0.07 0.030 15.38 1.19E-04 0

February-11 Unit 3 0.1958 65.27 0.392 192.49 0.0480 16.00 0.0382 12.74 0.0286 9.54 0.00014 0.05 0.030 9.90 1.19E-04 0

March-11 Unit 3 0.1503 135.31 0.625 561.56 0.0480 43.23 0.0382 34.42 0.0286 25.77 0.00014 0.13 0.030 26.74 1.19E-04 0

April-11 Unit 3 0.1917 174.54 0.599 554.92 0.0480 43.71 0.0382 34.81 0.0286 26.06 0.00014 0.13 0.030 27.04 1.19E-04 0

May-11 Unit 3 0.0989 95.39 0.621 598.62 0.0480 46.29 0.0382 36.86 0.0286 27.60 0.00014 0.14 0.030 28.63 1.19E-04 0

June-11 Unit 3 0.1246 105.58 0.629 531.98 0.0480 40.68 0.0382 32.39 0.0286 24.25 0.00014 0.12 0.030 25.16 1.19E-04 0

July-11 Unit 3 0.1429 132.50 0.617 581.80 0.0480 44.50 0.0382 35.43 0.0286 26.53 0.00014 0.13 0.030 27.53 1.19E-04 0

August-11 Unit 3 0.1559 126.43 0.612 505.84 0.0480 38.92 0.0382 30.99 0.0286 23.21 0.00014 0.11 0.030 24.08 1.19E-04 0

September-11 Unit 3 0.0985 91.94 0.599 573.55 0.0480 44.81 0.0382 35.68 0.0286 26.72 0.00014 0.13 0.030 27.72 1.19E-04 0

October-11 Unit 3 0.1644 94.39 0.551 341.96 0.0480 27.56 0.0382 21.94 0.0286 16.43 0.00014 0.08 0.030 17.04 1.19E-04 0

November-11 Unit 3 0.1661 117.94 0.605 440.19 0.0480 34.08 0.0382 27.13 0.0286 20.32 0.00014 0.10 0.030 21.08 1.19E-04 0

December-11 Unit 3 0.1268 111.56 0.620 549.20 0.0480 42.23 0.0382 33.63 0.0286 25.18 0.00014 0.12 0.030 26.12 1.19E-04 0

January-12 Unit 3 0.1422 113.81 0.599 492.77 0.0210 16.81 0.0191 15.25 0.0149 11.89 0.00014 0.11 0.030 23.77 1.19E-04 0

February-12 Unit 3 0.1266 109.81 0.612 533.85 0.0210 18.22 0.0191 16.53 0.0149 12.88 0.00014 0.12 0.030 25.76 1.19E-04 0

March-12 Unit 3 0.0916 7.66 0.463 52.07 0.0210 1.76 0.0191 1.59 0.0149 1.24 0.00014 0.01 0.030 2.48 1.19E-04 0

April-12 Unit 3 0.1573 74.20 0.577 288.03 0.0210 9.91 0.0191 8.99 0.0149 7.01 0.00014 0.07 0.030 14.01 1.19E-04 0

May-12 Unit 3 0.1448 131.52 0.607 555.81 0.0210 19.08 0.0191 17.31 0.0149 13.49 0.00014 0.13 0.030 26.97 1.19E-04 0

June-12 Unit 3 0.1052 87.71 0.609 514.35 0.0210 17.52 0.0191 15.89 0.0149 12.39 0.00014 0.12 0.030 24.76 1.19E-04 0

July-12 Unit 3 0.1647 165.04 0.605 610.93 0.0210 21.04 0.0191 19.09 0.0149 14.88 0.00014 0.14 0.030 29.75 1.19E-04 0

August-12 Unit 3 0.2448 206.70 0.599 520.50 0.0210 17.73 0.0191 16.09 0.0149 12.54 0.00014 0.12 0.030 25.07 1.19E-04 0

September-12 Unit 3 0.1740 171.45 0.641 630.04 0.0210 20.69 0.0191 18.77 0.0149 14.63 0.00014 0.14 0.030 29.25 1.19E-04 0

October-12 Unit 3 0.1939 184.23 0.601 581.73 0.0210 19.96 0.0191 18.10 0.0149 14.11 0.00014 0.13 0.030 28.22 1.19E-04 0
Table A‐1.1 Monthly Baseline Emissions

Month Unit ID SO2 Rate

 lb/MMBtu

SO2

tons

 NOx Rate

 lb/MMBtu

NOx

tons

PM

lb/MMBtu

PM

tons

PM10

lb/MMBtu

PM10

tons

PM2.5

lb/MMBtu

PM2.5

tons

H2SO4 

Mist

lb/MMBtu

H2SO4 

Mist

tons

CO

lb/MMBtu

CO

tons

VOCs

lb/MMBtu

VOC

ton

November-12 Unit 3 0.1714 143.96 0.596 507.78 0.0210 17.64 0.0191 16.00 0.0149 12.48 0.00014 0.12 0.030 24.94 1.19E-04 0

December-12 Unit 3 0.1810 131.87 0.590 449.67 0.0210 15.30 0.0191 13.88 0.0149 10.82 0.00014 0.10 0.030 21.64 1.19E-04 0

January-13 Unit 3 0.1880 167.43 0.614 550.35 0.0150 13.36 0.0148 13.17 0.0118 10.50 0.00014 0.12 0.030 26.44 1.19E-04 0

February-13 Unit 3 0.2144 187.77 0.583 517.84 0.0150 13.14 0.0148 12.96 0.0118 10.33 0.00014 0.12 0.030 26.01 1.19E-04 0

March-13 Unit 3 0.1632 151.85 0.564 525.23 0.0150 13.96 0.0148 13.76 0.0118 10.97 0.00014 0.13 0.030 27.63 1.19E-04 0

April-13 Unit 3 0.1705 132.36 0.562 454.76 0.0150 11.64 0.0148 11.48 0.0118 9.15 0.00014 0.11 0.030 23.04 1.19E-04 0

May-13 Unit 3 0.1885 137.10 0.585 435.43 0.0150 10.91 0.0148 10.76 0.0118 8.58 0.00014 0.10 0.030 21.60 1.19E-04 0

June-13 Unit 3 0.1809 120.46 0.601 425.42 0.0150 9.99 0.0148 9.85 0.0118 7.85 0.00014 0.09 0.030 19.77 1.19E-04 0

July-13 Unit 3 0.1880 169.73 0.632 575.47 0.0150 13.54 0.0148 13.35 0.0118 10.64 0.00014 0.13 0.030 26.80 1.19E-04 0

August-13 Unit 3 0.1894 108.55 0.600 378.91 0.0150 8.60 0.0148 8.48 0.0118 6.76 0.00014 0.08 0.030 17.02 1.19E-04 0

September-13 Unit 3 0.2019 155.91 0.548 434.82 0.0150 11.59 0.0148 11.42 0.0118 9.11 0.00014 0.11 0.030 22.93 1.19E-04 0

October-13 Unit 3 0.1612 78.80 0.528 261.09 0.0150 7.33 0.0148 7.23 0.0118 5.76 0.00014 0.07 0.030 14.52 1.19E-04 0

November-13 Unit 3 0.1804 114.72 0.550 363.94 0.0150 9.54 0.0148 9.41 0.0118 7.50 0.00014 0.09 0.030 18.88 1.19E-04 0

December-13 Unit 3 0.1726 120.95 0.524 378.38 0.0150 10.51 0.0148 10.37 0.0118 8.26 0.00014 0.10 0.030 20.81 1.19E-04 0

Emission 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 1.1-5

Sulfuric 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 3

2010 0.0170 0.0200 0.02302011 0.0180 0.0300 0.04802012 0.0290 0.0250 0.02102013 0.0150 0.0150 0.0150

PM10, lb/MMBtuPM2.5, lb/MMBtu

CO2 plus CH4 at 0.0243 lb/MMBtu x 25 plus N2O at 0.00353 lb/MMBtu x 398 plus CO2 based on EPA's GHG Mandatory Reporting Rule
Heat Input SO2 NOx PM PM10 PM2.5 H2SO4 

Mist

CO VOCs Lead 

MMBtu/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr tons/yr 

June-12 44,292,345 2,851 14,958 626.9 536.8 411.4 3.10 657.55 2.64 0.052 

July-12 44,479,735 2,922 15,031 632.9 541.4 414.9 3.11 660.33 2.65 0.052 

August-12 44,292,075 3,029 14,988 634.7 542.4 415.4 3.10 657.54 2.64 0.052 

September-12 44,027,197 3,114 14,926 635.5 542.3 415.2 3.08 653.61 2.62 0.052 

October-12 44,297,690 3,191 15,035 643.1 548.3 419.7 3.10 657.63 2.64 0.052 

November-12 44,110,191 3,189 14,962 645.0 549.3 420.3 3.09 654.84 2.62 0.052 

December-12 43,992,543 3,110 14,921 648.4 551.5 421.8 3.08 653.10 2.62 0.052 

January-13 44,278,966 3,094 15,011 636.4 543.5 416.2 3.10 657.35 2.63 0.052 

February-13 44,828,226 3,191 15,186 630.3 540.3 414.3 3.14 665.50 2.67 0.053 

March-13 44,686,609 3,217 15,106 608.4 524.5 402.8 3.13 663.40 2.66 0.053 

April-13 44,600,103 3,248 15,083 587.2 509.2 391.8 3.12 662.12 2.65 0.053 

May-13 44,445,443 3,339 15,037 564.3 492.7 379.8 3.11 659.82 2.64 0.052 

June-13 44,244,693 3,375 14,977 544.8 478.4 369.4 3.10 656.84 2.63 0.052 

July-13 44,081,216 3,404 14,939 522.2 462.0 357.6 3.09 654.41 2.62 0.052 

August-13 43,072,138 3,353 14,595 495.5 441.0 341.9 3.02 639.43 2.56 0.051 

September-13 42,205,727 3,376 14,268 467.6 419.3 325.8 2.95 626.57 2.51 0.050 

October-13 41,965,772 3,344 14,170 452.0 407.8 317.4 2.94 623.01 2.50 0.050 

November-13 41,771,402 3,335 14,104 433.5 394.3 307.6 2.92 620.12 2.49 0.049 

December-13 41,010,456 3,323 13,803 407.6 374.3 292.8 2.87 608.83 2.44 0.048 

Baseline emissions January 2011 through December 2012, MMBtu/yr and ton/yr

 3,110 43,992,543 14,921 648.4 551.5 421.8 3.08 653 2.62 0.052 

Baseline emissions January 2011 through December 2012, lb/MMBtu

 0.678 0.141 0.0295 0.0251 0.0192 0.00014 0.030 0.000119 2.36E-06 

Table A-1.4 Annual Average Emissions based on Rolling 24-Month Average - Units 1, 2, and 

Month

(a) The expected start of construction is mid 2015 (approximately June 30, 2015. Therefore, the earliest allowable baseline period is July 2010 th
Parameter Value Units Comments

Boiler 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 low oxidation catalyst

SO3 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 Wet Scrubber 57.39% 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 1.5 ppmvd corrected to 3% O2 Calculated from lb/MMBtu based on 40 CFR Part 60 Appendix 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 5
Parameter Value Units Comments

Pre-Project Heat Input 97,258,307 MMBtu/yr See Table A 1.2Post-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/yrIncreased Power Demand due to New Emission Controls 348,025 MMBtu/yr

0.3% (see Table A-9) of the future projecfactor of 89.35% (see Table A-8) which ingrowth

Total Projected Future Fuel Use 116,356,289 MMBtu/yr Post-project heat input including demand 

increased power demand due to new em

Total Projected Capacity Factor 89.61%Projected Future Fuel Use Excluding Demand Growth 97,606,332 MMBtu/yr Pre-project heat input plus increased pow

to new emission controls

Projected Capacity Factor Excluding Demand Growth and Non-Project Related Changes 75.17%SO2 Emission Rate 0.1722 lb/MMBtu Same as baseline, no project related cha

SO2 Emissions 8,403.2 ton/yr Based on Projected Future Fuel Use Exc

Growth

NOx Emission Rate 0.0980 lb/MMBtu 40 CFR 49 BART Rule, 30-day rolling aveNOx Emissions 4,782.7 ton/yr Based on Projected Future Fuel Use Exc

Growth

PM Emission Rate 0.0132 lb/MMBtu Same as baseline, no project related chaPM Emissions 646.5 ton/yr Based on Projected Future Fuel Use Exc

Growth

PM10 Emission Rate 0.0222 lb/MMBtu

BACT - 92% of 0.015 lb/MMBtu plus 0.00condensable organics plus 0.00435 lb/MMacid mist emissions

PM10 Emissions 1,288.9 ton/yr Total emissions including demand growth

Basis for Demand Growth Exclusion (c) 0.0165 lb/MMBtu Baseline emission rate

Demand Growth Exclusion (c) 154.47 ton/yr Baseline emission rate x demand growthPM10 Emissions 1,134.4 ton/yr Excluding non-project related emissions

PM2.5 Emission Rate 0.0163 lb/MMBtu

BACT - 53% of 0.015 lb/MMBtu plus 0.00condensable organics plus 0.00435 lb/MMacid mist emissions

PM2.5 Emissions 948.5 ton/yr Total emissions including demand growth

 Table A-3 Projected Future Emission Calculation for Units 4 and 5 (a)
Parameter Value Units Comments

 Table A-3 Projected Future Emission Calculation for Units 4 and 5 (a)

Basis for Demand Growth Exclusion (c) 0.0113 lb/MMBtu Baseline emission rate

Demand Growth Exclusion (c) 106.04 ton/yr Baseline emission rate x demand growthPM2.5 Emissions 842.5 ton/yr Excluding non-project related emissions

Sulfuric 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 rate

Demand Growth Exclusion (c) 2.72 ton/yr Baseline emission rate x demand growth

Sulfuric Acid Mist Emissions 250.6 ton/yr Excluding non-project related emissionsCO Emission Rate 0.02969 lb/MMBtu Same as baseline, no project related chaCO Emissions 1,449.0 ton/yr Based on Projected Future Fuel Use Exc

Growth

VOC Emission Rate 0.000119 lb/MMBtu Same as baseline, no project related chaVOC Emissions 5.81 ton/yr Based on Projected Future Fuel Use Exc

Growth

Lead Emission Rate 2.36E-06 lb/MMBtu Same as baseline, no project related chaLead Emissions 0.115 ton/yr Based on Projected Future Fuel Use Exc

Growth

CO2 Emission Rate 205.2 lb/MMBtu Same as baseline, no project related cha

CO2 Emissions 10,013,236 ton/yr Based on Projected Future Fuel Use Exc

Growth

CO2e Emission Rate 206.8 lb/MMBtu Same as baseline, no project related cha

CO2e Emissions 10,094,124 ton/yr Based on Projected Future Fuel Use Exc

Growth

(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 emissionparagraph (b)(41) the operator shall exclude, in calculating any increase in emissions that results from the particular project, that portioemissions following the project that an existing unit could have accommodated during the consecutive 24-month period used to establisactual emissions under paragraph (b)(48) of this section and that are also unrelated to the particular project, including any increased utiproduct 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 economizer bypass which result in lower net power output. See Table A-9
gr/scf ton/yr 

Silo for Dry Sorbent Storage

Pneumatic Transfer to Silo with Fabric Filter Control

 2,000 2,000 10 0.0050 0.0857 

Silo for SCR Reagent Storage (a)

Pneumatic Transfer to Silo with Fabric Filter Control

 2,000 5,000 10 0.0050 0.2143 

(a) The SCR reagent silo will only be built if urea pellets are selected as the SCR reagent. Other reagent optionconsidered are 29% aqueous ammonia and anhydrous ammonia. There will be no emissions from SCR reageneither ammonia option is selected.

 Table A-4 Projected Emission Increase Calculation for Reagent Handling

Maximum PM PM10 PM2.5 Emis

Daily 

Operating 

Hours

Source Source Type Flow scfm Annual Operating Hours
Source Road 

Type

Vehicle 

Type

Trucks 

per 

Year

Trucks 

per 

Day

Truck 

Weight 

Empty 

(tons)

Truck 

Weight 

Full 

(tons)

Truck 

Weight 

Average 

(tons)

Length 

(m)

Length

(miles)

Avg 

vehicle 

weight 

(tons)

Silt 

Loading

 (g/m2)

PM 

before 

Control 

lb/VMT

PM 

Control 

Efficiency

PM 

Annual 

Emissions

(ton/yr)

PM Daily 

Emissions

(lb/day)

PM10 

before 

Control 

lb/VMT

PM10 

Control 

Efficiency

PM10 

Annual 

Emissions

(ton/yr)

PM10 

Daily 

Emission

s

(lb/day)

DSI 

Delivery 

Trucks

900 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 

Watering 

Trucks

Reagent 

Trucks 1500 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 

Watering 

Trucks

(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 * W1.02

k = 0.011 for PM, 0.0022 for PM10, 0.00054 for PM2.5

sL = silt loading (g/m2)

W = average vehicle weight

Table A-5.1 Projected Emission Increase Calculation for Reagent Delivery (DSI and 29% Aqueous Ammonia)

No increase

Delivery of Sorbent for Dry Sorbent Injection

Paved

Delivery of SCR Reagent (29% Aqueous Ammonia) (a)

Paved

No increase
Source Road 

Type

Vehicle 

Type

Trucks 

per 

Year

Trucks 

per 

Day

Truck 

Weight 

Empty 

(tons)

Truck 

Weight 

Full 

(tons)

Truck 

Weight 

Average 

(tons)

Length 

(m)

Length

(miles)

Avg 

vehicle 

weight 

(tons)

Silt 

Loading

 (g/m2)

PM 

before 

Control 

lb/VMT

PM Control 

Efficiency

PM 

Annual 

Emission

s

(ton/yr)

PM Daily 

Emissions

(lb/day)

PM10 

before 

Control 

lb/VMT

PM10 

Control 

Efficiency

PM10 

Annual 

Emissions

(ton/yr)

PM10 

Daily 

Emission

s

(lb/day)

C

DSI 

Delivery 

Trucks

900 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 

Watering 

Trucks

Reagent 

Trucks 

874 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 

Watering 

Trucks

(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 * W1.02

k = 0.011 for PM, 0.0022 for PM10, 0.00054 for PM2.5

sL = silt loading (g/m2)

W = average vehicle weight

Delivery of SCR Reagent (Urea Pellets) (a)

Paved

No increase

Table A-5.2 Projected Emission Increase Calculation for Reagent Delivery (DSI and Urea Pellets)

Delivery of Sorbent for Dry Sorbent Injection

Paved

No increase
Source Road 

Type

Vehicle 

Type

Trucks 

per 

Year

Trucks 

per 

Day

Truck 

Weight 

Empty 

(tons)

Truck 

Weight 

Full 

(tons)

Truck 

Weight 

Average 

(tons)

Length 

(m)

Length

(miles)

Avg 

vehicle 

weight 

(tons)

Silt 

Loading

 (g/m2)

PM 

before 

Control 

lb/VMT

PM Control 

Efficiency

PM 

Annual 

Emissions

(ton/yr)

PM Daily 

Emissions

(lb/day)

PM10 

before 

Control 

lb/VMT

PM10 

Control 

Efficiency

PM10 Annual 

Emissions

(ton/yr)

PM10 

Daily 

Emission

s

(lb/day)

DSI 

Delivery 

Trucks

900 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 

Watering 

Trucks

Reagent 

Trucks 

643 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 

Watering 

Trucks

(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 * W1.02

k = 0.011 for PM, 0.0022 for PM10, 0.00054 for PM2.5

sL = silt loading (g/m2)

W = average vehicle weight

Delivery of SCR Reagent (Anhydrous Ammonia) (a)

Paved

No increase

Table A-5.3 Projected Emission Increase Calculation for Reagent Delivery (DSI and Anhydrous Ammonia)

Delivery of Sorbent for Dry Sorbent Injection

Paved

No increase
NOx SO2 PM PM10 PM2.5 CO VOC H2SO4 Lead GHG 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 Baseline Emissions 24,029.2 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 Projected Future 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 5 Emission 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 Traffic Emission Change 0.0 0.0 0.0952 0.0190 0.0047 0.0 0.0 0.0 0.0 0.0SCR Reagent Truck Traffic Emission Change (worst case)

0.0 0.0 0.0871 0.0174 0.0043 0.0 0.0 0.0 0.0 0.0

DSI Sorbent Material Handling Emission Change

0.0 0.0 0.0857 0.0857 0.0857 0.0 0.0 0.0 0.0 0.0

SCR Reagent Material Handling Emission Change (worst case)

0.0 0.0 0.2143 0.2143 0.2143 0.0 0.0 0.0 0.0 0.0

Total Project Emission Change -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 for Significant Net Emission Rate

40 40 25 15 10 100 40 7 0.6 75,000

PSD Netting Required No No No Yes Yes No No Yes No NoContemporaneous Projects - Auxiliary Boilers

NA NA NA 0.96 0.96 NA NA 0.0 NA NA

Contemporaneous Projects - Shutdown of Units 1, 2, and 3

NA NA NA -551.5 -421.8 NA NA -3.1 NA NA

Total PSD Emission Change -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 No

Table A-6 FOUR CORNERS Unit 4 and Unit 5 SCR Project PSD Applicability

Emission Source 

Description

(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 the particular project, that portion of the unit's emissions following the project that an existing unit 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 growthSee details in Table A-3.NA = Not Applicable
NOx SO2 PM PM10 PM2.5 CO VOC Lead GH

(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 10Unit 4 and 5 Projected Future Emissions 4,782.7 8,403.2 646.5 1,134.4 842.5 1,449.0 5.808 1.15E-01 10Unit 4 and Unit 5 Emission Change -19,246.5 30.0 2.3 333.1 292.4 5.17 0.021 4.11E-04 3

DSI Sorbent Truck Traffic Emission Change 0.0 0.0 0.0952 0.0190 0.0047 0.0 0.0 0.0 

SCR Reagent Truck Traffic Emission Change (worst case) 0.0 0.0 0.0871 0.0174 0.0043 0.0 0.0 0.0 

DSI Sorbent Material Handling Emission Change 0.0 0.0 0.0857 0.0857 0.0857 0.0 0.0 0.0 

SCR Reagent Material Handling Emission Change (worst case) 0.0 0.0 0.2143 0.2143 0.2143 0.0 0.0 0.0 

Total Project Emission Change -19,246.5 30.0 2.79 333.5 292.8 5.2 0.021 4.11E-04 3Tribal Significant Net Emission Rate 10 10 10 5 3 10 5 0.1 Tribal NSR Netting Required No Yes No Yes Yes No No No Contemporaneous Projects - Auxiliary Boilers NA 0.05 NA 0.96 0.96 NA NA NA 

Contemporaneous Projects - Shutdown of Units1, 2, and 3 (b) NA -3,110.1 NA -551.5 -421.8 NA NA NA Total Emission Change -19,246.5 -3,080.1 2.79 -217.0 -128.1 5.2 0.021 4.11E-04 3Tribal NSR Applicable No No No No No No No No NA = Not Applicable

Emission Source Description

Table A-7 FOUR CORNERS Unit 4 and Unit 5 SCR Project Tribal Minor Source NSR Applica

(b) Annual average emissions for the years 2011 and 2012 based on APS CEMS data(a) Pollutants not subject to PSD
 Four 

Corners 

Unit 4 

 Four 

Corners 

Unit 5 

Heat Input

MMBtu/yr

2014 83.90 76.52 80.21 104,145,465

2015 90.73 71.45 81.09 105,286,324

2016 79.96 83.62 81.79 106,195,622

2017 61.15 81.88 71.51 92,855,1662018 86.65 62.75 74.70 96,992,2152019 84.67 82.34 83.50 108,421,857

2020 83.08 85.37 84.22 109,355,561

2021 92.85 85.85 89.35 116,008,264

2022 90.37 87.96 89.16 115,770,562

2023 65.79 90.32 78.06 101,348,267

2024 92.83 64.43 78.63 102,094,163

Capacity Factor

Year FCPP Average

Table A-8 FCPP Projected Capacity Factors including 

Demand Growth and Non-Project Related Factors
SCR Parasitic Load Calculation (a)

Parameter Units Value

Parasitic 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 Un

% of Operating Hours Needing Temperature Increase % 31.7% 24.1% 46.3% Temperature Increase Required °F 29.61 13.13 14.29 Weighted Average Temperature Increase Required °F 9.4 3.2 6.6 Operating Hours hr/yr 7,542 6,810 7,302 Average Non-zero MW MW 719.3 725.7 746.3 % Efficiency Loss/°F in Economizer %/°F 0.025% 0.025% 0.025% Total MWH Increase Due to Economizer Bypass MWh/yr 12,749 3,918 9,007 Heat Rate Btu/KWh 9,800 9,800 9,800 Total MMBtu Increase Due to Economizer Bypass MMBtu/yr 124,937 38,394 88,265 Approximate Unit MWH/yr MWh/yr 5,425,205 4,942,251 5,449,796 4Approximate Capacity Factor % 80.2% 73.3% 80.6% Approximate Unit MMBtu/yr MMBtu/yr 53,167,009 48,434,058 53,408,003 4Increase in MMBtu/yr due to Economizer Bypass % 0.235% 0.079% 0.165% 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. Thcan result in increased fuel use.

Table A-9 Estimated Increased Fuel Use due to SCR Parasitic Load and Economizer B

Comments

APS 2021 projected hours of operation at reduccapacity factor of 92.8%)APS 2021 projected hours of operation at reduccapacity factor of 85.8%)Information from Black & VeatchParasitic load / gross capacity x hours at reduceParasitic load / gross capacity x hours at reduce

(a) This calculation is intended to account for increased fuel use due to the SCR parastiic load. Fuel feed to the furnaces can onlperiods when they are operating at reduced load, When operating at full load, the fuel use cannot be increased; the net power ou
AECOM Environment 

60221977-460 April 2014

Appendix B 

RBLC Clearinghouse Data 
RBLCID FACILITY NAME CORPORATE OR

COMPANY NAME

FACILITY

COUNTY

FACILITY

STATE

PERMIT

ISSUANCE

DATE

FACILITY DESCRIPTION PROCESS NAME

PRIMARY

FUEL

THROUGHPUT THROUGHPUT

UNIT

CONTR

DES

SC‐0104

SANTEE COOPER

CROSS GENERATING

STATION

SANTEE COOPER BERKELEY SC 2/5/2004 ELECTRIC UTILITY BOILER, NO. 3 AND NO. 4 BITUMINOUS COAL 5,700 MMBTU/H Unit 3 ha

SCR and w

OK‐0118

HUGO GENERATINGSTA

WESTERFARMERSELECTRIC CCOP

CHOCTAW OK 2/9/2007 COAL‐FIRED STEAM EGU BOILER (HU‐ UNIT 2) PULVERIZED COAL FIRED ELECTRIC GENERATING UNIT COAL 750 MW SCR, BAG

FGD 

TX‐0585 TENASKA TRAILBLAZER

ENERGY CENTER

TENASKATRAILBLAZERPARTNERS LLC

NOLAN TX 12/30/2010 Coal‐fired electric generating facility Coal‐fired Boiler

Sub‐

bituminous

coal

8,307 MMBTU/H Wet scru

NotApplicable

Desert Rock

Generating Station

Public Service

Company of New

Mexico

NM Jul‐08 1,500 MW coal fired power plant Coal‐fired Boiler Coal Wet Scru

MI‐0389

KARN WEADOCKGENERATING COMPLEX

CONSUMERSENERGY BAY MI 12/29/2009

ELECTRICITY GENERATING FACILITY,

EXISTING CAPACITY GREATER THAN

2,000 MW.

BOILER

PRB COAL OR

50/50 BLEND 8,190 MMBTU/H

HYDRATEINJECTIO

FGD

UT‐0065

INTERMOUNTAINPOWER GENERATINGSTATION ‐ UNIT #3

INTERMOUNTAINPOWER SERVICECORPORATION

MILLARD UT 10/15/2004

NEW PULVERIZED COAL FIRED ELECTRIC

GENERATING UNIT #3, DESIGNED AT 950‐GROSS

MW (900‐NETMW) WITH A DRY BOTTOM,

TANGENTIALLY FIRED OR WALL‐FIRED BOILER.

UNIT #3 BOILER WILL BE EQUIPPED WITH WET

FLUE GAS DESULPHURIZATION, LNB, OVER FIRE

AIR, SELECTIVE CATALYTIC REDUCTION AND

BAGHOUSES FOR CONTROL OF VARIOUSEMISSIONS. THE EXISTING PLANT HAS TWO

DRUM‐TYPE, PULVERIZED COAL FIRED BOILERS,

DESIGNATED AS UNIT 1 AND UNIT 2, EACH WITH

950‐GROSS MW

PULVERIZED COALFIRED ELECTRICGENERATING UNIT

BITUMINOUS

OR BLEND

950 MW‐gross

BAGHOUFILTER AN

GASDESULPH

NotApplicable Cliffside Unit 6 Duke Rutherfird NC 1/29/2008 Supercritical PC Unit 6 High S coal 800 MW Spry drye

baghouse

*MI‐0399 DETROIT EDISON‐‐ MONROE DETROIT EDISON MONROE MI 12/21/2010 Utility‐‐Coal fired power plant Boiler Units 1, 2, 3 and 4 Coal 7,624 MMBTU/HR ESPs and 

desulfuriz

NotApplicable

Prairie State

Generation Station

Prairie State

GeneratingCompany

Washington MO 12/28/2005 Two power boilers with 1,500 MW total capacity burning high sulfur coal Two pulverized coal fired boilers Coal 7,450 MMBtu/hr each SCR, ESP, 

ESP 

Table B‐1 Sulfuric Acid Mist Emission Limits for Coal Fired Boilers
RBLCID FACILITY NAME CORPORATE OR

COMPANY NAME

FACILITY

COUNTY

FACILITY

STATE

PERMIT

ISSUANCE

DATE

FACILITY DESCRIPTION PROCESS NAME

PRIMARY

FUEL

THROUGHPUT THROUGHPUT

UNIT

CONTR

DES

Table B‐1 Sulfuric Acid Mist Emission Limits for Coal Fired Boilers

OH‐0310

AMERICAN MUNICIPAL

POWER GENERATINGSTATION

AMERICANMUNICIPALPOWER

MEIGS OH 10/8/2009

TWO 5191 MMBTU/HOUR PULVERIZED

COAL‐FIRED BOILERS; ONE 150

MMBTU/HOUR NATURAL GAS

AUXILIARY BOILER, ONE FLY ASH AND

GYPSUM LANDFILL, COAL STORAGE,

CRUSHERS, FERTILIZER PLANT,

LIMESTONE AND FLY ASH HANDLING

EQUIPMENT, AND COOLING CELLS.

BOILER (2),

PULVERIZED COALFIRED

PULVERIZED

COAL 5,191 MMBTU/H WET FLU

DESULFU

NotApplicable

ELM ROADGNEERATING STATION

WE ENERGY WI January 2004 and 5/31/2011 TWO PC UNITS, 615 MW EACH PC COAL FIRED BOILERS EASTERN COAL 6,180 MMBTU/HR EACH SCR, BAG

FGD, WET 
AECOM Environment 

60221977-460 April 2014

Appendix C 

Units 4 & 5 – Indirect Heat 

Exchanger 

H2SO4 CAM Plan 
AECOM Environment C-1

60221977-460 April 2014

Units 4 & 5 – Indirect Heat Exchanger –

H2SO4 Compliance Assurance Monitoring (CAM) Plan

This section contains the H2SO4 CAM plan being proposed for Units 4 and 5. The control train for Units 4 

and 5 includes an SO3 mitigation system, which is the primary control system used to minimize the 

formation and emission of H2SO4.

CAM Background

Table 1: Emission Unit and H2SO4 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 

capacities 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/hour of coal. Unit 4 was 

constructed in 1969 and Unit 5 was constructed in 1970.

H2SO4 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 SO3 mitigation system, a baghouse, and a wet FGD 

system. The SO3 mitigation system will be designed specifically to 

control SO3 and, subsequently, the formation of H2SO4 emissions.

Table 2: Applicable Regulations and Current Monitoring for H2SO4

Pollutant: H2SO4

Regulation: Expected PSD BACT emission limit to be issued pursuant to 40 CFR 

52.21(b)(12)

Emission Limit:

There currently is no H2SO4 emission limit in place for Units 4 and 5. 

The proposed BACT emission limits are 0.00435 lb/MMBtu which is 

equivalent to 1.5 ppmvd corrected to 3% O2.

Current Monitoring 

Requirements:

As there is currently no applicable H2SO4 emission limit, there are no 

current monitoring requirements specifically for H2SO4.

Table 3: Current Estimated Pre-Controlled and Controlled H2SO4 Emissions

CAM Designation: Large PSEU
AECOM Environment C-2

60221977-460 April 2014

CAM Applicability

The Units 4 and 5 boilers will be subject to a BACT emission limit for H2SO4 upon issuance of the PSD

permit. Pursuant to 40 CFR 64.2(a), because the SO3 mitigation system is used to achieve compliance 

with this emission limit and potential pre-controlled H2SO4 emissions (calculated at the exit of the air preheater) exceed 100 tpy, CAM applies to the Units 4 and 5 boilers for H2SO4. This CAM Plan addresses 

the proposed monitoring that will ensure compliance with the H2SO4 emission limit.

Monitoring Approach for H2SO4

SO3 is generated in the Units 4 and 5 boilers due to the oxidation of sulfur in the combustion process. 

Additional SO3 can be generated in the SCR unit due to catalytic oxidation of SO2 to SO3. The amount of 

SO3 generated is a function of coal sulfur content, operating conditions (e.g., gas temperature) and 

characteristics of the SCR system (e.g., catalytic material). SO3 reacts with water in the flue gas to form 

H2SO4 vapor, which then condenses to form sub-micron H2SO4 mist. APS will primarily utilize an SO3

mitigation system to control H2SO4 formation and emissions although the SO3 control attained in the other 

existing control devices for PM and SO2 namely the baghouses and wet FGDs, is also enhance the SO3

system.

The specific design and operation of the SO3 mitigation system has not yet been finalized, so APS is still 

working with 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 immediately downstream of the economizer. The sorbent 

reacts with the SO3 to form solid compounds (e.g., sodium sulfate), which are removed in the dry 

baghouses and wet FGD systems.

The effectiveness of the SO3 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 SO3 and/or H2SO4 in the flue gas is not technically feasible currently. Therefore, APS

proposes to use the sorbent injection rate as the primary indicator of performance of the SO3 mitigation 

system. Continuously monitored SO2 emissions will also be used as a secondary indicator parameter, 

since SO3 formation, and thus H2SO4 emissions, may be correlated to SO2 emissions.

APS is not in the position of having had a PSD construction permit issued, and initial compliance tests 

completed before the requisite CAM Plan 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 the anticipated 

H2SO4 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 H2SO4

Method Indicator Parameter Range Frequency

1. SO3 Mitigation 

System Monitoring

Sorbent Injection Rate 

(lb/hr/acfm)

To be established during 

initial performance test Continuous

2. SO2 Emissions 

Monitoring

SO2 Emission Rate (30-

day rolling average) <0.30 lb/MMBtu Continuous
AECOM 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 meter 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 information 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-annual monitoring reports.
AECOM Environment C-4

60221977-460 April 2014

Secondary Indicator #2 – SO2 Emission Rates

The Units 4 and 5 boilers will use a 40 CFR Part 75 compliant CEMS to continuously measure SO2 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 SO2 emission rates in terms of lb/MMBtu based on a 30-day average 

for the emission units. SO2 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 SO3 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 confirmation that the SO3 mitigation system is in 

operation. Because other variables associated with the operation of the SO3 mitigation system (e.g., size 

and characteristics of the sorbent) are relatively fixed upon start-up and reaching steady-state operation, 

maintaining the sorbent injection rate at a value that exceeds the lower threshold value established in the 

performance test will ensure that H2SO4 emissions are also kept to levels less than the permit limit.

During the initial performance test, APS will confirm that when the SO2 emission rate is below the 

allowable emission rate, the H2SO4 emissions are also below their allowable rate. Because SO2 and 

H2SO4 emissions should be correlated, SO2 should serve as a suitable surrogate for H2SO4 emissions. 

Therefore, continuous monitoring of SO2 at levels below its allowable rate will provide a level of 

assurance that the H2SO4 emissions also remain below the allowable rate.

Rational for Selecting Indicator Ranges

Because the specific vendor and design of the SO3 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 SO2 and H2SO4 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 H2SO4 emission rate (e.g., 

highest coal sulfur content and lowest SO3 sorbent injection rates). SO2 emissions will be continuously 

monitoring simultaneous with the H2SO4 emissions testing. The final test plan will detail the operating 

conditions and target sorbent injection rates that will be used during which H2SO4 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 

H2SO4 Source Test Report 
 

TEST REPORT

In-House Engineering Test

On Five

COAL FIRED UNITS

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 

Prepared By

TRC Environmental Corporation

7761 Shaffer Parkway Suite 100 

Littleton, Colorado 80127 

TRC Report No. 182436.INHE

April-September 2011
 

TEST REPORT

In-House Engineering Test

On Five

COAL FIRED UNITS

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 

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 O2 Determination ........................................................................................ 15

3.3 SO3 Determination ...................................................................................... 16

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

4.1 O2 Continuous Emissions Monitors ............................................................ 18

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

4.3 SO3 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

APPENDICES

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 

oF Degrees Fahrenheit 

BACT Best Available Control Technology 

CEMS Continuous Emission Monitor System 

CFR Code of Federal Regulations 

CO2 Carbon Dioxide 

CTM Conditional Test Method 

DSCFH Dry Standard Cubic Feet per Hour 

EPA Environmental Protection Agency 

H2O2 Hydrogen Peroxide 

H2SO4

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 

NOX Nitrogen Oxides 

O2 Oxygen 

PPMV Parts Per Million Volume 

QA/QC Quality Assurance/Quality Control 

SCF Standard Cubic Feet 

SCFH Standard Cubic Feet per Hour 

SO2 Sulfur Dioxide 

SO3 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 (SO3) 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). 

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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 

SO3 (ppmv dry) Stack 1 6/14/11 0.02 

SO3 (lb/hr) Stack 1 6/14/11 0.13 

SO3 (ppmv dry) Stack 2 4/7/2011 0.06 

SO3 (lb/hr) Stack 2 4/7/2011 0.34 

SO3 (ppmv dry) Stack 3 4/7/2011 <0.03 

SO3 (lb/hr) Stack 3 4/7/2011 <0.25 

SO3 (ppmv dry) Stack 4 4/6/2011 <0.05 

SO3 (lb/hr) Stack 4 4/6/2011 <0.89 

SO3 (ppmv dry) Stack 5 4/5/2011 <0.05 

SO3 (lb/hr) Stack 5 4/5/2011 <0.93 

SO3 (ppmv dry) APH Inlet 5 9/30/2011 2.07 

SO3 (lb/hr) APH Inlet 5 9/30/2011 48.48 

SO3 (ppmv dry) APH Outlet 5 9/30/2011 0.18 

SO3 (lb/hr) APH Outlet 5 9/30/2011 4.12 

SO3 (ppmv dry) Stack 5 9/30/2011 0.08 

SO3 (lb/hr) Stack 5 9/30/2011 1.76 

2
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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 

SO3 (lb/MMBTU) Stack 3 4/7/2011 <0.000094 

SO3 (lb/MWH) Stack 3 4/7/2011 <0.0011 

SO3 (lb/MMBTU) Stack 4 4/6/2011 <0.00014 

SO3 (lb/MWH) Stack 4 4/6/2011 <0.00113 

SO3 (lb/MMBTU) Stack 5 4/5/2011 <0.00014 

SO3 (lb/MWH) Stack 5 4/5/2011 <0.0013 

SO3 (lb/MMBTU) APH Inlet 5 9/30/2011 0.0064 

SO3 (lb/MWH) APH Inlet 5 9/30/2011 0.062 

SO3 (lb/MMBTU) APH Outlet 5 9/30/2011 0.00055 

SO3 (lb/MWH) APH Outlet 5 9/30/2011 0.0052 

SO3 (lb/MMBTU) Stack 5 9/30/2011 0.00023 

SO3 (lb/MWH) Stack 5 9/30/2011 0.0022 

3
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 – O2 Concentration 

EPA Method 4 – Stack Gas Moisture 

EPA Conditional Test Method 013– SO3 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 

O2 EPA Method 3A Continuous Analyzer 

Paramagnetic cell 

Sampling conducted using 

Tedlar Bags for some sources 

SO3 EPC CTM-013 Controlled Condensation Sample analysis by ion 

chromatograph 

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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 SO3. 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 SO3 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 SO3 and oxygen (O2). 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 SO3 were collected in the 

appropriate sample containers and shipped to a NELAC Accredited laboratory where they were 

analyzed for SO3 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 SO3. Three test runs of 120 minutes in duration were conducted on the unit 

while operating at normal load rates. SO3 and O2 concentration were collected and analyzed 

using the EPA Methods 3A and CTM-013. Samples for O2 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 SO3 were collected in the appropriate sample containers and 

shipped to a NELAC Accredited laboratory where they were analyzed for SO3 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 

5
Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

the unit. Each location was tested to determine the concentrations of SO3 and O2 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 O2 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 SO3 were collected in the 

appropriate sample containers and shipped to a NELAC Accredited laboratory where they were 

analyzed for SO3 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 SO3 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 SO3 were calculated from these volumetric flow rates and the 

corresponding concentration of SO3. 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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Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 (%) 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 SO2 (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

O2 (vol %, dry) 6.0 6.1 6.1 6.0

Moisture (%) 14.3 16.1 16.7 15.73

SO3 (ppmv, dry) 0.02 0.02 < 0.01 0.02

OUTLET EMISSION RATES

SO3 (lb/hr) 0.16 0.12 < 0.09 0.13

SO3 (lb/MMBTU) 0.000088 0.000065 < 0.000051 0.000068

SO3 (lb/MWH) 0.00095 0.00070 < 0.00055 0.00073

7
Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 (%) 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 SO2 (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

O2 (vol %, dry) 8.1 8.6 8.8 8.5

Moisture (%) 16.0 14.7 15.2 15.3

SO3 (ppmv, dry) 0.05 0.03 0.09 0.06

OUTLET EMISSION RATES

SO3 (lb/hr) 0.30 0.20 0.54 0.34

SO3 (lb/MMBTU) 0.00016 0.00011 0.00028 0.00018

SO3 (lb/MWH) 0.0017 0.0012 0.0031 0.0020

8
Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 (%) 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 SO2 (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

O2 (vol %, dry) 6.5 6.4 6.3 6.4

Moisture (%) 13.0 13.6 7.9 11.5

SO3 (ppmv, dry) <0.03 <0.03 <0.04 <0.03

OUTLET EMISSION RATES

SO3 (lb/hr) <0.21 <0.22 <0.32 <0.25

SO3 (lb/MMBTU) <0.000079 <0.000082 <0.000121 <0.000094

SO3 (lb/MWH) <0.0009 <0.0010 <0.0014 <0.0011

9
Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 (%) 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 SO2 (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

O2 (vol %, dry) 5.1 5.1 5.1 5.1

Moisture (%) 12.1 11.0 16.1 13.1

SO3 (ppmv, dry) 0.05 0.06 <0.04 <0.05

OUTLET EMISSION RATES

SO3 (lb/hr) 0.87 1.08 <0.72 <0.89

SO3 (lb/MMBTU) 0.00014 0.00017 <0.00011 <0.00014

SO3 (lb/MWH) 0.0011 0.0014 <0.00092 <0.0011

10
Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 (%) 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 SO2 (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

O2 (vol %, dry) 6.2 6.2 6.3 6.2

Moisture (%) 8.9 10.4 9.2 9.52

SO3 (ppmv, dry) <0.02 <0.03 0.09 <0.05

OUTLET EMISSION RATES

SO3 (lb/hr) <0.45 <0.64 1.71 <0.93

SO3 (lb/MMBTU) <0.000066 <0.000096 0.00025 <0.0001389

SO3 (lb/MWH) <0.00060 <0.00086 0.0023 <0.0012526

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Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 (%) 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 SO2 (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

O2 (vol %, dry) 6.1 6.1 5.9 6.0

SO3 (ppmv, dry) 2.15 1.78 2.28 2.07

OUTLET EMISSION RATES

SO3 (lb/hr) 50.10 41.66 53.67 48.48

SO3 (lb/MMBTU) 0.0067 0.0055 0.0071 0.0064

SO3 (lb/MWH) 0.0636 0.0529 0.0682 0.0616

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Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 (%) 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 SO2 (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

O2 (vol %, dry) 6.5 6.4 6.5 6.5

SO3 (ppmv, dry) 0.20 0.19 0.14 0.18

OUTLET EMISSION RATES

SO3 (lb/hr) 4.59 4.37 3.40 4.12

SO3 (lb/MMBTU) 0.00061 0.00058 0.00045 0.00055

SO3 (lb/MWH) 0.0058 0.0056 0.0043 0.0052

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Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 (%) 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 SO2 (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

O2 (vol %, dry) 6.1 6.2 6.1 6.1

SO3 (ppmv, dry) 0.10 0.07 0.06 0.08

OUTLET EMISSION RATES

SO3 (lb/hr) 2.32 1.64 1.31 1.76

SO3 (lb/MMBTU) 0.00031 0.00022 0.00017 0.00023

SO3 (lb/MWH) 0.0029 0.0021 0.0017 0.0022

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Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 Determination 

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

for the analysis of O2. 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 O2 samples were extracted by one of the 

following method of a single-point, integrated sampling tedlar bag as used in EPA Method 3. 

15
Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 

O2 Servomex 1400 01420C1/2534 

3.3 SO3 Determination 

The determination of stack gas concentrations of Sulfuric Acid (H2SO4) 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 SO3) and the 

sulfur dioxide (SO2) are separated using an H2SO4 condenser prior to the first impinger. As 

shown 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 (H2O2). 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. 

16
Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

Figure 3-1. CTM-013 Sample System Diagram 

17
Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

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 O2 Continuous Emissions Monitors 

The O2 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 O2. 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 O2 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. 

18
Emission Test Report

Five Coal Fired Units April-September 2011

Report No.: 182436.INHE

Table 4-1. Reference Method CEMS Performance Criteria 

Criteria 

O2 

(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 SO3 Sampling 

In accordance with EPA CTM-013 as referenced in NCASI Method 8A, the 3% H2O2

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% H2O2. 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. 

19
 

APPENDIX A– FIELD DATA SHEETS 

A1
A2
A3
A4
A5
A6
A7
A8
A9
A10
A11
A12
A13
A14
A15
A16
A17
A18
A19
A20
A21
A22
A23
A24
A25
A26
A27
A28
A29
A30
A31
A32
A33
A34
A35
A36
A37
A38
A39
A40
 

APPENDIX B– EXAMPLE CALCULATIONS 

B1
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 CSO3, corrected SO3 concentration (ppm) 385.3 ideal gas constant @ EPA STP (68 OF and 29.92 "Hg);

8.07 CO2, corrected O2 concentration (%) (scf / lb-mol)

2.77E+07 Qd, stack exhaust flow rate (DSCFH) 80.07 Molecular weight of SO3 (lb/lb-mol)

170.9 MWHr 29.92 EPA STP ( " Hg); Pref

1894 MMBTU/Hr 454 conversion, grams per pound

.

SO3 density factor, SO3

= 80.07 lb/lb-mol x 10-6

385.3 scf/lb-mol

= 2.08E-07 lb/scf

SO3 mass emission rate (lb/hr), ESO3 (lb/hr)

= CSO3 x Qd x DSO3

= 0.09 x 2.77E+07 x 2.08E-07

= 0.54 lbs/hr

SO3 mass emission rate (lb/MMBtu)

= SO3 (lb/hr) 

MMBTU/hr

= 0.5360

1894.10

= 0.0002830 lbs/MMBtu

SO3 mass emission rate (lb/MWHr)

= SO3 (lb/hr) 

MW-hr

= 0.54

170.9

= 0.0031 lb/MW-hr

SO3 Emission Rates

B2
Example Calculations

Refers to Test Run: Unit 2 Run 1

CX = raw concentration of component

CO = average of initial and final zero bias checks

CM = average of intial and final span bias checks

CMA = actual concentration of upscale calibration gas

CMA

CM - CO

Oxygen

CO2 7.97 %

CO 0.03 %

CM 9.86 %

CMA 9.99 %

9.86 - 0.03

CO2 = 8.07 %

CO2 = 7.97 - 0.03 * 9.99

Corrected Emission Concentrations (Equation 7E-5)

(Eq. 7E-1) CxCorrected = CX - CO

*

B3
EXAMPLE CALCULATIONS

Values may differ from Summary Tabes due to rounding and truncation.

Observed Data

154 = SO3 (μg) from analyses

80.07 = Molecular Weight of SO3 (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 μg to gr

1000000 = Conversion from μl to l

28.3 = Conversion from SCF to l

Example Calculations for Unit 2 Run 3

SO3 (ppmv) Calculation

Conc. SO3 (ppmv) = Conc SO3 (ug) X Volume of Gas per mol (l/gmol) X Conversion from μg to g

Molecular Weight of SO3 (gr/gmol) X Volume of Gas Collected (SCFH) X Conversion from l to SCFH X Conversio

= 154 X 24.04 X 1000000

80.07 X 17.57 X 28.3 X 1000000

= 0.09301 (ppmv)

B4
EXAMPLE CALCULATIONS:

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

B5
 

APPENDIX C – QUALITY ASSURANCE ACTIVITIES 

C1
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 1.00

dH (in. H2O)

Flow Rate (cfm)

Differential Pressure vs. Flow Rate

C2
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 1.00

dH (in. H2O)

Flow Rate (cfm)

Differential Pressure vs. Flow Rate

C3
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)

C4
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)

C5
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.

C6
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)

C7
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)

C8
Meter Box: Orifice Full Calibration

Date: 7/7/2011 Set Used: Brass Reference Orifice Set Orifice (#) K' Factor ( )

Prev. Calib. Date: 5/12/2011 Manufacturer:

Location: TRC Albuquerque Model:

Technician: JCC Tested By:

Meter Serial No: 997368

Meter Box ID: Meter Box ID: 610203

Atm. Pressure (corr. In Hg): Atm. Pressure (corr. In Hg): 24.85

Critical Vacuu Critical Vacuum + 2 in Hg: m + 2 in Hg: 14 in Hg (required minimum) in. Hg. (required minimum)

Prev Calib Factor (Y): Prev. Calib Factor (Y): 0 9815.

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#era ( b)see aove) (i H2O) (in. H2O) ( i)mn ( ft)cu ( ft)cu ( ft)cu (d F)eg (d F)eg (d F)eg (d F)eg (i H )n g (d F)eg (d F)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 21.0 270.307 270.307 280.112 280.112 9.805 87 87 89 88 20.0 91 91

55 0.4578 0.87 15.0 280.112 280.112 289.333 289.333 9.221 90 88 91 89 18.7 91 91

63 0.5940 1.50 10.0 289.333 289.333 297.275 297.275 7.942 91 90 92 90 17.5 91 91

Meter Box Dry Gas Meter Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume

Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume Calibration Calibration

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@)

Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation Meter Box

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il

Meter Box

(cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) C lib ti T t R lt Calibration Test Results Pass/Fail

5.14 145.60 0.319 5.06 143.30 0.984 -0.004 1.433 -0.16 * Average Y: Average Y: 0.9887 PASS

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: Ave. Y w/in 5% of previous value: YES

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: 0 95 >= Y <= 1 05: PASS

** Average dH: ** Average dH: 1 595. PASS

C it irera:

* 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 Differential Pressure vs. Flow Rate Fl R t

1.6

1.4

1 2.

1

O) H2 . O)

0 8.

(in. H2O H (in. H dH (in. dH (

0.6

d

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)

C9
Meter Box: Orifice Full Calibration

Date: 7/8/2011 Set Used: BRASS Reference Orifice Set Orifice (#) K' Factor ( )

Prev. Calib. Date: 5/12/2011 Manufacturer:

Location: TRC Albuquerque Model:

Technician: JCC Tested By:

Meter Serial No: 978517

Meter Box ID: Meter Box ID: 610204

Atm. Pressure (corr. In Hg): Atm. Pressure (corr. In Hg): 24.85

Critical Vacuu Critical Vacuum + 2 in Hg: m + 2 in Hg: 14 in Hg (required minimum) in. Hg. (required minimum)

Prev Calib Factor (Y): Prev. Calib Factor (Y): 1 0058.

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#era ( b)see aove) (i H2O) (in. H2O) ( i)mn ( ft)cu ( ft)cu ( ft)cu (d F)eg (d F)eg (d F)eg (d F)eg (i H )n g (d F)eg (d F)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 20.0 321.403 321.403 333.525 333.525 12.122 98 97 99 98 19.5 95 95

63 0.5940 1.6 10.0 333.525 333.525 341.382 341.382 7.857 99 98 100 98 18.0 95 96

Meter Box Dry Gas Meter Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume

Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume Calibration Calibration

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@)

Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation Meter Box

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il

Meter Box

(cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) C lib ti T t R lt Calibration Test Results Pass/Fail

4.94 139.93 0.313 5.04 142.79 1.020 0.004 1.582 -0.10 * Average Y: Average Y: 1.0167 PASS

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: Ave. Y w/in 5% of previous value: YES

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: 0.95 >= Y <= 1.05: PASS

** Average dH: ** Average dH: 1 677. PASS

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 Differential Pressure vs. Flow Rate Fl R t

1.8

1 6.

1.4

1.2

O)

1

H2O) . (inH2O H (in. H

0.8

dH (in. dH (

0 6

d

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)

C10
Meter Box: Orifice Full Calibration

Date: 7/8/2011 Set Used: BRASS Reference Orifice Set Orifice (#) K' Factor ( )

Prev. Calib. Date: 5/12/2011 Manufacturer:

Location: TRC Albuquerque Model:

Technician: JCC Tested By:

Meter Serial No: 978517

Meter Box ID: Meter Box ID: 610204

Atm. Pressure (corr. In Hg): Atm. Pressure (corr. In Hg): 24.85

Critical Vacuu Critical Vacuum + 2 in Hg: m + 2 in Hg: 14 in Hg (required minimum) in. Hg. (required minimum)

Prev Calib Factor (Y): Prev. Calib Factor (Y): 1 0058.

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#era ( b)see aove) (i H2O) (in. H2O) ( i)mn ( ft)cu ( ft)cu ( ft)cu (d F)eg (d F)eg (d F)eg (d F)eg (i H )n g (d F)eg (d F)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 20.0 321.403 321.403 333.525 333.525 12.122 98 97 99 98 19.5 95 95

63 0.5940 1.6 10.0 333.525 333.525 341.382 341.382 7.857 99 98 100 98 18.0 95 96

Meter Box Dry Gas Meter Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume

Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume Calibration Calibration

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@)

Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation Meter Box

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il

Meter Box

(cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) C lib ti T t R lt Calibration Test Results Pass/Fail

4.94 139.93 0.313 5.04 142.79 1.020 0.004 1.582 -0.10 * Average Y: Average Y: 1.0167 PASS

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: Ave. Y w/in 5% of previous value: YES

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: 0.95 >= Y <= 1.05: PASS

** Average dH: ** Average dH: 1 677. PASS

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 Differential Pressure vs. Flow Rate Fl R t

1.8

1 6.

1.4

1.2

O)

1

H2O) . (inH2O H (in. H

0.8

dH (in. dH (

0 6

d

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)

C11
Meter Box: Orifice Full Calibration

Date: 10/13/2011 Set Used: BRASS Reference Orifice Set Orifice (#) K' Factor ( )

Prev. Calib. Date: 7/8/2011 Manufacturer:

Location: TRC Albuquerque Model:

Technician: JCC Tested By:

Meter Serial No: 978517

Meter Box ID: Meter Box ID: 610204

Atm. Pressure (corr. In Hg): Atm. Pressure (corr. In Hg): 25.02

Critical Vacuu Critical Vacuum + 2 in Hg: m + 2 in Hg: 14 in Hg (required minimum) in. Hg. (required minimum)

Prev Calib Factor (Y): Prev. Calib Factor (Y): 1 0058.

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#era ( b)see aove) (i H2O) (in. H2O) ( i)mn ( ft)cu ( ft)cu ( ft)cu (d F)eg (d F)eg (d F)eg (d F)eg (i H )n g (d F)eg (d F)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 15.0 524.228 524.228 532.877 532.877 8.649 85 77 89 78 9.0 75 76

63 0.5940 1.3 18.0 532.228 532.228 545.710 545.710 13.482 88 77 94 80 7.2 76 76

Meter Box Dry Gas Meter Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume

Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume Calibration Calibration

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@)

Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation Meter Box

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il

Meter Box

(cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) C lib ti T t R lt Calibration Test Results Pass/Fail

4.96 140.58 0.301 5.17 146.37 1.041 -0.007 1.445 0.01 * Average Y: Average Y: 1.0485 PASS

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: Ave. Y w/in 5% of previous value: YES

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: 0.95 >= Y <= 1.05: PASS

** Average dH: ** Average dH: 1 431. PASS

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 Differential Pressure vs. Flow Rate Fl R t

1.4

1 2.

1

0.8

O) H2 . O) (in. H2O

0 6

H (in. H dH (in. dH (

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

0.20 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)

C12
Meter Box: Orifice Full Calibration

Date: 10/13/2011 Set Used: Brass Reference Orifice Set Orifice (#) K' Factor ( )

Prev. Calib. Date: 8/1/2011 Manufacturer:

Location: TRC Albuquerque Model:

Technician: JCC Tested By:

Meter Serial No: 90598

Meter Box ID: Meter Box ID: 90598

Atm. Pressure (corr. In Hg): Atm. Pressure (corr. In Hg): 24.98

Critical Vacuu Critical Vacuum + 2 in Hg: m + 2 in Hg: 14 in Hg (required minimum) in. Hg. (required minimum)

Prev Calib Factor (Y): Prev. Calib Factor (Y): 1 0150.

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#era ( b)see aove) (i H2O) (in. H2O) ( i)mn ( ft)cu ( ft)cu ( ft)cu (d F)eg (d F)eg (d F)eg (d F)eg (i H )n g (d F)eg (d F)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 11.0 988.647 988.647 993.632 993.632 4.985 69 68 69 68 14.0 62 62

55 0.4578 0.96 11.0 993.632 993.632 1,000.165 1,000.165 6.533 69 68 71 69 13.0 62 63

63 0.5940 1.70 10.0 1000.165 1000.165 1,007.792 1,007.792 7.627 71 68 71 69 11.5 63 64

Meter Box Dry Gas Meter Meter Box Dry Gas Meter Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume

Critical Orifice Dry Gas Meter Orifice

Volume Volume Volume Volume Calibration Calibration

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@)

Vm (std) Vm (std) Rate Vcr (std) Vm (std) Value Variation Value Variation Meter Box

( ft) (lit ) (CFM) ( ft) (lit ) (#) (#) (i H2O) (i H2O) P /F il

Meter Box

(cu ft) (liters) (CFM) (cu ft) (liters) (#) (#) (in H2O) (in H2O) C lib ti T t R lt Calibration Test Results Pass/Fail

3.87 109.52 0.309 3.92 111.08 1.014 0.000 1.723 -0.04 * Average Y: Average Y: 1.0138 PASS

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: Ave. Y w/in 5% of previous value: YES

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: 0 95 >= Y <= 1 05: PASS

** Average dH: ** Average dH: 1 758. PASS

C it irera:

* 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 Differential Pressure vs. Flow Rate Fl R t

1.8

1 6.

1.4

1.2

O)

1

H2O) . (inH2O H (in. H

0.8

dH (in. dH (

0 6

d

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)

C13
 

APPENDIX D – CALIBRATION CERTIFICATIONS 

D1
D2D3
D3D2
D4
D5
D6
 

APPENDIX E – LOGGED DATA RECORDS 

E1
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

E2
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

E3
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

E4
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

E5
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

E6
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

E7
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

E8
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

E9
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

E10
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

E11
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

E12
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

E13
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

E14
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

E15
 

APPENDIX F – UNIT OPERATIONAL DATA 

F1
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 5AAVO2NET90A5RAVWETO2VAL 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

F2
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

F3
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 88.8

F4
4GJ5NETMW 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 45.0

F5
06-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 43.6

F6
06-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 70.0

F7
3GJ5NETMWATT 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 52.14

F8
07-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 65.66

F9
2GJ5NETMWATT 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 0.0

F10
07-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 0.0

F11
07-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 60.7

F12
Unit 1 Unit 1

Net MW Relative Fuel Flow Boiler Exit % O2 Stack % O2 KSCFH ppm SO2 net BTU/KWH

Start Time End Time 1GJ5NETMWATT 1FFVTOTLFUELFL 1aAVSELO2 1RAVO2PERCENT 1RAVSTKGASFLOW 1RAVSO2PPM1MIN 1PA5HRA

14‐Jun‐11 10:00:00 14‐Jun‐11 11:00:00 170.2 56.5 2.35 7.62 1,924,691 42.7 10889.914‐Jun‐11 11:00:00 14‐Jun‐11 12:00:00 170.1 55.6 2.30 7.60 1,911,799 15.5 10816.114‐Jun‐11 12:00:00 14‐Jun‐11 13:00:00 170.4 55.4 2.31 7.57 1,914,660 49.9 10813.814‐Jun‐11 13:00:00 14‐Jun‐11 14:00:00 170.4 55.3 2.29 7.60 1,922,327 36.4 10790.714‐Jun‐11 14:00:00 14‐Jun‐11 15:00:00 170.8 55.1 2.30 7.59 1,930,471 41.4 10760.314‐Jun‐11 15:00:00 14‐Jun‐11 16:00:00 170.5 55.3 2.32 7.71 1,929,649 38.6 10803.414‐Jun‐11 16:00:00 14‐Jun‐11 17:00:00 170.4 55.4 2.29 7.63 1,927,279 39.0 10874.714‐Jun‐11 17:00:00 14‐Jun‐11 18:00:00 170.7 55.1 2.30 7.60 1,920,290 38.0 10878.7

Unit 5 Unit 5

Net MW Relative Fuel Flow Boiler Exit % O2 Stack % O2 KSCFM ppm SO2 net BTU/KWH

Start Time End Time 5GJ5NETMW 5FFXFUELFLOW 5AAVO2NET90AVG 5RAVWETO2VAL 5RAVAVGFLOW 5RAVSO2PPM1MIN 5PA5HRA

30‐Sep‐11 09:00:00 30‐Sep‐11 10:00:00 787.4 68.9 2.50 5.25 1,870.42 40.0 9554.130‐Sep‐11 10:00:00 30‐Sep‐11 11:00:00 787.6 68.6 2.48 5.93 1,874.31 52.1 9553.430‐Sep‐11 11:00:00 30‐Sep‐11 12:00:00 786.8 68.8 2.52 5.96 1,875.11 49.5 9574.830‐Sep‐11 12:00:00 30‐Sep‐11 13:00:00 787.2 69.0 2.50 5.91 1,879.14 46.9 9567.830‐Sep‐11 13:00:00 30‐Sep‐11 14:00:00 787.5 69.2 2.51 5.57 1,882.48 40.4 9568.530‐Sep‐11 14:00:00 30‐Sep‐11 15:00:00 788.3 69.3 2.49 5.90 1,886.53 46.7 9564.930‐Sep‐11 15:00:00 30‐Sep‐11 16:00:00 787.5 69.2 2.50 5.91 1,903.52 46.5 9577.830‐Sep‐11 16:00:00 30‐Sep‐11 17:00:00 787.7 68.8 2.49 5.90 1,908.88 45.5 9569.9

F13
 

APPENDIX G – LABORATORY ANALYSES DATA 

G1
 ANALYTICAL REPORT

CLIENT: TRC ENVIRONMENTAL, INC.

PROJECT:

ANALYTICAL SERVICES PROVIDED:

 SO3 (EPA METHOD 8A) 

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 the approved method(s). 

Date of Review: April 21, 2011 

J. Bruce Nemet

Quality Assurance Officer

178050: APS

G2
G3
Client: 

RFA #: 

Analysis: 

 H2O 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

G4
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 SO3

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

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:

G5
Client: TRC, Inc

RFA #: 178050

Analysis: EPA Method 8A

SO3 Analytical Data Sheet

Standard Manufacturer: AccuSpec m2: -6.49E-05 R2

: 0.9999827

Lot ID: SC8350362 m1: 

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 SO3

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

SO4 Standard Calibration Curve

2.43E-01

 Standard Areas

Internal Calibration Verification

Matrix Spike

G6
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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 15:15 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

1 - Sulfate - 4.103

G7
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Version 6.80 SR7 Build 2528 (148369)

2 DI H2O a

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/21/2011 11:33 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.110

G8
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Version 6.80 SR7 Build 2528 (148369)

3 DI H2O b

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/21/2011 11:42 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.100

G9
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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 15:41 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G10
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Version 6.80 SR7 Build 2528 (148369)

5 U5-1 b

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 15:51 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G11
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Version 6.80 SR7 Build 2528 (148369)

6 U5-2 a

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 16:01 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G12
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Version 6.80 SR7 Build 2528 (148369)

7 U5-2 b

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 16:10 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G13
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Version 6.80 SR7 Build 2528 (148369)

8 U5-3 a

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 16:20 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G14
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9 U5-3 b

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 16:30 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.103

G15
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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 16:40 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G16
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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 16:49 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.103

G17
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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 16:59 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G18
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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 17:09 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G19
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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 17:19 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G20
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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 17:29 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G21
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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 17:38 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G22
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Chromeleon (c) Dionex 1996-2006

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17 U3-1 b

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 17:48 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G23
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18 U3-2 a

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 17:58 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.103

G24
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19 U3-2 b

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 18:08 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.110

G25
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Version 6.80 SR7 Build 2528 (148369)

20 U3-3 a

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 18:18 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.113

G26
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Chromeleon (c) Dionex 1996-2006

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21 U3-3 b

Sequence ICS2000\JOBS\TRC\178050

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 18:27 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G27
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 18:37 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.113

G28
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 18:47 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G29
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 18:57 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G30
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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 19:06 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G31
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 19:16 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G32
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 19:26 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.107

G33
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 19:36 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.110

G34
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/20/2011 19:45 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

2 - Sulfate - 4.103

G35
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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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 Type: ASRS_4mm

Injection Volume: 25 μl Suppressor Current (mA): 85

Control Program: SO4 32mm

Quantif. Method: 32mm so4 Eluent Cartridge: EluGen-OH

Recording Time: 04/21/2011 11:52 Eluent Concentration (mM): 32

No. Ret.Time Peak Name Height 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

min

1 - Sulfate - 4.093

G36
 ANALYTICAL REPORT

CLIENT: TRC ENVIRONMENTAL, INC.

PROJECT:

ANALYTICAL SERVICES PROVIDED: 

 • SO3 

 (EPA METHOD 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 the approved method(s). 

Date of Review: August 22, 2011 

J. Bruce Nemet

Quality Assurance Officer

182068: APS Four Corners 

G37

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

G39
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 SO3

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.

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:

G40
Client: TRC, Inc.

RFA #: 182068: APS

Analysis: EPA Method 8A

SO3 Analytical Data Sheet

Standard Manufacturer: AccuSpec m2

: -6.49E-05 R

2

: 0.9999827

Lot ID: SC8350362 m1

: 

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 SO3

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

SO4 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

G41
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

8/19/2011 11:25 AM

Ilya-report test3/Integration

Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

1 10 PPM AUDIT a

Sequence ICS2000\Methods\Sulfate

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

1 - Sulfate - 3.543

G42
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Ilya-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 AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.550

G43
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

8/19/2011 11:25 AM

Ilya-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 AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.550

G44
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

8/19/2011 11:25 AM

Ilya-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 AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.553

G45
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

8/19/2011 11:25 AM

Ilya-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 AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.553

G46
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

8/19/2011 11:25 AM

Ilya-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 AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.553

G47
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

8/19/2011 11:25 AM

Ilya-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 AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.550

G48
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

8/19/2011 11:25 AM

Ilya-report test3/Integration

Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

8 SO2 MATRIX a

Sequence ICS2000\Methods\Sulfate

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.550

G49
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

8/19/2011 11:25 AM

Ilya-report test3/Integration

Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

9 SO2 MATRIX b

Sequence ICS2000\Methods\Sulfate

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.550

G50
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

8/19/2011 11:25 AM

Ilya-report test3/Integration

Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

10 10 PPM AUDIT b

Sequence ICS2000\Methods\Sulfate

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

1 - Sulfate - 3.550

G51
 ANALYTICAL REPORT

CLIENT: TRC ENVIRONMENTAL, INC.

PROJECT:

ANALYTICAL SERVICES PROVIDED: 

 • SO3 

 (EPA METHOD 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 the approved method(s). 

Date of Review: October 19, 2011 

J. Bruce Nemet

Quality Assurance Officer

182068: APS Four Corners 

G52

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

G54
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 SO3

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.

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:

G55
Client: TRC, Inc.

RFA #: 182068

Analysis: EPA Method 8A

SO3 Analytical Data Sheet

Standard Manufacturer: Ultra m2

: 2.07E-04 R

2

: 0.9999931

Lot ID: L00282 m1

: 

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 SO3

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

SO4 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

G56
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

10/19/2011 1:34 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\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

1 - Sulfate - 3.427

G57
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

2 APH IN 1 a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.430

G58
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

3 APH IN 1 b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

1 - Sulfate - 3.420

G59
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

4 APH IN 2 a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.430

G60
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

5 APH IN 2 b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.423

G61
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

6 APH IN 3 a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.423

G62
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

7 APH IN 3 b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.423

G63
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

8 APH OUT 1 a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.427

G64
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

9 APH OUT 1 b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.427

G65
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

10 APH OUT 2 a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.430

G66
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

11 APH OUT 2 b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.430

G67
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

12 APH OUT 3 a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.433

G68
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

13 APH OUT 3 b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.433

G69
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

14 STACK 1 a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.430

G70
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

15 STACK 1 b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.433

G71
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

16 STACK 2 a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.433

G72
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

17 STACK 2 b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.433

G73
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

18 STACK 3 a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.433

G74
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

19 STACK 3 b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.437

G75
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

20 SO3 MATRIX a

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.433

G76
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

21 SO3 MATRIX b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

2 - Sulfate - 3.430

G77
Operator:Resolution Analytics Timebase:ics2000 Sequence:SO4 32mM Page 1-1

10/19/2011 1:34 PM

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Chromeleon (c) Dionex 1996-2006

Version 6.80 SR7 Build 2528 (148369)

22 10 PPM AUDIT b

Sequence ICS2000\JOBS\TRC\182068

Column: IonPac AS18 4x250mm Suppressor Type: ASRS_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 Area 

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

min

1 - Sulfate - 3.430

G78