SALT RIVER PROJECT 

NAVAJO GENERATING STATION – UNITS 1, 2, 3 

SCR AND BAGHOUSE CAPITAL COST ESTIMATE REPORT 

SL-010214 

Revision D 

Prepared By: 

Project No. 12656-001 

August 17, 2010 
 

 

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Navajo Report SCR and BH Cost Est Rev D.docx August 17, 2010

Project No. 12656-001

NOTICE 

This Document was prepared by Sargent & Lundy, L.L.C., expressly for the sole use of Salt River 

Project in accordance with the agreement between S&L and Client. This Deliverable was prepared 

using the degree of skill and care ordinarily exercised by engineers practicing under similar 

circumstances. Client acknowledges: (1) S&L prepared this Deliverable subject to the particular scope 

limitations, budgetary and time constraints, and business objectives of the Client; (2) information and 

data provided by others may not have been independently verified by S&L; and (3) the information and 

data contained in this Deliverable are time sensitive and changes in the data, applicable codes, 

standards, and acceptable engineering practices may invalidate the findings of this Deliverable. Any 

use or reliance upon this Deliverable by third parties shall be at their sole risk.
 

 

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NAVAJO GENERATING STATION 

SCR AND BAGHOUSE CAPITAL COST ESTIMATE 

CONTENTS 

Section Page

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EXECUTIVE SUMMARY................................................................................................... ES-1 

1. General Plant Description ........................................................................................ 1-1

1.1 Description of Existing Plant........................................................................................ 1-1

1.2 Overview of Proposed Air Quality Control Systems (AQCS) ...................................... 1-1

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

2.1 General........................................................................................................................ 2-1

2.2 Meteorological Criteria ................................................................................................ 2-3

2.3 Industry Codes and Standards.................................................................................... 2-3

2.4 Supporting Documents................................................................................................ 2-3

3. Plant Mechanical Systems and Equipment............................................................. 3-1

3.1 Service Water System................................................................................................. 3-1

3.2 Potable Water System................................................................................................. 3-1

3.3 Fire Protection Systems .............................................................................................. 3-2

3.4 Plant and Instrument Air System................................................................................. 3-2

3.5 Flue Gas System......................................................................................................... 3-3

3.6 Sorbent Injection System ............................................................................................ 3-7

3.7 SCR............................................................................................................................. 3-8

3.8 Pulse-Jet Fabric Filter (Baghouse)............................................................................ 3-10

4. Plant Electrical Systems and Equipment................................................................ 4-1

4.1 Codes and Standards.................................................................................................. 4-1

4.2 Electrical Power Supply Systems................................................................................ 4-1

4.3 Basic Electrical System............................................................................................... 4-1

4.4 Auxiliary Power System Performance......................................................................... 4-2

4.5 Auxiliary Power System Equipment ............................................................................ 4-4

4.6 DC Power Supply System........................................................................................... 4-5

4.7 Uninterruptible AC Power System............................................................................... 4-6

4.8 Electrical Control and Protection................................................................................. 4-6

4.9 Communication System .............................................................................................. 4-6

4.10 Lighting and Maintenance Power System................................................................... 4-6

4.11 Grounding System....................................................................................................... 4-7

4.12 Lightning Protection System........................................................................................ 4-7

4.13 Cathodic Protection System........................................................................................ 4-7

4.14 Freeze Protection Systems ......................................................................................... 4-7

4.15 Auxiliary Power Requirements .................................................................................... 4-7
 

 

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CONTENTS, CONT. 

Section Page

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5. Plant Control Systems and Equipment ................................................................... 5-1

5.1 General........................................................................................................................ 5-1

5.2 SCR Option ................................................................................................................. 5-1

5.3 SCR and Baghouse Option......................................................................................... 5-2

6. Project Schedule ....................................................................................................... 6-1

6.1 introduction.................................................................................................................. 6-1

6.2 Project Milestones – SCR Option................................................................................ 6-1

6.3 Project Procurement – SCR Option ............................................................................ 6-2

6.4 Project Milestones – SCR and baghouse Option........................................................ 6-3

6.5 Project Procurement – SCR with Baghouse ............................................................... 6-4

7. General Arrangement Features................................................................................ 7-1

7.1 Common...................................................................................................................... 7-1

7.2 SCR Option ................................................................................................................. 7-1

7.3 SCR and Baghouse Option......................................................................................... 7-2

8. Utility Relocation....................................................................................................... 8-1

8.1 Plant Utilities................................................................................................................ 8-1

9. Plant Economics ....................................................................................................... 9-1

9.1 Basis of Cost Estimates .............................................................................................. 9-1

9.2 Capital Cost Estimates................................................................................................ 9-3

9.3 Budgetary Quotes ....................................................................................................... 9-4

9.4 O&M Costs.................................................................................................................. 9-6 

 9.5 Total Annual Costs.......................................................................................9-7 

10. Construction and Constructibility ......................................................................... 10-1

10.1 Construction Site Plan............................................................................................... 10-1

10.2 Installation Methodology............................................................................................ 10-2

10.3 Startup and Commissioning ...................................................................................... 10-5
 

 

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TABLES 

No./Title Page

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Table ES-1. Summary of SCR Only Capital Cost Estimate................................................................ES-3 

Table ES-2. Summary of SCR Only - With Dry Sorbent Injection-Capital Cost Estimate...................ES-4 

Table ES-3. Summary of 2007 Capital Cost Estimate-SCR Only (Including Outage Costs)..............ES-4 

Table ES-4. Summary of SCR and Baghouse Capital Cost Estimate ................................................ES-5 

Table ES-5. Summary of 2007 Capital Cost Estimate-SCR & Baghouse (Including Outage Costs)..ES-5 

Table ES-6. Levelized Annual Costs ..................................................................................................ES-6 

Table 2-1. SCR Design Criteria Summary.............................................................................................2-1

Table 4-1. Predicted Auxiliary Power Consumption...............................................................................4-8

Table 6-1. SCR Option Schedule Milestones ........................................................................................6-1

Table 6-2. Unit 3 SCR Option Critical Path............................................................................................6-2

Table 6-3. SCR and Baghouse Option Schedule Milestones ................................................................6-3

Table 6-4. Unit 3 SCR and Baghouse Option Critical Path....................................................................6-4

Table 9-1. Total Estimated Capital Cost Summary................................................................................9-4

Table 9-2. Conceptual O&M Costs (on a per Unit Basis) ......................................................................9-7 

Table 9-3. Levelized Annual Costs.........................................................................................9-8 
 

 

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APPENDIXES 

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Appendix A. Design Basis 

Appendix B. Capital Cost Estimate Equipment List 

Appendix C. Climate Data 

Appendix D. Piping and Instrumentation Diagrams 

Appendix E. Crane Placement 

Appendix F. Electrical Single-Line Diagrams 

Appendix G. Project Schedules 

Appendix H. Foster Wheeler Basis of Labor 

Appendix I. General Arrangement Drawings 

Appendix J. Conceptual Capital Cost Estimates 

Appendix K. Specification Summary Packages 

Appendix L. Master Procurement List 

Appendix M. Model Files 

Appendix N. Model Views 

Appendix O. SRP-Provided Data 

Appendix P. NPS Communications 

Appendix Q. Presentation for NPS 

Appendix R. Presentation for EPA 
 

 

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CERTIFICATION FOR REPORT 

FOR 

SALT RIVER PROJECT 

NAVAJO GENERATING STATION 

SCR AND BAGHOUSE CAPTIAL COST ESTIMATE 

I CERTIFY THAT THIS REPORT WAS PREPARED BY ME OR UNDER MY SUPERVISION AND THAT I 

AM A REGISTERED PROFESSIONAL ENGINEER UNDER THE LAWS OF THE STATE OF ARIZONA. 

Electronic copy of final document; 

Sealed original is with Arvind A. Patel 

Certificate No. 48573 

REVISION: CERTIFIED BY DATE 

 
 

 

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SALT RIVER PROJECT 

NAVAJO GENERATING STATION 

SCR AND BAGHOUSE CAPITAL COST ESTIMATE 

ISSUE SUMMARY PAGE 

PURPOSE OF ISSUE DATE PAGES AFFECTED 

REV. A, FOR COMMENT 04-16-2010 ALL 

REV. B, FOR USE 06-04-2010 ALL 

REV. C, FOR USE 08-06-2010 EXECUTIVE SUMMARY 

9.1.1 

9.1.10 

TABLE 9-1 

9.4 

TABLE 9-2 

9.5 

TABLE 9-3 

APPENDIX J – ALL 

APPENDIX P – NEW 

APPENDIX Q – NEW 

APPENDIX R – NEW 

REV. D, FOR USE 08-17-2010 EXECUTIVE SUMMARY 

1.2 

9.3.1 

 

 

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EXECUTIVE SUMMARY

The United States Environmental Protection Agency (EPA) is currently in the process of developing a 

Best Available Retrofit Technology (BART) proposal for the Navajo Generating Station (NGS). One of 

the five statutory factors that must be considered in arriving at a BART proposal is the cost of each 

control technology option. Salt River Project (SRP) retained Sargent & Lundy, L.L.C (S&L) to perform a 

detailed cost study that can be used in developing a BART proposal for NGS. Sargent & Lundy, L.L.C. 

prepared this report to present the estimated capital cost for the addition of SCRs or SCRs and 

baghouses on all three units at NGS. 

This report builds on the high-level feasibility studies that were performed by S&L in 2007 through 2009 

for a similar scope of work. The original feasibility studies provided predicted costs based on a level of 

difficulty of the installation at NGS compared to typical costs experienced in the industry for other SCR 

and polishing baghouse installations. This report provides more detailed conceptual designs and cost 

estimates for the work. 

For this report, S&L developed general arrangements, estimated quantities of materials, solicited 

budgetary quotes, and developed detailed cost estimates, schedules, and cash flows. Estimated 

quantities of materials were generated from the developed general arrangements. Since NGS is a 

highly congested site resulting in significant construction challenges, S&L had subcontracted Foster 

Wheeler to provide estimated construction costs, including costs for heavy-lift cranes, based on the 

general arrangements and estimated quantities. 

A total of nine cost estimates have been developed, three for each NGS unit consisting of; one estimate 

for SCR only (SCR Option), one estimate for SCR with dry sorbent injection (SCR with DSI Option), 

and one estimate for SCR plus baghouse (SCR and Baghouse Option). S&L and Foster Wheeler 

worked in conjunction to develop project schedules for the work. The schedule for the design and 

procurement work was developed by S&L while Foster Wheeler provided input to the construction 

portion. 

NGS consists of three (3) 812-MW (gross) CE/Alstom boilers that are fueled by Western bituminous 

coal from Peabody’s Kayenta mine on the Black Mesa. Currently, each unit utilizes a hot-side 

electrostatic precipitator (HESP) for particulate control and a wet flue gas desulfurization system (FGD) 

for SO2 control. The units are also being retrofitted with low-NOX burners (LNBs) to reduce NOX

emissions. S&L was asked to evaluate the cost of installing SCRs on each unit with an option to add 

polishing baghouses. The SCRs would tie into the flue gas path downstream of the existing HESPs and 

discharge upstream of the existing air pre-heaters. The baghouses would tie into the flue gas path 

downstream of the existing air pre-heaters and discharge upstream of the existing FGD systems. For 

the SCR and Baghouse Option, new ID booster fans would also be required. 

Major equipment added would be two (2) SCR reactors per unit, a common anhydrous ammonia 

storage facility, unit-specific sorbent injection systems, and two (2) baghouse casings per unit. Unit 2 

would incorporate a stacked baghouse design due to site space constraints. The work would include 

refurbishment of the existing ID fans for the SCR Option, or new ID booster fans for the SCR and 

Baghouse Option. All units would continue to discharge through their existing unitized stacks. 
 

 

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Several options were evaluated and estimated for the supply of power to the SCR and SCR plus 

baghouse system’s auxiliaries and ID fans. A new unit auxiliary transformer (UAT) would be installed to 

support new infrastructure for the SCR and Baghouse Option. 

Site constraints present a number of construction challenges. Major concerns include the congestion 

and limited access available for installation of the potential new work on Unit 2, as well as the tie-in 

work for the SCRs on all three units. The tie-in work for the SCRs must be accomplished in the 

relatively congested area between the precipitators and the boilers, where access to large construction 

equipment is limited and at the same time must be accomplished in a relatively short duration during 

scheduled plant outages. For installation of the Unit 2 work, large cranes that would be set up outside 

of the immediate construction area, yet be capable of placing large loads into the construction area, 

would be necessary. Additional challenges include construction of the unique stacked baghouses in the 

congested Unit 2 area, and performing the majority of the Unit 2 installation work immediately adjacent 

to, under, and over the existing coal conveyors that provide coal to all three of the units at NGS. 

In order to relocate existing plant utilities to make room for the SCRs and baghouses, a short duration 

outage (estimated at about one week) may be required early in the construction phase. Since this is not 

one of NGS’s regularly scheduled outages, lost generation costs associated with this outage have been 

included in the cost estimate. No costs have been added for lost generation during the eight week 

major outage since this is one of NGS’s regularly scheduled outages. 

Engineering studies, project development, procurement, detailed engineering, design, construction, and 

startup schedules have been developed, assuming a target commercial operation of Unit 3 during a 

future three-year series of major outages. Separate schedules have been prepared for the SCR Option 

and SCR and Baghouse Option. Multiple lump sum construction contracting is assumed for the 

foundations, structural and mechanical construction, electrical / instrument & controls construction, 

testing and inspection, and final sitework. The schedule is structured to utilize construction-quality bid 

documents for the procurement of ductwork, structural steel, and foundations. Separate construction 

contracts are assumed for each unit. 

The conceptual cost estimates developed for the report are based on the developed general 

arrangements, preliminary equipment list, estimated quantities of materials, and budgetary quotes from 

vendors for major equipment. Unit costs of materials and the remaining equipment have been 

estimated based on S&L in-house data, vendor catalogs, industry publications such as Means and 

Richardson, and costs on other similar projects. The construction costs have been developed with input 

provided by Foster Wheeler. The estimated costs are based on the year 2010 price level, and include 

costs of equipment, materials, craft labor, indirect labor, overtime, per-diem, contractor’s general and 

administrative costs, contractor’s profit, A-E engineering, construction management, start-up, 

commissioning, owner’s costs, contingency, and allowance for funds used during construction 

(AFUDC). The owner’s costs include owner’s construction management, spare parts, legal support, 

owner’s insurance, lost generation during short outages, ammonia unloading facility at railhead, and 

sales taxes. Future cost escalation is not included in the estimates. The contingencies included in the 

cost estimates are based on a risk analysis using Monte Carlo simulations to obtain a 95% confidence 

level of not exceeding the budget. The AFUDC is calculated based on 2.43% annual percentage rate. 

Preliminary cash flows have also been developed. 
 

 

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• Table ES-1 is a summary of the 2010 capital cost estimates for the SCR Only Option. 

• Table ES-2 is a summary of the 2010 capital cost estimates for the SCR Only - With Dry 

Sorbent Injection Option. 

• Table ES-3 is a summary of the 2007 capital cost estimates for the SCR Only Option. 

• Table ES-4 is a summary of the 2010 capital cost estimates for the SCR and Baghouse Option. 

• Table ES-5 is a summary of the 2007 capital cost estimates for the SCR and Baghouse Option. 

The overall costs developed in this study are similar to the costs developed in the 2007 through 2009 

high level feasibility studies. Costs for the SCR Only Option decreased from the earlier studies since it 

has been determined that the existing ID fan motors and auxiliary power system have adequate 

capacity to support the new SCR systems. Typically, implementation of an SCR system would be 

expected to require new ID Fans and new transformers; however, these costs would not be incurred for 

the NGS SCRs. The fan and auxiliary power upgrades would be required for the SCR and Baghouse 

Option, thus, the reduced costs are not seen in the estimates for the SCR and Baghouse Option. The 

relative costs for the Unit 3 installations are higher in the current study than in the earlier studies 

because costs for common systems that support all three Units have been allocated to Unit 3. This 

study is considerably more detailed than the earlier high level feasibility studies. 

The total annualized costs presented in the December 2008 BART Analysis have been updated to 

reflect the revised capital and annual O&M costs for the three different options. Table ES-6 presents 

the updated annualized costs. 

 Unit 1 Unit 2 Unit 3 & Common Total 

SCR (Includes Sitework) $ 50,386,000 $ 63,860,000 $ 60,661,000 $ 174,907,000 

Electrical and I&C $ 3,478,000 $ 3,888,000 $ 5,297,000 $ 12,663,000 

Construction Equipment & Scaffolding $ 11,471,000 $ 18,934,000 $ 14,091,000 $ 44,496,000 

Other Direct & Construction Indirect Costs $ 29,731,000 $ 41,879,000 $ 37,491,000 $ 109,101,000 

Indirect Costs $ 38,481,000 $ 50,135,000 $ 46,699,000 $ 135,315,000 

Contingency $ 15,224,000 $ 23,052,000 $ 18,559,000 $ 56,835,000 

AFUDC $ 3,054,000 $ 4,060,000 $ 3,730,000 $ 10,844,000 

Total Project Costs $ 151,825,000 $ 205,808,000 $ 186,528,000 $ 544,161,000 

$/kw (812MW Gross) $187 $253 $230 $223 

$/kw (750MW Net) $202 $274 $249 $242 

Table ES-1 Summary of SCR Only Capital Cost Estimates
 

 

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 Unit 1 Unit 2 Unit 3 & Common Total 

SCR (Includes Sitework) $ 51,931,000 $ 65,479,000 $ 62,201,000 $ 179,611,000 

Electrical and I&C $ 3,478,000 $ 3,883,000 $ 5,342,000 $ 12,703,000 

Construction Equipment & Scaffolding $ 11,617,000 $ 19,117,000 $ 14,253,000 $ 44,987,000 

Other Direct & Construction Indirect Costs $ 30,198,000 $ 42,442,000 $ 38,000,000 $ 110,640,000 

Indirect Costs $ 39,066,000 $ 50,825,000 $ 47,298,000 $ 137,189,000 

Contingency $ 15,537,000 $ 23,445,000 $ 18,882,000 $ 57,864,000 

AFUDC $ 3,119,000 $ 4,133,000 $ 3,796,000 $ 11,048,000 

Total Project Costs $ 154,946,000 $ 209,324,000 $ 189,772,000 $ 554,042,000 

$/kw (812MW Gross) $191 $258 $234 $227 

$/kw (750MW Net) $207 $279 $253 $246 

Table ES-2 Summary of SCR Only - With Dry Sorbent Injection - Capital Cost Estimates

Unit 1 Unit 2 Unit 3 & Common Total 

SCR Only $ 188,000,000 $ 254,000,000 $ 188,000,000 $ 630,000,000 

$/kw (812MW Gross) $232 $313 $232 $259 

$/kw (750MW Net) $251 $339 $251 $280 

Table ES-3 Summary of 2007 Capital Cost Estimate - SCR Only (Including Outage Costs)
 

 

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 Unit 1 Unit 2 Unit 3 & Common Total 

SCR (Includes Sitework) $ 49,653,000 $ 63,370,000 $ 60,514,000 $ 173,537,000 

Baghouse $ 71,095,000 $ 67,771,000 $ 52,948,000 $ 191,814,000 

Electrical and I&C $ 14,977,000 $ 14,831,000 $ 18,437,000 $ 48,245,000 

Construction Equipment & Scaffolding $ 29,345,000 $ 33,270,000 $ 26,577,000 $ 89,192,000 

Other Direct & Construction Indirect Costs $ 78,797,000 $ 85,736,000 $ 70,100,000 $ 234,633,000 

Indirect Costs $ 77,981,000 $ 86,030,000 $ 73,737,000 $ 237,748,000 

Contingency $ 42,484,000 $ 51,247,000 $ 38,092,000 $ 131,823,000 

AFUDC $ 7,852,000 $ 8,664,000 $ 7,464,000 $ 23,980,000 

Total Project Costs $ 372,184,000 $ 410,919,000 $ 347,869,000 $ 1,130,972,000 

$/kw (812MW Gross) $458 $506 $428 $464 

$/kw (750MW Net) $496 $548 $464 $503 

Table ES-4 Summary of SCR and Baghouse Capital Cost Estimates

Unit 1 Unit 2 Unit 3 & Common Total 

SCR & Baghouse $ 288,000,000 $ 434,000,000 $ 288,000,000 $ 1,010,000,000 

$/kw (812MW Gross) $355 $534 $355 $415 

$/kw (750MW Net) $384 $579 $384 $449 

Table ES-5 Summary of 2007 Capital Cost Estimate - SCR & Baghouse (Including Outage Costs)
 

 

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 SCR Option SCR with DSI 

Option 

 SCR & 

Baghouse Option 

Unit 1 Total Capital Cost $ 151,825,000 $ 154,946,000 $ 372,184,000 

Annual Capital Cost

(Total Capital Cost x CRF) $ 17,597,000 $ 17,958,000 $ 43,136,000 

Annual O & M Cost $ 3,982,000 $ 4,257,000 $ 6,878,000 

Total Annual Cost $ 21,579,000 $ 22,215,000 $ 50,014,000 

Unit 2 Total Capital Cost $ 205,808,000 $ 209,324,000 $ 410,919,000 

Annual Capital Cost

(Total Capital Cost x CRF) $ 23,853,000 $ 24,261,000 $ 47,626,000 

Annual O & M Cost $ 3,982,000 $ 4,257,000 $ 6,878,000 

Total Annual Cost $ 27,835,000 $ 28,518,000 $ 54,504,000 

Unit 3 Total Capital Cost $ 186,528,000 $ 189,772,000 $ 347,869,000 

Annual Capital Cost

(Total Capital Cost x CRF) $ 21,619,000 $ 21,995,000 $ 40,318,000 

Annual O & M Cost $ 3,982,000 $ 4,257,000 $ 6,878,000 

Total Annual Cost $ 25,601,000 $ 26,252,000 $ 47,196,000 

Units 

1,2,& 3 Total Capital Cost $ 544,161,000 $ 554,042,000 $ 1,130,972,000 

Annual Capital Cost

(Total Capital Cost x CRF) $ 63,069,000 $ 64,214,000 $ 131,080,000 

Annual O & M Cost $ 11,946,000 $ 12,771,000 $ 20,634,000 

Total Annual Cost $ 75,015,000 $ 76,985,000 $ 151,714,000 

Capital Recovery Factor (CRF) = 0.1159

Based on an interest rate of 9.8% and amortization period of 20 years

Table ES-6 Levelized Annual Costs

The results of this study addressed the input received from the National Park Service (NPS) and EPA 

Region 9. The NPS complemented the level of technical rigor that went into the cost engineering work 

and acknowledged the soundness of the overall study methodology. The NPS provided several 

observations regarding control levels and applicability of the EPA Pollution Control Cost Manual 

(PCCM) estimates. These comments and the responses are included in Appendix P. The PCCM was 

designed by EPA to be used on units 25MW to 600MW, and on “high dust” units that have only one 

reactor per combustion unit. NGS is larger than 600MW, would be a “low dust” application and would 

have two reactors per combustion unit. The PCCM cost model was not designed to be used on a unit 

similar to those found at NGS. But the NPS suggested that it might be helpful (while understanding the 

limitations of the PCCM) to calculate the cost using the PCCM so a relative comparison can be made 

between this project and other projects previously considered by EPA. When using the PCCM and 

adjusting the cost developed by a composite BLS price index, the PCCM predicts that the cost of an 

SCR on NGS Unit 1 in 2010 would be $47,844,624 or $64/kW (see Appendix P). Recent Surveys (data 

provided by NPS and public sources) of actual SCR installations show that costs for SCRs vary from 
 

 

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$100/kW to $300/kW. The cost developed in this study falls inside the reported range at $228/kW while 

the cost predicted by using the PCCM is outside the range. The NPS also participated in the July 20, 

2010 discussions with EPA. An NPS representative raised several questions that have been addressed 

in this report. These responses as well as responses to questions made by EPA in that meeting are 

also found in Appendix P. 
 

 

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1. GENERAL PLANT DESCRIPTION 

1.1 DESCRIPTION OF EXISTING PLANT 

NGS is located on the Navajo Indian Reservation near Page, Arizona. It consists of three (3) 

812-MW (gross) coal-fired units, which entered service in 1974, 1975, and 1976, respectively. 

NGS serves electric customers throughout the Southwest, and also supplies energy to pump 

water through the Central Arizona Project. 

The fuel for NGS is provided by Peabody Western Coal Company’s Kayenta Mine located 

approximately 50 miles to the east. The coal is delivered to the site via a dedicated rail from the 

coal mine to the plant. Cooling water for the station is supplied by nearby Lake Powell. 

Each of the three (3) existing units is equipped with stacked hot-side electrostatic precipitators 

(HESPs) for particulate control and FGD scrubbers for SO2 reduction. As part of a separate 

ongoing project, the units are also being retrofitted with low-NOX burners (LNBs) to reduce NOX

emissions. 

1.2 OVERVIEW OF CONCEPTUAL AIR QUALITY CONTROL SYSTEMS (AQCS) 

To further reduce NOX emissions, selective catalytic reaction (SCR) systems, proven control 

technology for reducing NOX, would be required. 

1.2.1 SCR Option 

As part of a Best Available Retrofit Technology (BART) assessment for NGS, SCR systems are 

being evaluated. An SCR system requires a catalyst, which uses anhydrous ammonia injection 

to react with NOX present in the flue gas. This is a proven control technology for reducing NOX. 

In order to limit the increase in sulfur trioxide/ sulfuric acid (SO3/H2SO4) emissions, catalyst 

with ultra-low SO2 to SO3 oxidation (< @ 0-5% across reactor) would be procured for use in the 

SCR. 

In the event sorbent injection is required for mitigating SO3 emissions associated with SCR, a 

further study would have to be conducted to determine if the existing FGD system can remove 

the additional particulates that would be formed. 

1.2.2 SCR and Baghouse Option 

Under the SCR and Baghouse Option, the existing HESPs would remain in service and new 

polishing baghouses would be installed downstream of the air preheater and upstream of the 

existing wet FGD systems. This type of system consists of fabric bags, which hang from a 

tubesheet, which then collect particulate on the surface of the bag. At periodic intervals, 

compressed air is piped through the bags, inflating them to remove the captured material off the 

bag to be collected in hoppers below each compartment. This reduces the amount of particulate 

emissions and is a proven emissions control technology. 
 

 

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To reduce sulfur trioxide (SO3) emissions, S&L evaluated the cost of dry sorbent injection (DSI) 

systems on each unit. This type of system consists of sorbent storage, sorbent feed, and 

sorbent injection systems, which use either a calcium- or sodium-based sorbent to react with 

SO3 present in the flue gas. This offers significant reduction in the amount of sulfuric acid 

(SO3/H2SO4) emissions. 
 

 

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2. DESIGN BASIS 

2.1 GENERAL 

Site-specific design basis and criteria documents were developed for mechanical, electrical, 

I&C, and civil/structural work. The design basis document used in the development of the cost 

estimate is provided in Appendix A. 

A summary of key design parameters for the SCR catalyst and ancillary equipment sizing has 

been provided in Table 2-1 below. The values in this table represent measured data, estimated 

concentrations based on engineering experience and judgment, estimated ammonia feed rates 

based on a specified slip, and the outlet NOx design point for maximum and minimum load. 

Table 2-1. SCR Design Criteria Summary 

SCR Design Criteria (Values typical for all Units) Units Maximum 

Load 

Minimum 

Load 

a. Load MW 812 403 

b. Heat Input to Boiler MBtu/hr 7,350 3,650 

c. Flue Gas Mass Flow Rate lb/hr 7,308,000 3,629,000 

d. Flue Gas Vol. Flow Rate acfm 4,179,000 1,813,800 

e. Pressure at SCR Inlet in. w.g. -11.25 -11.25 

f. Flue Gas Temperature at SCR Inlet °F 670 500 

g. Economizer Bypass -- Yes* 

h. Inlet NOx lb/MBtu 0.24 0.17 

i. Outlet NOx lb/MBtu 0.05 0.05 

k. SO2 Concentration at SCR Inlet ppmvd 621 602 

l. SO3 Concentration at SCR Inlet ppmvd 3.74 3.63 

m. Ammonia Injection Required lb/hr 550 173 

n. Design Ammonia Slip ppmvd 

@ 3% O2

2 2 

o. Estimated Flue Gas Composition to 

SCR 

 

 N2 vol% 71.45 71.59 

 O2 vol% 2.87 3.35 

 H2O vol% 11.81 11.58 

 CO2 vol% 13.79 13.40 

 SO2 ppmv 547 532 

 SO3 ppmv 3.30 3.21 

 HCl ppmv 0 0 

 HF ppmv 0 0 

* An Economizer bypass will be required to maintain minimum flue gas temperature of 580°F at the inlet of 

the SCR. 
 

 

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Table 2-2. SCR Option Design Emissions 

Emission lb/mmBtu 

NOX Current Permit 

Current Operation 

SCR Design 

0.24 (1)

0.20 to 0.22 (1)

0.05 

 Notes: (1) Based on LNB in operations 

Table 2-3. SCR and Baghouse Option Design Emissions 

Emission lb/mmBtu 

NOX Current Permit 

Current Operation 

SCR Design 

0.24 (1)

0.20 to 0.22 (1)

0.05 

Particulate matter: 

Total PM10

Current Emissions 

Proposed Emissions 

0.06 

0.015 (2)

 Notes: (1) Based on LNB in operations 

 (2) Based on polishing fabric filter. 

2.1.1 NOx Control 

NOX emissions would be controlled using SCR technology. The SCR system would be designed 

under ideal operating conditions to achieve an actual NOX emission rate of approximately 0.05 

lb/mmBtu to ensure compliance with an anticipated NOX limit of 0.07-0.08 lb/mmBtu on a 30-day 

rolling average. Margin is provided between the design target and the anticipated NOx limit to 

allow for normal operating fluctuations associated with minor equipment upsets, fuel 

characteristics impacting NOX generation, and SCR process delays due to load changes. 

2.1.2 Particulate Control 

Particulate emissions would be controlled on all three NGS units using the existing HESPs. The 

HESP systems have been designed to achieve an actual PM emission rate to ensure 

compliance with an anticipated PM limit of 0.05 lb/mmBtu on a 30-day rolling average. Margin is 

provided between the design target and the anticipated limit to allow for normal operating 

fluctuations associated with minor equipment upsets, fuel characteristics, and load changes. 

2.1.3 Sulfuric Acid Mist Control 

As a result of the potential installation of the new SCRs on all three NGS units to reduce NOX

emissions below the projected permit limit, the uncontrolled sulfuric acid mist emissions would 

be expected to increase due to SO2 oxidation across the catalyst. In an effort to reduce the 

sulfuric acid mist emissions, the following measures are being considered: 
 

 

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1. Design the SCR for ultra-low SO2 to SO3 conversion catalyst which will limit SO2 oxidation to 

below 0.5% across the reactor. This is expected to increase the particulate loading entering 

the wet FGD system. The wet FGD system is expected to capture some portion of this 

particulate matter, which may be significant enough to prevent increasing the plant’s 

particulate emissions above a level that would affect the plant permit. 

2. If ultra-low conversion catalyst alone is not capable of preventing a significant increase in 

plant emissions of particulate matter, sorbent would be injected upstream of the existing wet 

FGD systems to react with the sulfuric acid to form sodium- or calcium sulfate. The WFGD 

system would again be required to capture the generated solids to prevent a significant 

increase in particulate emissions. 

3. In the event that sorbent injection upstream of the WFGD system is not sufficient enough to 

prevent a significant increase in particulate emissions, pulse jet fabric filters would be 

installed upstream of the existing WFGD systems. Sorbent would be then injected and the 

resultant particulate captured in the baghouses. 

2.2 METEOROLOGICAL CRITERIA 

Site-specific meteorological criteria were included in the design basis and are provided in 

Appendix C. 

2.3 INDUSTRY CODES AND STANDARDS 

Systems, structures, and equipment would meet the latest codes and standards within the 

design basis in Appendix A. 

2.4 SUPPORTING DOCUMENTS 

Existing plant documentation, drawings, and operational data were utilized. These documents 

are listed in Appendix A. Select documents are included in Appendix O for future reference. 
 

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3. PLANT MECHANICAL SYSTEMS AND EQUIPMENT 

3.1 SERVICE WATER SYSTEM 

Based on S&L’s experience with SCR and baghouse retrofit projects, the ancillary systems for 

the SCR and baghouse have minimal service water demands. It is assumed that the existing 

plant service water system has adequate pressure and flow margin to meet the water 

requirements of the SCR Option or SCR and Baghouse Option. 

3.1.1 SCR Option 

For the SCR Option, service water would be utilized for wash down hose stations in the SCR 

area, as well as in the ammonia unloading area. 

3.1.2 SCR and Baghouse Option 

In addition to the service water requirements for the SCR Option, the SCR and Baghouse 

Option requires service water at wash down stations within the baghouse area and ID booster 

fan area. Service water would also serve as the cooling medium for the baghouse pulse-jet 

compressors; approximately 150 gallons per minute (gpm) per unit would be required for 

compressed-air cooling. The cooling water would be discharged to a local collection sump and 

admitted to the FGD process via the mist eliminator wash water tank. 

3.2 POTABLE WATER SYSTEM 

This cost estimate assumes that the existing plant potable water system has adequate pressure 

and flow margin to support additional users for the SCR Option or SCR and Baghouse Option. 

3.2.1 SCR Option 

The expected additional potable water users for the SCR include eyewash/emergency shower 

for the anhydrous ammonia storage area. 

3.2.2 SCR and Baghouse Option 

In addition to the potable water users for the SCR Option, the SCR and Baghouse Option 

requires potable water for eyewash/ emergency shower for the sorbent unloading area, as well 

as the waste silo area. 

Each of the eyewash stations and emergency showers stated above would require 

approximately 5-20 gpm. The new potable water distribution header for ancillaries would tie into 

the existing potable water header and be supplied by a new 2-inch, heat-traced, stainless steel 

header. 
 

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3.3 FIRE PROTECTION SYSTEMS 

Fire protection for new emissions control equipment would be provided by the existing NGS fire 

protection system; this includes fire pumps, yard piping, and hydrants. It is assumed the existing 

fire protection system has sufficient capacity to meet these new demands. 

3.3.1 SCR Option 

Fire protection for the SCR and auxiliary equipment would require fire hydrants located within 

50 feet of the SCR structure. The fire protection header would also be extended to the new 

ammonia unloading area and supply quench water for ammonia leak protection as well as an 

additional hydrant for fire protection in the area. 

3.3.2 SCR and Baghouse Option 

Fire protection for the baghouse and auxiliary equipment would require fire hydrants located 

within 50 feet of the baghouse structure. The baghouse would be designed with polyphenylene 

sulfide (PPS) fabric bags to minimize fire potential. PPS fabric bags are neither flammable nor 

combustible. A fire water standpipe would provide water to the penthouse area for use during 

outages when flammable materials may be present. 

The existing fire protection system would also be extended to the new unit auxiliary 

transformers (UATs) deluge system. 

Below-grade fire protection piping would be either 8-inch or 10-inch SDR 9 HDPE piping and 

would be buried below frost depth per National Fire Protection Association (NFPA) codes. 

Above-ground fire protection piping would be carbon steel. 

3.4 PLANT AND INSTRUMENT AIR SYSTEM 

3.4.1 SCR Option 

This cost estimate assumes the existing plant compressed air systems have adequate capacity, 

flow, and pressure margin, to meet the demand of new users for the SCR addition. However, 

air receivers would be added to support the sonic horns used to clean the catalyst. 

3.4.2 SCR and Baghouse Option 

The addition of the baghouse adds a large air user to the plant. To meet the air consumption 

requirements for the pulse-jet cleaning system of the baghouse, 2 x 100%, oil-free, centrifugal 

compressors would be added per unit. These compressors would also provide compressed air 

to all new intermittent-user (valves, instruments, tools, etc.); therefore, no additional 

compressed-air load would be added to the existing plant compressed air systems. All air would 

be dried to -40°F dew point by implementing 2 x 100%, heated blower, purge-type regenerative 

desiccant dryers. 

All instrument air piping would be stainless steel. All service air piping would be carbon steel. 
 

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Refer to sketches MSK-1002-01, MSK-1002-02, MSK-1002-03, MSK-2002-01, MSK-2002-02, 

MSK-2002-03, MSK-3002-01, MSK-3002-02 and MSK-3002-03 in Appendix D for conceptual 

design. 

3.5 FLUE GAS SYSTEM 

3.5.1 General Ductwork 

For the purposes of the capital cost estimate, all existing ductwork is considered to be capable 

of safely withstanding its original design conditions. No degradation of the ductwork from 

corrosion or other deleterious effects is considered to be present in the system, and no 

resources are proposed for a condition assessment of the existing ductwork or for reinforcement 

of the ductwork due to loss of material from corrosion or similar effects. 

All new ductwork would be sized to achieve a flue gas velocity of approximately 60 feet per 

second (fps). In areas where new ductwork would be restricted in size due to space constraints 

placed by existing items, higher velocities would be experienced. Thicker duct plate would be 

used to account for erosion in areas where the velocity exceeds 90 fps. 

3.5.2 SCR Option Ductwork 

The new ductwork to and from the SCR systems would exit the existing system downstream of 

the HESPs and would tie back in upstream of the air heaters. These tie-ins would occur in the 

available space between the existing boiler building and the HESPs. For Units 1 and 3, common 

ducts would be routed to and from SCR systems that are located side-by-side to one side of the 

unit, to the north for Unit 1, and to the south for Unit 3. For Unit 2, the SCR systems would be 

separated from each other because of space constraints in this congested area, and separate 

ductwork would run on the north and the south sides of the HESP to and from the separate SCR 

systems placed to the north and south of the Unit 2 chimney. 

Revised internal pressures in the existing flue gas ductwork that would result from adding the 

new SCR systems into the system and modifying the existing ID Fans would require 

reinforcement of the existing ductwork downstream of the added SCR systems. Sufficient 

controls on the existing ID Fans would ensure that there are no changes to internal pressures in 

the existing ductwork upstream of the SCR systems, back to and including the boiler; therefore, 

no reinforcement would be needed for this portion of the ductwork because of revised 

pressures. 

3.5.3 SCR and Baghouse Option Ductwork 

The new ductwork to and from the baghouses would exit from and return into the existing 

ductwork in the area of the abandoned chimneys that runs from the existing ID Fans to the FGD 

area. For both Units 1 and 3, common ducts would be routed to the two baghouses that would 

be located side-by-side to one side of the unit, to the north for Unit 1, and to the south for Unit 3, 

and then on to two ID Booster Fans, also placed side-by-side, before returning to the existing 

ductwork that leads into the FGD system. For Unit 2 the baghouses would be stacked due to the 

extreme congestion in the area and the new ID Booster Fans would be separated, but the 
 

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ductwork routing, though complicated by the tight arrangement, would be essentially the same 

as on the other two units. 

Refer to sketches MSK-1005-01, MSK-1005-02, MSK-2005-01, MSK-2005-02, MSK-3005-01 

and MSK-3005-02 in Appendix D for conceptual design. 

3.5.4 SCR Option Mechanical 

Currently, the NGS flue gas path contains four (4) centrifugal ID fans arranged in parallel. The 

original maximum continuous rating (MCR) of these fans is 675,000 acfm at 33.8 inwg. Postscrubber installation, NGS performed an As-Tested Condition for the ID fans and the results 

identified the new duty point as 895,103 acfm at 31.41 inwg., with a motor operating point of 

6,143 horsepower (hp). 

Based on preliminary calculations, the existing ID fans would require modifications to support 

installation of the new SCR systems. The existing rotating element would be replaced with a 

new rotor assembly (impeller, shaft, and bearings). The new rotating element would be tipped to 

meet the additional pressure drop requirements of the SCR. Typically, tipping a centrifugal ID 

fan would result in the following performance increases: 7.5% flow, 15% pressure, and 27.5% 

brake horsepower. The increased flow and pressure requirements that would be seen by the 

addition of an SCR are within the 7.5% and 15% increases. The larger horsepower requirement 

is acceptable for the existing fan motor. See Section 4.0 for additional information on the 

electrical systems. 

The existing air heater would need to be evaluated to determine if it would properly perform at 

the modified ID fan duty point or need other modifications to address ammonium bisulfate 

fouling or acid condensation associated with the SCR. The cost estimate includes allowances to 

perform an air heater evaluation and structural reinforcement. These allowances would be 

refined upon detailed engineering and evaluation by the original air heater manufacturer. 

3.5.5 Air Heater Evaluation 

3.5.5.1 Ammonium Bisulfate Formation 

The application of SCR technology to coal fired power plants creates a potential problem with 

the deposition of ammonia-sulfur salts in the air preheater. The vanadium/titanium-based 

catalyst will oxidize a portion of the sulfur dioxide in the flue gas to sulfur trioxide. Under certain 

temperature and concentration conditions, the sulfur trioxide will react with ammonia slip from 

the SCR reactor to form ammonium bisulfate (ABS) which will tend to deposit in the air 

preheater. If favorable conditions for this reaction persist and ammonia concentrations reach 

higher than the designed value of 2 ppmvd, frequent washings of the air preheater may be 

required. 

The installation of an SCR system will result in a small amount of ammonia gas and an increase 

in sulfur trioxide gas over the current level entering the air preheaters. Currently, sulfur trioxide 

(SO3) calculations and test data performed for these Units show that the SO3 is approximately 4 

ppmvd at 3% O2 entering the APH. The catalyst for the new SCR systems would be specified 
 

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with a maximum SO2 conversion of 0.50% for the entire system. This results in an SO3

concentration at the APH of approximately 6 ppmvd at 3% O2. Under certain conditions, SO3

and ammonia will react to form ammonium bisulfate (ABS) according to the following reaction: 

NH3 + SO3 + H2O = NH4HSO4

ABS will condense from the gas stream and form a sticky deposit on the heat transfer surface of 

the air heater at a temperature of 380 – 450 °F. Fly ash particles will tend to stick to the ABS 

resulting in the gradual pluggage of the APH. Depending on the degree of formation, this could 

result in an increase in APH pressure drop (impacting ID fan capacity) as well as a loss in 

thermal efficiency for the plant. 

ABS is also corrosive (acidic in nature) and will corrode the mild steel or low alloy steel surfaces 

of the APH. The rough surface of corroded material further enhances the deposition of 

ammonium bisulfate and accelerates the plugging mechanism. 

3.5.5.2 Ammonium Bisulfate Impact on Navajo SCR Systems 

Combustion of the design fuel and SCR installation will result in the following gas conditions 

leaving the economizer and entering the APH. 

 Economizer Outlet SCR Outlet/APH Inlet 

Temperature at Full Load (°F) 670 673 

SO3 Concentration (ppmvd @ 3% O2) 3.72 6.18 

The oxidation of SO2 to SO3 is controlled by the catalyst formulation; the catalyst must be 

formulated to restrict oxidation of SO2 to control SO3 production which could accelerate ABS 

formation and/or create a visible sulfuric acid plume. A design of 2 ppmvd (@ 3% O2) ammonia 

slip at the end of catalyst life and an oxidation rate of 0.50% across the reactor was chosen to 

minimize SO3 formation to prevent any substantial increase in sulfuric acid emissions. Low 

ammonia slip also minimizes the nitrogen content in scrubber water blowdown. If SO3 is limited 

to less than 7 ppm, the possibility of having blue plume is eliminated. 

The concentration of ammonia and SO3 will vary across the cross sectional area of the reactor 

exit. If areas with higher concentrations of NH3 coincide with areas of high SO3 concentrations 

then ABS may form in localized areas of the air preheater. This phenomenon must be taken into 

consideration when selecting APH protection such as enameled coatings. A typical formation 

diagram for ammonium bisulfate is shown in Figure 1. 
 

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The ABS dew point while burning bituminous fuel will be in the temperature range of 590 °F to 

615 °F. The melting point of this compound is 300 °F and the boiling point is 914 °F. Once this 

compound is formed, it will be in liquid phase above 300 °F and the solid phase below 300 °F. 

Therefore, all metal surfaces of the APH from 300 °F to 615 °F will be subjected to ammonium 

bisulfate deposition. 

The following conclusions can be drawn from Figure 1: 

• The formation diagram for ammonium bisulfate suggests the potential formation of ABS 

in the air preheater. 

• The likelihood of ammonium bisulfate formation is higher at the end of catalyst life 

when firing the higher sulfur fuels, when the ammonia slip would be close to 2 ppm in 

conjunction with approximately 6 ppmvd SO3. 
 

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The following design elements for the Navajo SCR system are important to reduce the likelihood 

that ammonia bisulfate formation will be a significant problem: 

• Ensuring proper catalyst design, including 2 ppm ammonia slip and maximum 0.50% 

oxidation of SO2 to SO3 across the SCR reactor. 

• Ensuring NH3/NOx distribution requirements are demonstrated in the CFD and physical 

flow modeling to avoid large areas of high ammonia slip. 

3.5.5.3 Air Heater Basket Recommendation 

Based on normal catalyst performance, NH3 slip should range from a negligible value during 

initial operation to less than 2 ppm towards the end of the catalyst life. After the SCR 

installation, SO3 levels as high as 6 ppmvd at 3% O2 are possible. SRP currently operates on a 

three year outage cycle which will require the SCR systems to operate at close to 100% 

reliability. Significant ABS formation and air heater plugging is not expected due to the low SO3

content in the flue gas and it is not likely that a change in air heater basket material would be 

required. 

3.5.6 SCR and Baghouse Option Mechanical 

For existing ID fan configuration and performance data, see subsection above. 

Based on preliminary calculations, new ID booster fans would be required to support the 

installation of the SCR and baghouse. The existing four (4) 25% (per unit) ID fans would be 

used (without modifications) and two (2) new 50% axial ID booster fans (per unit) would be 

added between the baghouse and wet scrubber inlet. The existing ID fan would operate at a 

decreased pressure rise in order to achieve a pressure of -1 in. W.C. at the fan discharge. It is 

an industry standard to maintain baghouses under negative pressure to avoid flue gas leakage. 

ID fan isolation would be accomplished by double-louver-type and guillotine isolation dampers 

at the ID fan inlet and outlet, respectively. 

Refer to the design basis document (Appendix A) for assumptions and inputs as well as 

sketches MSK-1005-01 and MSK-1005-02 (Appendix D). 

3.6 SORBENT INJECTION SYSTEM 

3.6.1 SCR Option 

Sorbent injection for SO3 control would utilize hydrated lime for the SCR Option. The hydrated 

lime would be delivered to one of three silos located near each unit’s injection point. The 

sorbent would be offloaded from the truck via onboard blowers, into a seven-day storage silo. 

The hydrated lime would then be transferred from the storage silo to the ductwork injection point 

via 2 x 100% blowers provided at each sorbent storage silo. Sorbent can be injected either 

upstream or downstream of the air preheater; for Navajo, sorbent will be injected upstream of 

the air preheater. Carbon steel pipe would be used to transfer the hydrated lime to the ductwork 
 

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and carbon steel injection lances would be utilized to get satisfactory distribution within the duct. 

The sorbent would be collected and removed from the flue gas stream in the existing wet FGD. 

3.6.2 SCR and Baghouse Option 

Sorbent injection for SO3 control would utilize a sodium-based sorbent, such as trona, for the 

SCR and Baghouse Option. The trona would be delivered to one of three silos located near 

each unit’s injection point. The sorbent would be offloaded from the truck via onboard blowers, 

into a seven day storage silo. The trona would then be transferred from the storage silo to the 

ductwork injection point via 2 x 100% blowers provided at each sorbent storage silo. Sorbent 

can be injected either upstream or downstream of the air preheater; for Navajo, sorbent will be 

injected upstream of the air preheater. Carbon steel pipe would be used to transfer the trona to 

the ductwork and carbon steel injection lances would be utilized to get satisfactory distribution 

within the duct. Further evaluation is required to determine if the sorbent can be collected in the 

existing wet FGD. If the FGD will not adequately remove the sorbent then the SCR plus 

baghouse option would have to be used. 

Refer to sketches MSK-1004-01, MSK-2004-01 and MSK-3004-01 in Appendix D for conceptual 

design. 

3.7 SCR 

3.7.1 SCR Reactors 

Preliminary calculations indicate that 2 x 50% SCR reactors would be required for each unit. 

Each SCR reactor would be of a 4-catalyst layer design, with only 2 layers being initially loaded. 

The SCR would be designed to operate with ultra-low SO2-to-SO3 conversion catalyst, using 

sonic horns to keep the catalyst levels clean. Additionally, vacuum cleaning lines would be 

installed with each reactor. These lines would be routed to a terminal point where a vacuum 

truck could be hooked up to assist in cleaning a reactor during an outage. Each SCR reactor 

would have an economizer inlet flue-gas side bypass, to ensure that the flue gas temperature is 

above 580°F at the reactor inlet. No reactor bypass would be provided. The economizer inlet 

flue-gas side bypass would be designed with double-louver-type isolation dampers and seal air. 

Feedwater recirculation may also be used to increase the flue gas temperature above 580 oF. 

During detailed design, both options would be evaluated, and the most cost effective option 

would be selected. The cost of a feedwater recirculation modification is typically less than an 

economizer bypass, which is the basis for the estimate, 

Anhydrous ammonia has been chosen as the reagent for this study. Additional studies will be 

needed to better understand the costs and the risks associated with the options of anhydrous 

ammonia, aqueous ammonia, and urea. The anhydrous ammonia is delivered in liquid form, and 

then vaporized to form gaseous ammonia. Approximately 550 lbs/hr of gaseous ammonia would 

be required per unit (275 lbs/hr per reactor). 

3.7.2 Anhydrous Ammonia Delivery and Transfer 

The delivery and transfer of anhydrous ammonia is the same both for the SCR Option and the 

SCR and Baghouse Option. 
 

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Anhydrous ammonia would be delivered to the site via truck to a common ammonia unloading 

area located to the south of Unit 3. Anhydrous ammonia is a liquid, and would be unloaded via 

onboard truck pumps into one of three (3) bullet-type storage tanks. Each storage tank would be 

sized for 14 days of continuous operation at full load for one unit. 

Each tank would have one dedicated pump to transfer the liquid anhydrous ammonia from the 

common storage area to each unit. In addition, one backup pump would be cross-tied to each 

tank to provide redundancy for each unit. The 4 x 33% pump arrangement maximizes operator 

turndown flexibility. The anhydrous ammonia would be transferred to each unit via special 

double-walled pipe utilizing leak detection cable located aboveground on a pipe rack. The 

interior pipe would be stainless steel and would be the primary carrier for the anhydrous 

ammonia. A larger-diameter carbon steel pipe is utilized on the exterior to keep leaks contained. 

3.7.3 Anhydrous Ammonia Vaporization and Injection 

The vaporization and injection of anhydrous ammonia is the same both for the SCR Option and 

the SCR and Baghouse Option. 

The anhydrous ammonia is pumped to the vaporizer skid at each reactor. Each vaporizer skid 

consists of two vaporizers with each skid requiring 1,500 lbs/hr of low pressure steam, provided 

from the corresponding unit’s low-pressure steam system. 

The gaseous ammonia leaves the vaporizer and mixes with dilution air for final reactor injection. 

Each vaporizer skid includes its own dilution air blower skid, with 2 x 100% blowers on each 

skid. The dilution air is heated with steam to match the temperature of the gaseous ammonia, 

and then blown to a static mixer, where it is mixed with the vaporized ammonia. This mixture 

(5% ammonia and 95% air) is then blown to the ammonia injection grid at one of the SCR 

reactors. 

3.7.4 Low-Pressure Steam for Vaporizer 

Low-pressure steam required for the vaporizer is the same both for the SCR Option and the 

SCR and Baghouse Option. 

The low-pressure steam required for each vaporizer would be provided from the corresponding 

unit’s low-pressure steam system. Once the steam has been used to vaporize the ammonia, it 

would be discharged to a local condensate storage tank. The condensate storage tank would 

discharge to a collection sump and the contents pumped to the mist eliminator wash water tank 

for reuse. 

Refer to sketches MSK-1003-01, MSK-2003-01, MSK-3003-01 and MSK-3003-2 in Appendix D 

for conceptual design. 
 

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3.8 PULSE-JET FABRIC FILTER (BAGHOUSE) 

3.8.1 Baghouse 

A baghouse system would be installed downstream of the existing ID fans and upstream of the 

new ID booster fans on all three units. Flue gas enters on the bottom half of the baghouse 

through an inlet plenum system. The gas rises through the baghouse and the particulates, 

generated by the reaction between the airborne SO3 and injection sorbent, are collected on the 

outside of the filter bag. The gross air-to-cloth ratio would be designed to be 6:1. The cleaned 

flue gas discharges into a common outlet plenum and exits the baghouse casing through the 

upper half of the baghouse, on the same side as the inlet. 

The baghouse system would consist of two casings, with each casing equipped with eight 

compartments. Each compartment contains a number of PPS filter bags (such that the air-tocloth ratio is 6:1) and can be isolated by the use of and inlet and outlet damper. The bags are 

cleaned by the use of 2 x 100% air compressors (with 2 x 100% dryers and 2 x 100% 

receivers), which are common to both casings. 

The pulse-jet cleaning cycle is activated when the pressure drop across a casing is higher than 

the predetermined set point. The pulse-jet cleaning cycle requires compressed air to be sent 

sequentially into rows of cleaning headers, located just above the tops of the filter bags. As the 

compressed air is blown through a bag, the solids on the outside of the filter bag are released. 

These solids are then collected in hoppers located directly below the bags in each 

compartment. A dust detector is installed within each compartment to detect an increase in 

particulate emissions due to a damaged filter bag. Damaged filter bags can be replaced while 

the baghouse is on line by isolating the necessary compartment by closing the inlet and outlet 

dampers. 

Each baghouse system would be equipped with an internal bypass for emergency situations 

where the flue gas temperature rises above the maximum bag temperature, which in this case 

(PPS bags), is 375oF. In this event, a poppet damper system connecting the inlet and outlet 

ductwork would fail open, opening up a path between the inlet and outlet plenum. 

Simultaneously, the inlet and outlet isolation dampers to each compartment would fail closed. 

This combination would protect the bags from the hot flue gas, while also providing an open gas 

path through the baghouse. 

3.8.2 Waste Collection and Disposal System 

For each unit, the baghouse waste would be transported from the individual compartment 

hoppers to a storage silo. The solid waste would be emptied from the hoppers via vibrators and 

discharged into a pipeline collection system that runs underneath each of the hoppers. 

The solid waste would be transported in these lines via pneumatic blowers. Due to the physical 

arrangement, Unit 1 would require 2 x 100% blowers, while Units 2 and 3 would utilize a 3 x 

50% setup (per unit). The waste storage silos would be sized for a 7-day storage capacity and 

would utilize 2x100% blowers to provide air to the fluidizing trays on the silo floor. The waste 

material would be removed from the silo and mixed with water using pin/paddle mixers, 

discharged into a truck and disposed into a plant landfill. 
 

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Refer to sketches MSK-1006-01, MSK-2006-01 and MSK-3006-01 in Appendix D for conceptual 

design. 
 

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4. PLANT ELECTRICAL SYSTEMS AND EQUIPMENT 

4.1 CODES AND STANDARDS 

Electrical equipment and systems provided would be supplied by qualified and experienced 

manufacturers. Electrical equipment and systems would be of proven design and successfully 

used on power plant projects. The design and specifications would be in accordance with 

applicable regulations and applicable local codes and ordinances. Electrical equipment would 

meet the latest codes and standards. 

Design practices at the existing plant would be utilized as deemed appropriate. 

4.2 ELECTRICAL POWER SUPPLY SYSTEMS 

The methods for powering each of the options are discussed below: 

4.2.1 SCR Only Option (Each of Units 1, 2, and 3) 

• The one-line diagrams for all three units and for the common facility are represented on 

drawing ESK-1000. 

• Utilize existing ID fan motors. 

• Two (2) unit station transformers (USTs) per unit fed from existing 4.16-kV switchgear. 

• 480-V switchgears and motor control centers (MCCs) per unit. 

• Common loads for the anhydrous ammonia system fed from existing 480-V buses 

LSPA/LSPB. 

4.2.2 SCR and Baghouse Option (Each of Units 1, 2 and 3) 

• The one-line diagrams for all three units and for the common facility are represented on 

drawings ESK-1001 SHT. 1, 2 and 3. 

• One (1) three-winding unit auxiliary transformer (UAT) per unit. 

• Two (2) 13.8-kV switchgears per unit. 

• Two (2) 13.8-kV common switchgears for startup and shutdown. 

• Two (2) 4.16-kV switchgear extensions per unit. 

• Two (2) USTs per unit fed from extension of existing 4.16-kV switchgear. 

• 480-V switchgear and MCCs per unit. 

4.3 BASIC ELECTRICAL SYSTEM 

4.3.1 SCR Option 

The electrical auxiliary power system would be designed to utilize the existing sources 

where applicable. The ID fan motors for each unit have spare capacity and therefore 

would be reused in conjunction with a retrofitted fan. New 4.16/0.48-kV USTs would be 
 

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fed from the existing FGD 4.16-kV switchgear located in the FGD pump house of each 

unit. These transformers would provide the auxiliary power to 480-V switchgear and 

MCCs required for the SCR system loads. 

The ammonia delivery system associated with the installation of the SCRs for each of 

the three units would be located at the south end of the power plant. The ammonia 

delivery system would require new 480-V MCCs. The MCCs would be powered from the 

existing switchgears LSPA and LSPB located in the limestone preparation enclosure. 

Refer to drawings ESK-1000 SHT. 1 in Appendix F for the one-line diagrams for all three 

units. 

4.3.2 SCR and Baghouse Option 

New ID booster fans estimated to be 10,000 hp would be required for each unit to 

overcome the pressure drop through the new baghouse. The new booster fans cannot 

be supported from the existing UATs. It is therefore necessary to add one (1) new UAT 

and two (2) 13.8-kV switchgears for each unit to distribute power to the new ID booster 

fans. 

Two (2) additional common switchgears would be added for unit startup and shutdown, 

and would be located in a common power distribution center (PDC) enclosure. The new 

common 13.8-kV switchgears would be powered from the existing station service 13.8-

kV buses SSA and SSB. 

An extension of the 4.16-kV switchgear bus would be required to provide the required 

quantity of feeders for the new auxiliary air compressor and 4.16/.48-kV UST. 

The 480-V system loads would be fed from a pair of new 4.16-kV to 480-V transformers 

for each unit. The transformers would feed loads associated with the baghouse, SCR, 

and the ID booster fans. 

Refer to drawings ESK-1001 SHT. 1, SHT. 2, and SHT. 3 in Appendix F. 

4.4 AUXILIARY POWER SYSTEM PERFORMANCE 

4.4.1 SCR Option 

The auxiliary power system for the SCR Option simply consists of addition of 4.16-kV to 

480-V transformers tied to the existing plant auxiliary system and, hence, does not 

require extensive study. The 480-V transformers would be selected to perform similarly 

to the existing 480-V system at the plant. 

The capacity of each 480-V UST would be such that it would carry the entire load 

connected to the switchgear lineup with the other transformer out of service. 
 

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4.4.2 SCR and Baghouse Option 

The auxiliary power system for the SCR and Baghouse Option would be designed to 

provide an adequate and reliable power supply to the plant's electrical auxiliary loads. 

The system would be designed to handle auxiliary load requirements under all plant 

operating modes and under the contingency of the loss of any of its UATs. 

The auxiliary power system would consist of the main components and subsystems, 

such as UATs and USTs, medium- and low-voltage distribution systems, motors, and 

other electrical loads. 

The design of the auxiliary power system would be based on results of an Auxiliary 

Power System Study. The results of the study would determine the new UAT MVA 

ratings, auxiliary power system voltages, auxiliary transformer impedances, the short 

circuit rating at each voltage to achieve acceptable steady state voltage regulation at 

each power system bus, and to achieve acceptable voltage regulation during motor 

starting. The study would consider reasonable contingency operating conditions such as 

a single transformer out of service. The study would also consider full-load operation as 

well as startup and shutdown of the unit. 

The auxiliary power system study would use the following criteria to establish acceptable 

performance: 

• The total capacity of the UAT would be sufficient to supply both ID booster fans for 

the SCR and Baghouse Option. The remaining auxiliary loads would be fed from the 

existing UATs and the existing plant auxiliary system. The existing auxiliary system 

would be checked for adequate performance. 

• The capacity of each 480-V UST would be such that it would carry the entire load 

connected to the switchgear lineup with the other transformer out of service. 

• The momentary and interrupting short circuit duty on the auxiliary system circuit 

breakers would be within the corresponding breaker and switchgear ratings. 

• The short circuit evaluation would be based on: 

⎯ A pre-fault voltage of 105% system nominal operating voltage. 

⎯ Maximum operating load. 

⎯ Motor contribution to the fault current would be included in accordance with 

the applicable ANSI/IEEE standards. 

⎯ Transformer impedances would reflect negative manufacturing tolerance. 

• Steady state voltage regulation during normal plant operation would be limited to a 

maximum of 110% of equipment rating during maximum system voltage and 

minimum bus loading, and would not fall below 90% of equipment rating during 

minimum system voltage and maximum bus loading. 

• During motor starting, the voltage dip for medium-voltage motors would be limited to 

80% of motor-rated voltage at the motor terminals when starting the largest single 

motor with maximum load on the bus. On the 480-V buses the level of voltage dip 

during motor starting would be limited to 80% of motor-rated voltage at the motor 
 

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terminals when starting the largest single motor with maximum load on the bus. 

Additionally, the bus voltage at the MCCs would not be less than 85% of bus-rated 

voltage. 

• The voltage regulation calculations would consider the minimum system operating 

voltage, maximum bus loading, and positive manufacturing tolerance for transformer 

impedance. 

• The voltage level on the auxiliary buses during bus transfer would be sufficient to 

allow the reacceleration of the transferred medium voltage and low voltage motors in 

groups. 

• The medium-voltage fast transfer scheme would be used for all bus transfers and 

would follow the scheme being utilized at the existing plant. 

4.5 AUXILIARY POWER SYSTEM EQUIPMENT 

4.5.1 SCR Option 

All of the SCR auxiliary loads would be supplied from two (2) 4.16-0.48-kV USTs per 

unit. The 4.16-0.48-kV USTs would be connected to the existing 4.16-kV FGD 

switchgear. Feeds from the USTs to the doubled-ended switchgears would be made by 

cable bus. The 480-V switchgears would be located in their associated unit’s pump 

building, where space is available for future equipment. 

The main 480-V buses would be connected via a tie breaker. The 480-V switchgears 

would feed MCCs that in turn would feed all the 480-V motor and other loads. The 480-V 

switchgear and MCC current interrupting rating would be equal to or less than 65 kA. 

MCCs would be radial-fed with no interconnecting ties between MCC buses. For Units 1 

and 3, the 480-V MCCs would be located in new PDCs positioned near the SCRs. For 

Unit 2, where the SCRs are in relative close proximity to the Unit 2 pump building and 

there are space constraints on the ground for a PDC, the 480-V MCCs would be located 

in the Unit 2 pump building, where space is available for future equipment. 

Anhydrous ammonia system loads would be fed from new MCCs. The 480-V MCCs 

would be located in a new PDC positioned near the anhydrous ammonia delivery area. 

4.5.2 SCR and Baghouse Option 

During normal operation, the new ID booster fans would be supplied with power from 

one (1) new three-winding 26-14.9-kV UAT for each unit. The HV winding of the UATs 

would be fed by tapping into the existing isolated phase bus ducts (IPBs). Each LV 

winding would feed a separate new 13.8-kV switchgear bus. 

13.8-kV buses would be sized to accommodate the maximum rating of the new UAT 

windings. The 13.8-kV switchgears would be located in new PDCs. Refer to the General 

Arrangement drawing (Appendix I) for PDC location. 
 

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During startup and shutdown, the new 13.8-kV buses that feed the ID booster fans 

would be fed from existing main station service (MSS) and reserve station service (RSS) 

transformers. MSS and RSS distribution would be supplied via two (2) new common 

13.8-kV switchgears that would be tied to each unit switchgear by means of cable bus. 

The 13.8-kV Common switchgear would be located in a new PDC. Refer to the General 

Arrangement drawing (Appendix I) for PDC location. 

An extension of the existing 4.16-kV switchgear buses would be required. The buses to 

be extended are shown on One Line Drawings ESK-1001 SHT 1, 2 and 3 (Appendix F). 

Switchgear feeders would be added to provide feeds for the new 4-kV auxiliary air 

compressors associated with the baghouse and to service the 4.16-kV - 480-V 

transformers. 

Two (2) 4.16-.48 kV USTs per unit would be required to service the 480-V loads. The 

4.16-.48 kV UST would be connected to the extensions of the existing 4.16-kV FGD 

switchgear as described above. Feeds from the USTs to the double-ended switchgears 

would be made by cable bus. The 480-V switchgears would be located in their 

associated unit’s pump building, where space is available for future equipment. 

480-V MCCs would service all smaller 480-V loads for the baghouse, SCR, and ID 

booster fans. For Units 1 and 3, the 480-V MCCs dedicated for SCR loads would be 

located in new PDCs positioned near the SCRs. Since the baghouse and ID booster 

fans are in relative close proximity to the unit pump buildings, the 480-V MCCs 

dedicated for baghouse and ID booster fan loads would be located in the unit’s pump 

building, where space is available for future equipment. All 480-V MCCs for Unit 2 would 

be located in the Unit 2 pump building, where space is available for future equipment. 

Anhydrous ammonia system loads would be fed from new MCCs. The 480-V MCCs 

would be located in a new PDC positioned near the anhydrous ammonia delivery area. 

4.6 DC POWER SUPPLY SYSTEM 

The DC power supply system would consist of sealed-type VRLA batteries. The batteries would 

be sized to handle the duty cycles determined in the final design. All batteries would have 

design margin for future loads. Batteries would be able to supply full-duty cycle load for no less 

than two hours after loss of the charging system. Each battery would be furnished with two 

battery chargers. The battery chargers would be redundant. The batteries would be installed 

within the electrical equipment rooms. 

Overcurrent protective devices would be provided in DC distribution panels with an interrupting 

capacity greater than the maximum available short circuit current. All cables in the DC 

distribution system would be designed to withstand the maximum available short circuit current. 

The DC power system would feed the emergency bearing pumps for the ID booster fans, 

uninterruptible power supply (UPS) systems, and the control power for switchgear. 
 

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4.7 UNINTERRUPTIBLE AC POWER SYSTEM 

The uninterruptible AC power system would consist of a system that would provide regulated 

sinusoidal voltage to critical loads during normal and off-normal operations, as well as isolation 

of critical loads from transients generated on the plant electrical auxiliary system. The system 

would act as a source of uninterruptible power to critical loads in the event of failure of the 

normal AC power sources. The system would be designed with sufficient capacity to provide the 

peak demand currents of the connected loads and to clear branch circuit faults without adverse 

effects on the system. The system would include AC input rectifier, inverter, bypass power 

supply, static transfer switch, manual bypass switch, and UPS distribution panel boards with 

fast-acting current limiting type circuit breakers and fuses. 

The UPS system would provide power to electrical loads, such as the DCS and instrumentation 

and controls, which require a regulated and AC uninterrupted power source. 

4.8 ELECTRICAL CONTROL AND PROTECTION 

Protective relaying systems would be designed to protect all electrical equipment in the main 

and auxiliary power supply systems. Protection would be provided for transformers as well as 

for the auxiliary power system and the loads connected to the auxiliary power system. The 

protective relay system would remove and alarm abnormal operating conditions occurring on 

equipment designed for voltage transformation, energy conversion, and distribution of electrical 

power, as well as limit damage to faulted or overloaded equipment. The protective relaying 

system would be a coordinated application of multifunction relays. All protective relays would be 

selected to coordinate with protective devices supplied by manufacturers of major equipment, 

as well as the thermal limits of electrical conductors and electrical equipment, such as 

transformers and motors. 

4.9 COMMUNICATION SYSTEM 

Communication systems for the new facilities would follow the existing plant communication 

systems. It is expected that the communication system extensions would be required for the 

following: 

• Paging system 

• Fire alarm and other signal systems 

• Commercial telephone system 

4.10 LIGHTING AND MAINTENANCE POWER SYSTEM 

The lighting power system would consist of normal AC lighting, DC emergency lighting, and 

convenience receptacles. The lighting system would follow the lighting system at the existing 

plant. The lighting system would provide illumination for SCR and baghouse operation and 

maintenance under normal conditions, means of egress under emergency conditions, and 

emergency lighting in the equipment rooms to perform manual operations during a power 

outage of the normal power source. Emergency egress lighting would be powered self-
 

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contained battery packs, depending on the physical location of the emergency light fixture. 

Panelboards would be located indoors. 

A maintenance welding system powered from the new 480-V system would be provided 

throughout the SCR and baghouse areas. 

4.11 GROUNDING SYSTEM 

The station grounding system would be extended with an interconnected network of bare solid 

copper conductors and copper ground rods. The systems would be designed to protect plant 

personnel and equipment from the hazards that can occur during power system faults and 

lightning strikes. 

Major equipment items, such as switchgear, unit substation transformers, MCCs, and control 

panels, would have integral ground buses, which would be connected to the station ground grid. 

Electronic panels and equipment, where required, would be grounded utilizing an insulated 

ground conductor connected in accordance with the manufacturer's recommendations. The 

grounding system would be designed in accordance with applicable IEEE standards and would 

be installed in accordance with the NEC. 

4.12 LIGHTNING PROTECTION SYSTEM 

The lightning protection design would be in accordance with NFPA 780. Lightning protection for 

buildings and structures would consist of air terminals installed around the perimeter of the 

structure. The air terminals would be connected together with stranded copper conductors and 

connected to the plant ground grid with stranded copper down conductors. 

4.13 CATHODIC PROTECTION SYSTEM 

The existing cathodic protection system would be extended, as required, to provide corrosion 

control of buried metallic piping. 

4.14 FREEZE PROTECTION SYSTEMS 

Freeze protection system would be provided for outdoor piping (8” and smaller), instruments, 

and other devices subject to freezing in cold weather. The freeze protection system would be 

designed to accommodate both normal plant operations and extended plant shutdowns in cold 

weather. Similar systems and equipment would be utilized to meet process temperature 

maintenance needs of piping systems required to be maintained at high temperatures. 

4.15 AUXILIARY POWER REQUIREMENTS 

Addition of the major AQCS equipment will increase the auxiliary load of the plant. Also, the 

modification to the ID fans in the SCR Only option will use a greater amount of auxiliary power 

than currently used. Table 4-1 lists predicted auxiliary power consumption for the new 

equipment. 
 

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Table 4-1. Predicted Auxiliary Power Consumption 

Option Plant Auxiliary Power Unit Basis 

Existing four (4) Induced Draft Fan Modification 

(increase BHP) 

5.0 MW 

Anhydrous Ammonia Storage and Transfer 0.1 MW 

SCR 

SCR TOTAL 5.1 MW 

SCR with DSI Existing four (4) Induced Draft Fan Modification 

(increase BHP) 

5.0 MW 

 SCR and Sorbent Injection System 0.2 MW 

 Anhydrous Ammonia Storage and Transfer 0.1 MW 

SCR with DSI TOTAL 5.3 MW 

SCR and Sorbent Injection System 0.2 MW 

Anhydrous Ammonia Storage and Transfer 0.1 MW 

Existing Induced Draft Fan Modification 

(decrease BHP) and New ID Booster Fan 

10.0 MW 

SCR + Baghouse 

Baghouse Loads 0.5 MW 

SCR + BAGHOUSE TOTAL 10.8 MW 
 

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5. PLANT CONTROL SYSTEMS AND EQUIPMENT 

5.1 GENERAL 

Triple instrumentation would be used on critical control loops and auxiliaries that if operated outof-limits would cause loss of power generation or catastrophic damage to a major plant 

auxiliary. The control logic would perform median select logic for analog loops and 2-out-of-3 

logic for digital loops. 

Dual instrumentation would be used for systems and auxiliaries that if operated out-of-limits 

would directly affect plant operation or cause damage to major auxiliaries. The control logic 

would perform average select logic of the two analog signals or 2-out-of-2 logic for digital 

signals. 

Wherever possible, transmitters would be used in lieu of process switches. Transmitters would 

be electronic, 2-wire type, with isolated 4-20 mA DC output signals. 

Temperature measurements for control and monitoring inputs would be made with RTDs or 

Chromel-Constantan (Type E) thermocouples. 

5.2 SCR OPTION 

The SCR system would be controlled by new DCS equipment that would be tied into the 

existing plant Foxboro DCS. New DCS equipment for Unit 1 and Unit 3 would be located in their 

respective new PDCs near the SCRs. New DCS equipment for Unit 2 would be located in the 

existing Unit 2 FGD pump house. The common DCS equipment for the anhydrous ammonia 

equipment would be located in the anhydrous ammonia unloading and storage area. All new 

DCS equipment would tie into the existing network in the Environmental and Chemical Lab 

Control Room. The new Unit 1 and Unit 2 DCS equipment would tie into the existing cabinet 0-

DCS-CABQ. The new Unit 3 and common DCS equipment would tie into the existing cabinet 0-

DCS-CABR. Each Unit DCS would require 500 I/O points and the common DCS would require 

100 I/O. 

Each unit’s SCR has two reactors. Each reactor would require an in situ NOX and O2

measurement on both the inlet and outlet side for a total of four measurements per unit. In 

addition to these measurements, a common meteorological station would also be added. 

Each unit would require approximately 100 balance-of-plant instruments. These instruments 

include various transmitters, switches, thermocouples, etc., for the various SCR reactor 

measurements and new ID fan interface. The common DCS would require approximately 10 

balance-of-plant instruments. These instruments include various transmitters, switches, 

thermocouples, etc., for the anhydrous ammonia unloading tanks and transfer pumps. 

Minimal modifications may be required to the Control Room HVAC system controls to create a 

safe haven in the control room in the event of an ammonia leak. 
 

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5.3 SCR AND BAGHOUSE OPTION 

The SCR system would be controlled by new DCS equipment that would be tied into the 

existing plant Foxboro DCS. New DCS equipment for Unit 1 and Unit 3 would be located in their 

respective new PDC near the SCR, their respective PDCs housing 13.8-kV switchgear, and 

their respective FGD pump houses. New DCS equipment for Unit 2 would be located in the 

existing Unit 2 FGD pump house and the new Unit 2 PDC housing 13.8-kV switchgear. The 

common DCS equipment for the anhydrous ammonia equipment would be located in the 

anhydrous ammonia unloading and storage area and the common PDC building. All new DCS 

equipment would tie into the existing network in the Environmental and Chemical Lab Control 

Room. The new Unit 1 and Unit 2 DCS equipment would tie into the existing cabinet 0-DCSCABQ. The new Unit 3 and common DCS equipment would tie into the existing cabinet 0-DCSCABR. Each unit DCS would require 1000 I/O points and the common DCS would require 200 

I/O points. 

The Unit 1, 2, and 3 pulse-jet baghouse cleaning system would be controlled via the Vendor 

provided PLC. The PLC would have datalink integration into the new DCS. All other baghouse 

systems would be controlled via the DCS. 

Each unit’s SCR has two reactors. Each reactor would require an in situ NOX and O2

measurement on both the inlet and outlet side for a total of four measurements per Unit. In 

addition to these measurements, a common meteorological station would also be added. 

Each unit would require approximately 150 balance-of-plant instruments. These instruments 

include various transmitters, switches, thermocouples, etc., for the various SCR reactor 

measurements, the new ID booster fans, and the new baghouse equipment. The common DCS 

would require approximately 10 balance-of-plant instruments. These instruments include various 

transmitters, switches, thermocouples, etc., for the anhydrous ammonia unloading tanks and 

transfer pumps. 

Minimal modifications may be required to the Control Room HVAC system controls to create a 

safe haven in the control room in the event of an ammonia leak. 
 

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6. PROJECT SCHEDULE 

6.1 INTRODUCTION 

Summary Level and Level III project schedules for development, design, construction, and 

startup of the project were prepared based on a multiple firm price construction contracting 

strategy. Construction-quality design drawings would be used for bidding purposes for the 

ductwork, structural steel, and foundations. The schedule, as currently laid out, represents the 

most cost effective and least risky option. However, there does exist some flexibility in activity 

durations, equipment lead times, and predecessor/successor relationships at the risk of higher 

financial expense. 

The construction contracts would be: 

• Substructure – Separate Contracts for Units 3, 2, and 1 

• Mechanical & Structural General Work – Separate Contracts for Units 3, 2, and 1 

• Electrical & Instrumentation General Work – Separate Contracts for Units 3, 2, and 1 

• Construction Testing & Inspection 

• Final Sitework 

These schedules are provided in Appendix G. 

6.2 PROJECT MILESTONES – SCR OPTION 

The SCR Option schedules provided in Appendix G comprise an eight (8)-month engineering 

study phase, a twenty-nine (29)-month procurement and detailed engineering period, an 

eighteen (18)-month construction phase, and a two (2)-month tie-in. The total project duration, 

from study authorization to the completion of the tie-in outage is 42 months for Units 1 and 3, 

and 44 months for Unit 2. The construction and startup schedules including tie-in durations were 

furnished by Foster Wheeler and are also provided in Appendix G. The Foster Wheeler 

schedule was incorporated into the overall project schedule. 

Development of the schedules was based on the following milestones: 

Table 6-1. SCR Option Schedule Milestones 

Milestone 

Months After 

Notice To Proceed 

Notice to Proceed (Unit 3) - 

Purchase Catalysts 10 

Notice to Proceed (Unit 2) 10 

Receive Final Flow Model Report 16 

Purchase Structural Steel 20 
 

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Milestone 

Months After 

Notice To Proceed 

Notice to Proceed (Unit 1) 24 

Start Construction 25 

Complete Tie In Outage (Unit 3) 42 

Commercial Operation Unit 3 44 

Complete Tie In Outage (Unit 2) 54 

Commercial Operation Unit 2 56 

Complete Tie In Outage (Unit 1) 66 

Commercial Operation Unit 1 68 

6.3 PROJECT PROCUREMENT – SCR OPTION 

S&L’s initial determination of Unit 3 critical path is as follows: 

Table 6-2. Unit 3 SCR Option Critical Path 

Activity Months After Notice to 

Proceed 

Bid Issue Catalyst Specification 7 

Award Catalyst Contract 10 

Receive Final Flow Model Report 16 

Bid Issue Structural Steel 17 

Award Structural Steel Package 20 

Release Foundation Design Package for Bid 19 

Award Foundations Contract 22 

Release M-GWC Design Package for Bid 21 

Award M-GWC 24 

Initial Ductwork Delivered Onsite 26 

Release E-GWC Design Package for Bid 26 

Award E-GWC 30 

Complete Pre-Outage Construction 39 

Complete Tie In Outage Unit 3 42 
 

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6.4 PROJECT MILESTONES – SCR AND BAGHOUSE OPTION 

The SCR and Baghouse Option schedule comprises an eight (8)-month engineering study 

phase, a thirty-one (31)-month procurement and detailed engineering period, a nineteen (19)-

month construction phase, and a two (2)-month tie-in phase. The total project duration, from 

study authorization to the completion of the tie-in outage is 48 months for Units 1 and 3, and 

50 months for Unit 2. The construction and startup schedules were furnished by Foster 

Wheeler, and are also provided in Appendix G. The Foster Wheeler schedule was incorporated 

into the overall project schedule. 

Development of the schedules was based on the following milestones: 

Table 6-3. SCR and Baghouse Option Schedule Milestones 

Milestone 

Months After 

Notice To Proceed 

Notice to Proceed (Unit 3) - 

Purchase Catalysts 10 

Notice to Proceed (Unit 2) 10 

Purchase Baghouse 11 

Receive Final Flow Model Report 16 

Notice to Proceed (Unit 1) 24 

Purchase Structural Steel 27 

Start Construction 31 

Complete Tie In Outage (Unit 3) 48 

Commercial Operation Unit 3 50 

Complete Tie In Outage (Unit 2) 60 

Commercial Operation Unit 2 62 

Complete Tie In Outage (Unit 1) 72 

Commercial Operation Unit 1 74 
 

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6.5 PROJECT PROCUREMENT – SCR WITH BAGHOUSE 

S&L’s initial determination of Unit 3 critical path is as follows: 

Table 6-4. Unit 3 SCR and Baghouse Option Critical Path 

Activity Months After Notice to 

Proceed 

Bid Issue Catalyst Specification 7 

Award Catalyst Contract 10 

Receive Final Flow Model Report 16 

Bid Issue Structural Steel 24 

Award Structural Steel Package 27 

Release Foundation Design Package for Bid 24 

Award Foundations Contract 28 

Release M-GWC Design Package for Bid 26 

Award M-GWC 30 

Initial Ductwork Delivered On-Site 31 

Release E-GWC Design Package for Bid 30 

Award E-GWC 33 

Complete Pre-Outage Construction 44 

Complete Tie In Outage Unit 3 48 
 

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7. GENERAL ARRANGEMENT FEATURES 

7.1 COMMON 

No significant changes to the existing drainage and roads in the area would be required to 

accommodate the new air quality equipment. Local modifications of these systems required in 

the area of the new work would tie back into the existing systems as quickly as possible. 

Access roads would be maintained in the area of the new work. New pipe racks and ductwork 

that cross over or run along roads would be set at elevations high enough and with support 

column spacings wide enough to permit vehicle access below. For the purposes of this cost 

estimate the minimum clearance above all roads for vehicle access is 25 feet. 

7.2 SCR OPTION 

The two new SCRs for both Units 1 and 3 would be located side-by-side where possible for a 

more efficient ductwork arrangement as well as for better access and maintenance operations 

between the pair. 

The new ductwork to and from the SCRs would exit the existing system downstream of the 

electrostatic precipitators and would tie back in upstream of the air heaters. These tie-ins would 

occur in the available space between the existing boiler building and the electrostatic 

precipitators. 

7.2.1 SCR Unit 1 

For Unit 1, the SCRs would be placed above the existing pipe rack that runs along the north 

side of the unit. The pipe rack would not be modified or affected in any way. 

7.2.2 SCR Unit 2 

For Unit 2, the SCRs would be separated from each other because of space constraints in this 

congested area. Separate SCRs would be placed to the north and south of the Unit 2 chimney. 

Existing platforms that run between the Unit 1 and Unit 2 precipitators would be demolished to 

provide space for the new ductwork to and from the north SCR. 

7.2.3 SCR Unit 3 

For Unit 3, a portion of the existing maintenance facility / fabrication shop south the unit would 

be demolished to make room for the SCRs. For the purposes of this cost estimate space for a 

replacement facility for the demolished portion is reserved on the north side of the site. 
 

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7.3 SCR AND BAGHOUSE OPTION 

The two new baghouses and ID Booster Fans for each unit would be located side-by-side where 

possible for a more efficient ductwork arrangement as well as better access and maintenance 

operations between the pair. 

For all units, the abandoned chimney shell would be used as a support for the ductwork going to 

and from the baghouses. A branch of ductwork would pass through the existing openings in the 

shell and additional openings would be cut as necessary, rather than demolishing the remaining 

shell and erecting new steel framing in the area to support the ductwork. 

7.3.1 Baghouses Unit 1 

For Unit 1, the baghouses would be located within the existing water treatment area and would 

be separated to avoid disturbing the existing equipment in the area. 

The west Unit 1 baghouse, located between the existing brine concentrators and clarifier tanks, 

would be elevated above grade to maintain the roadway in the area, allowing for a 25-foot-high 

vehicle access below it. 

The existing ash blowers and their foundation on the north side of Unit 1 would be relocated to 

accommodate the new ID Booster Fans. The existing pipe rack that runs along the north side of 

the unit would be demolished to accommodate the new fans. For the purposes of this cost 

estimate space is reserved for a replacement rack somewhat farther north of the existing one 

but still south of the water treatment area. 

The existing sump and trenches in the water treatment area near the east Unit 1 baghouse 

would be relocated to accommodate the new baghouse. 

7.3.2 Baghouses Unit 2 

For Unit 2, the baghouses would be stacked because of the extreme congestion in the area. 

The existing tool room between the Unit 2 and Unit 3 precipitators would be demolished to make 

room for the baghouses. For the purposes of this cost estimate space is reserved for a 

replacement tool room on the north side of the site. 

On Unit 2, the new ID Booster Fans would need to be separated to fit into the extremely 

congested area, with one on the north side of the Unit 2 chimney and the other on the north side 

of the Unit 3 chimney, south of the coal conveyor between Units 2 and 3. 

The ductwork running to and from the Unit 2 baghouses would pass over and under both the 

existing coal conveyor that runs between Units 2 and 3 and also the new ductwork running to 

and from the south SCR for Unit 2. This congestion, coupled with the stacked baghouses for 

this unit, would put this ductwork at a higher elevation than it would need to be for the other two 

units. 

For Unit 2, the existing opening in the abandoned chimney would be used for the baghouse 

supply duct, while the return duct from the baghouses, pushed higher by the stacked baghouses 
 

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on this unit and the need to cross over the conveyor and the SCR ductwork, would run over the 

top of the remaining portion of the shell. 

On Unit 2, fitting the north ID Booster Fan into the tight area would require demolition of the 

existing stair tower / elevator adjacent to the Unit 2 pump enclosure. A bridge would be added 

between the Unit 1 and Unit 2 pump enclosures to provide access to the upper floor of the 

Unit 2 pump enclosure via the Unit 1 pump enclosure elevator. These existing stairs and 

elevator also provide access up to the top of the adjacent Unit 2 absorbers, so an alternate 

means of access to the absorbers that works around the various new items in the area would be 

provided. 

A portion of the Unit 2 absorber foundation that supports this stair tower / elevator would also be 

demolished to accommodate the new fan foundation for the north ID booster fan. 

7.3.3 Baghouses Unit 3 

For Unit 3 no relocations of existing equipment or other major items would be required in the 

area of the new work. The pair of new baghouses and also the pair of new Booster Fans would 

fit side-by-side in an open area east of the existing fabrication shop / maintenance facility on the 

south side of Unit 3. 
 

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8. UTILITY RELOCATION 

8.1 PLANT UTILITIES 

NGS is designed with water utility corridors and electrical ductbanks installed below grade. A 

major utility corridor is located north of Unit 1 and south of the water treatment facility along the 

east/west access road with branch distribution to the south of the plant. NGS has implemented 

a phased underground to aboveground (on piperacks) utility relocation plan. Refer to Appendix 

O for information provided by NGS regarding utilities currently relocated and plans for future 

relocation. For the purposes of this report, the basis of the cost estimate would be relocation of 

all identified utilities from underground to aboveground piperacks in line with current NGS 

relocation philosophy. The information provided by NGS in Appendix O would form the basis of 

a pipe relocation evaluation during the detailed engineering phase of the work. Additionally, for 

the purpose of this report, it is assumed the existing systems have sufficient capacity (pressure 

margin) to support relocation of utilities aboveground. 

8.1.1 SCR Option 

Based on preliminary review of the documents included in Appendix O, there are no piping 

relocations required to support installation of new equipment for the SCR Option. The cathodic 

protection system would most likely be affected from underground work. Modification to the 

system would be required as necessary. Existing platforms that run between the Unit 1 and 

Unit 2 precipitators would be demolished to provide space for the new ductwork to and from the 

north SCR of Unit 2. This would require the relocation of two (2) precipitator transformers from 

that platform to under the precipitator. 

8.1.2 SCR plus Baghouse Option 

To support installation of new infrastructure (piperack, baghouse, ductwork) for the Unit 1 SCR 

and Baghouse Option, a section of the major east/west underground utility corridor identified 

above would be required to be relocated. The existing pipe rack that runs along the north side of 

the unit would be demolished to accommodate the new booster fans. This would be replaced by 

a new rack located on the north side of the existing road. There are cables that run along the 

existing rack. These cables would be relocated to the pipe rack on the north side of the road. 

There are also distribution panels on the ground below existing rack that would need to be 

relocated. Relocation of the cables is assumed to only affect Unit 1. Detailed study / evaluation 

must be performed to identify service of each cable. Additionally, to support installation of the 

Unit 1 ID booster fans, a section of underground piping would be relocated just east of the new 

fans onto existing piperack. Any piping relocated to above ground would need to be heat traced. 

To support installation of the Unit 2 baghouse, a section of aboveground ash conveying piping 

would be relocated east onto existing piperack. To support installation of the Unit 3 baghouse a 

short section of underground fire protection piping would relocated further south from the current 

installed location. Additionally, the existing tool room between the Unit 2 and Unit 3 precipitators 

would be demolished to make room for the Unit 2 baghouses. The existing tool room has cable 

trays loaded with cables running along side it. These cables would be relocated around the new 

baghouse by installing termination panels at the points where the cable need to be rerouted. 
 

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Relocation of these cables is assumed to only affect Unit 2. Detailed study / evaluation must be 

performed to identify service of each cable. 
 

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9. PLANT ECONOMICS 

9.1 BASIS OF COST ESTIMATES 

9.1.1 General 

The conceptual cost estimates provided in Appendix J are based on the installation of new NOX

and particulate reduction equipment at NGS. Estimates 30621B, 30622B, and 30623B reflect 

the installation of SCR systems only on NGS Units 1-3 for NOx reduction. Estimates 30412E, 

30413E, and 30414E reflect the installation of SCR systems only with dry sorbent injection on 

NGS Units 1-3 for NOX reduction. Estimates 30415E, 30416E, and 30417E include the addition 

of SCR systems as well as polishing baghouses for NOX reduction and particulate control on 

Units 1-3. 

The cost estimates are conceptual in nature, and based largely on S&L experience on similar 

projects. No significant preliminary engineering has been performed to firm up the project 

details, and specific site characteristics have not been fully analyzed. Allowances have been 

added, where necessary, to cover issues that are likely to arise but are not clearly quantified at 

this time. Under AACE International’s guidelines these estimates could be classified as Class 4 

Estimates. Class 4 estimates are generally prepared based on limited information, and 

subsequently, have fairly wide accuracy ranges. They area prepared for a number of purposes, 

such as but not limited to, detailed strategic planning, business development, project screening 

at more developed stages, alternative scheme analysis, confirmation of economic and or 

technical feasibility, and preliminary budget approval or approval to proceed to next stage. 

9.1.2 Contracting Strategy 

The capital cost for the plant modifications are based on Owner-managed engineering, 

procurement, and construction. Design of the plant would be performed by an architectengineer, hired by the Owner. All equipment will be purchased directly by the Owner and 

construction would be completed via a multiple lump sum contract arrangement. 

9.1.3 Equipment Costs 

The equipment costs include only those for the manufactured equipment. These items include, 

but are not limited to, anhydrous ammonia system, sorbent injection system, fans, fabric filters, 

compressors, dampers, transformers, switchgear, DCS, pumps, and motors. SCR catalyst is 

also included as equipment since it is purchased as a manufactured item. Informal budgetary 

quotes were obtained for the catalyst, anhydrous ammonia system, sorbent injection system, 

fabric filters, booster fans, compressors, and unit auxiliary transformers. All other equipment 

costs were estimated on the basis of S&L in-house data, vendor catalogs, industry publications, 

and other related projects. 
 

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9.1.4 Material Costs 

The material costs include those for commodity-type materials, such as structural steel, 

ductwork, concrete, piping, valves, cable, cable tray, and conduit. All material unit costs were 

estimated on the basis of S&L in-house data, vendor catalogs, industry publications, and other 

related projects. Quantities of materials were based on preliminary estimates by the project 

team. 

9.1.5 Labor 

An estimate of all construction-related costs, including construction management and startup 

and commissioning was prepared by Foster Wheeler. See “REV2_Basis of Labor Costs” in 

Appendix H. Additional information regarding the construction methodology that is used as the 

basis of the labor estimates is included in Section 10 of this report. 

9.1.6 Labor Productivity 

Labor productivity was accounted for in the cost estimates using two distinct factors. A regional 

productivity factor of 1.05 was applied to all direct labor work hours. This was the actual direct 

labor productivity experienced by Foster Wheeler on the Springerville Generating Station Unit 4 

construction project. Another productivity factor based on the difficulty of each item of work was 

included in the line items in the estimate spreadsheets, based on the differing construction 

aspects for each unit. For more details see section 1.6 “REV2_Basis of Labor Costs” in 

Appendix H, and Section 10 of this report. 

9.1.7 Project Indirect Costs 

Indirect costs for hiring the architect-engineer were included in the estimates. Construction 

management and startup and commissioning costs prepared by Foster Wheeler were also 

included. Estimated owner’s capital costs are also included. Owner’s costs include owner’s 

construction management, ammonia unloading facility at railhead, legal support, insurance, 

operating and maintenance support during construction and start-up, spare parts, contract 

services, lost generation during short outages and sales taxes. 

9.1.8 Escalation 

Escalation is not included in the estimate. All costs are in 2010 dollars. 

9.1.9 Contingency 

The project contingency was determined using a technique called range analysis. The cost 

estimates were divided into major cost centers, such as equipment, catalyst, steel, other 

materials, labor, indirects, etc. High and low ranges were established for each of these cost 

centers. These ranges were then entered into a software program utilizing Monte Carlo 

Simulation to determine an overall contingency for the project. The Monte Carlo Simulation was 

based on running 10,000 iterations, where the inputs are randomly generated from probability 

distribution curves to simulate the process of sampling. The output is a curve, on which a point 

gives a percentage confidence factor and the corresponding overall dollar amount for the project 
 

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to meet that confidence factor. For this project, we have used a 95% confidence factor to 

determine contingency dollars. 

9.1.10 Allowance for Funds Used During Construction 

Allowance for funds used during construction (AFUDC) has been calculated at 2.43% annual 

percentage rate.

9.1.11 Cash Flow 

Quarterly cash flows were prepared based upon 42-month schedules for the SCR Option cost 

estimates and 48-month schedules for SCR and Baghouse Option cost estimates. 

9.2 CAPITAL COST ESTIMATES 

The capital cost estimates present the following cost breakdown for NGS: 

• SCR 

• Anhydrous Ammonia 

• Sorbent Injection 

• Baghouse 

• Waste Collection System 

• Flue Gas System & ID Fans 

• BOP Piping & Equipment 

• Electrical-Auxiliary Power 

• Controls and Instrumentation 

• New structures 

• Removal and Relocation of existing equipment and infrastructure 

• Site services/sitework 

• Overtime, including Spot Overtime 

• Contractor General & Administrative 

• Contractor Profit 

• Indirect Expenses 

• Contingency

• Allowance for funds used during construction (AFUDC) 

The total estimated capital costs are as given below: 
 

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Table 9-1. Total Estimated Capital Cost Summary 

Unit 1 SCR (Estimate 30621B) $151,825,000

Unit 2 SCR (Estimate 30622B) $205,808,000

Unit 3 & Common SCR (Estimate 30623B) $186,528,000

Total for U1, U2, U3 SCR Only Option $544,161,000

 

Unit 1 SCR w/ DSI (Estimate 30412E) $154,946,000

Unit 2 SCR w/ DSI (Estimate 30413E) $209,324,000

Unit 3 & Common SCR w/ DSI (Estimate 30414E) $189,772,000

Total for U1, U2, U3 SCR Only w/ DSI Option $554,042,000 

 

Unit 1 SCR & BH (Estimate 30415E) $372,184,000 

Unit 2 SCR & BH (Estimate 30416E) $410,919,000 

Unit 3 & Common SCR & BH (Estimate 30417E) $347,869,000 

Total for U1, U2, U3 SCR and Baghouse Option $1,130,972,000 

9.3 BUDGETARY QUOTES 

9.3.1 SCR Catalyst 

Budgetary-level quotes were anonymously solicited from five vendors for the SCR catalyst 

required to reduce the NOX emissions without increasing the SO3 emissions above specified 

levels. These vendors are: 

• Ceram 

• Cormetech 

• Haldor-Topsoe 

• Hitachi 

• Johnson Mathey 

Quotes were received from Haldor-Topsoe and Johnson Mathey. These quotes, along with the 

letter specification sent to vendors, are included in Appendix K. Due to the ability to meet the 

required NOX emissions while also keeping the SO3 emissions below specified levels, the 
 

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Haldor-Topsoe quote was determined to be the most technically feasible and the cost was used 

as the basis for the cost estimate. 

9.3.2 Ammonia Storage and Feed System 

Budgetary-level quotes were anonymously solicited from two vendors for the ammonia storage 

and feed system required to support the SCR operation. These vendors are: 

• Chemithon 

• Wahlco 

Quotes were received from Wahlco. These quotes, along with the letter specification sent to 

vendors, are included in Appendix K. Subsequent to the initial solicitation, the total storage time 

for ammonia for the site was increased to 14 days. Revised pricing was solicited from Wahlco 

and has also been included in Appendix K in the form of an e-mail from Robyn Clark. Due to the 

ability to provide the ammonia in accordance with the letter specification, the Wahlco quote was 

determined to be the most technically feasible and the cost was used as the basis for the cost 

estimate. 

9.3.3 Dry Sorbent Injection System 

Budgetary-level quotes were anonymously solicited from three vendors for the dry sorbent 

injection system required to support the station subsequent to the installation of SCR systems. 

These vendors are: 

• FLSmidth 

• Nol-Tec 

• UCC 

Quotes were received from both Nol-Tec and UCC. These quotes, along with the letter 

specification sent to vendors, are included in Appendix K. Despite being more expensive, due to 

the ability to provide the dry sorbent injection system in accordance with the letter specification, 

the UCC quote was determined to be the most technically feasible and the cost was used as the 

basis for the cost estimate. 

9.3.4 Pulse-jet Fabric Filter 

Budgetary-level quotes were anonymously solicited from three vendors for the fabric filter, which 

may be required to reduce the particulate emissions for the site, with the ability to capture SO3, 

mercury, and fine particulate as well. These vendors are: 

• Alstom 

• Babcock & Wilcox (B&W) 

• Hamon Research Cottrell (HRC) 
 

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Quotes were received from all three vendors. These quotes, along with the letter specification 

sent to vendors, are included in Appendix K. Due to the ability to meet the required PM 

emissions while also addressing the requirement for a stacked fabric filter for Unit 2, the B&W 

quote was determined to be the most technically feasible and the cost was used as the basis for 

the cost estimate. 

9.3.5 ID Fans 

Budgetary-level quotes were anonymously solicited from Howden for new ID booster fans for 

the SCR and Baghouse Option as well as full rotor and bearing replacement for the SCR 

Option. 

Quotes were based on preliminary ID fan sizing calculations preformed by S&L and detailed in 

the Design Basis Document (Appendix A). Refer to Appendix K for the budgetary pricing quotes. 

9.3.6 Pulse-jet Air Compressors and Auxiliaries 

A budgetary-level quote was anonymously solicited from Atlas Copco for the pulse-jet air 

compressors and auxiliaries (aftercooler, air dryer and receiver tanks). The quote was based on 

sizing information provided to Atlas Copco. The methodology for the sizing is detailed in the 

Design Basis document Appendix A. Refer to Appendix K for the budgetary pricing quote. 

9.3.7 Unit Auxiliary Transformers 

Budgetary-level quotes were solicited from three vendors for the unit auxiliary power 

transformers required to support the station subsequent to the installation of SCR and 

Baghouse systems. These vendors are: 

• ABB 

• General Electric (GE) 

• Niagra 

Quotes were received from all three vendors. These quotes, along with the letter specification 

sent to vendors, are included in Appendix K. The Niagra quote was determined to be the most 

technically feasible by providing a detailed product quote and therefore the Niagra cost was 

used as the basis for the cost estimate. 

9.4 O&M COSTS 

9.4.1 Operating and Maintenance Costs 

The conceptual operating and maintenance (O&M) cost estimates provided in Appendix J are 

based on the installation of new NOx and particulate reduction equipment at NGS. These were 

generated based upon the following three operating scenarios: SCR installation only; SCR and 

DSI; and SCR, DSI, and Baghouse. 
 

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The cost estimates are conceptual in nature and based largely on S&L experience on similar 

projects. No significant preliminary engineering has been performed to firm up the project details 

and site specific characteristics have not been fully analyzed. Margin has been added to 

quantities, including sorbent feed rates, steam requirements, auxiliary power consumption, etc., 

to provide conservatism to these cost estimates. A summary of these costs are shown below in 

Table 9-2. 

Table 9-2. Conceptual O&M Costs (on a per Unit Basis) 

Variable O&M Unit Cost SCR Only SCR and DSI SCR and Baghouse

Ammonia $475/ton 1,035,000 $ 1,035,000 $ 1,035,000 $ 

Catalyst Replacement $8,000/m3 672,000 $ 672,000 $ 672,000 $ 

Auxiliary Power $45/MW-hr 1,809,000 $ 1,880,000 $ 3,832,000 $ 

Steam $5/mmBtu 71,000 $ 71,000 $ 71,000 $ 

Sorbent (Hydrated Lime) $200/ton - $ 119,000 $ - $ 

Sorbent (Trona) $125/ton - $ - $ 71,000 $ 

Waste Disposal** $50/ton - $ 82,000 $ 32,000 $ 

Bag Replacement $100/bag - $ - $ 450,000 $ 

Cage Replacement $30/cage - $ - $ 45,000 $ 

Total Variable O&M* $/year $ 3,859,000 3,587,000 $ 6,208,000 $ 

Fixed O&M SCR Only SCR and DSI SCR and Baghouse

Maintenance Material $/year 237,000 $ 239,000 $ 402,000 $ 

Maintenance Labor $/year 158,000 $ 159,000 $ 268,000 $ 

Total Fixed O&M*** $/year $ 398,000 395,000 $ 670,000 $ 

Total O&M Cost* $/year 3,982,000 $ 4,257,000 $ 6,878,000 $ 

* Based on 90% Capacity Factor. 

** Waste disposal cost represents levelized costs for trucking of waste to landfill site, development of landfill (dual 

liner with leachate collection system) and landfill maintenance. 

*** Operating & Maintenance 

- Maintenance, material and labor costs are calculated as a function of the overall capital cost for each 

option utilizing benchmarking data 

- SCR maintenance cost includes: ammonia unloading system monitoring, ammonia tank 

unloading, ammonia risk management plan, ammonia tank inspection, maintenance of ammonia 

pumps, dilution air blowers, supporting components, and annual ammonia injection grid tuning 

- SCR only and SCR & DSI options, fixed O&M costs calculated based upon 0.2% 

of capital cost 

- SCR& Baghouse option, fixed O&M costs calculated based upon 0.25% of capital cost 

- SCR & Baghouse maintenance cost includes: 1% bag replacement every year, compressor 

maintenance, hopper heater maintenance, and ash handling system 

9.5 TOTAL ANNUAL COSTS 

9.5.1 Total Annual Costs 

The total annual costs for the SCR option, SCR plus DSI option, and SCR plus Baghouse option 

are shown in Table 9-3. This table also includes a breakdown for each unit within each option. 
 

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The total annual cost is the sum of the annual capital cost and the annual operating and 

maintenance cost. The annual capital cost has been calculated by multiplying the total capital 

cost by a Capital Recovery Factor (CRF) of 0.1159. The CRF of 0.1159 is based on an annual 

interest rate of 9.8% and amortization period of 20 years 

Table 9-3. Levelized Annual Costs 

 SCR Option SCR with DSI 

Option 

 SCR & 

Baghouse Option 

Unit 1 Total Capital Cost $ 151,825,000 $ 154,946,000 $ 372,184,000 

Annual Capital Cost

(Total Capital Cost x CRF) $ 17,597,000 $ 17,958,000 $ 43,136,000 

Annual O & M Cost $ 3,982,000 $ 4,257,000 $ 6,878,000 

Total Annual Cost $ 21,579,000 $ 22,215,000 $ 50,014,000 

Unit 2 Total Capital Cost $ 205,808,000 $ 209,324,000 $ 410,919,000 

Annual Capital Cost

(Total Capital Cost x CRF) $ 23,853,000 $ 24,261,000 $ 47,626,000 

Annual O & M Cost $ 3,982,000 $ 4,257,000 $ 6,878,000 

Total Annual Cost $ 27,835,000 $ 28,518,000 $ 54,504,000 

Unit 3 Total Capital Cost $ 186,528,000 $ 189,772,000 $ 347,869,000 

Annual Capital Cost

(Total Capital Cost x CRF) $ 21,619,000 $ 21,995,000 $ 40,318,000 

Annual O & M Cost $ 3,982,000 $ 4,257,000 $ 6,878,000 

Total Annual Cost $ 25,601,000 $ 26,252,000 $ 47,196,000 

Units 

1,2,& 3 Total Capital Cost $ 544,161,000 $ 554,042,000 $ 1,130,972,000 

Annual Capital Cost

(Total Capital Cost x CRF) $ 63,069,000 $ 64,214,000 $ 131,080,000 

Annual O & M Cost $ 11,946,000 $ 12,771,000 $ 20,634,000 

Total Annual Cost $ 75,015,000 $ 76,985,000 $ 151,714,000 

Capital Recovery Factor (CRF) = 0.1159

Based on an interest rate of 9.8% and amortization period of 20 years
 

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10. CONSTRUCTION AND CONSTRUCTIBILITY 

As part of the cost estimating effort, Foster Wheeler, a major constructor for this type of work, 

was engaged to provide input into the construction aspects of the project. Input for this portion 

of the report has been provided by Foster Wheeler. 

10.1 CONSTRUCTION SITE PLAN 

10.1.1 Site Development and Temporary Facilities 

It is expected that the NGS site already has sufficient, existing infrastructure and temporary 

facilities to support the Units 1-3 SCR and baghouse construction retrofit project. These 

required facilities include parking areas for construction craft labor and management staff 

personnel, phone service and temporary electrical power distribution for site construction 

management office trailers and facilities, prepared material laydown and storage areas, and 

material assembly yards. The basis of this conceptual construction estimate is that sufficient 

facilities of this nature already exist to support mobilization of the required construction 

contractor(s). 

10.1.2 Laydown, Fabrication, and Staging Areas 

The construction plan is to use the existing prepared area southeast of Unit 3 for material 

laydown and ground-fabrication. This area was identified with the NGS management staff during 

the site visit of January 20-21, 2010, as the laydown and fabrication areas used for the prior 

scrubber retrofit projects. It is assumed that there is also existing space at site for storage of a 

limited amount of materials that would require climate-controlled storage. The basis of this 

conceptual construction estimate is that sufficient facilities of this type already exist at site. 

10.1.3 Cranes and Heavy Lift Considerations 

Foster Wheeler worked with Mammoet North America LLC (Mammoet) in the development of 

this estimate, to size the heavy lift cranes that would be required to support the installation 

strategy of ground-assembling at site, the SCR, baghouse, and flues into sections with weights 

ranging from 35-55 tons. Mammoet visited the NGS site on March 1-2, 2010 with Foster 

Wheeler and S&L representatives to review the conceptual arrangement drawings and the 

existing site conditions for the SCR and baghouse retrofit work. 

Based on their review of the site, the drawings, and the installation strategy, Mammoet has 

provided general arrangement drawings for the placement of the selected cranes for each unit, 

for both the SCR Option and the SCR and Baghouse Option. Mammoet also provided the 

equipment description and pricing to receive, transport, and set one auxiliary transformer per 

unit. Further detailed description of the heavy-lift cranage to be used is included in subsections 

below. 
 

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10.2 INSTALLATION METHODOLOGY 

Foster Wheeler developed a preliminary Level I construction schedule for the work (see 

Appendix G), which has been incorporated into the overall schedule also shown in Appendix G. 

Foster Wheeler’s construction schedule is based on direct labor work hours estimated from the 

quantities provided by S&L. The construction schedule was used to determine the approximate 

durations required for the heavy-lift equipment, and to develop the histogram for the 

approximate craft labor manpower required for the work. With the limited information available 

at this time and the high-level nature of this construction estimate, further detailed installation 

sequence and plans have not been determined. 

10.2.1 Substructure Work 

Based on previous experience with retrofit work on existing units, the construction estimate 

includes the cost of a specialty day-lighting contractor to determine any existing underground 

utilities or obstructions that may interfere with the installation of new underground materials. 

10.2.2 Foundations 

The basis of the estimate, from commodities to be installed, assumes that reinforcing bars, 

embedments and anchor bolts would be shop-fabricated to the maximum extent possible. It is 

also assumed that the concrete for foundations would be provided from an onsite batch plant. 

10.2.3 Equipment Installation 

In the SCR Option scenarios for the work, the ID fan rotors would be replaced. Work hours have 

been applied for the activity based on prior experience with rotor replacements in similar retrofit 

circumstances. The same information has been provided in the estimate for the new ID fans to 

be installed for the SCR and Baghouse Option scenarios, and for other miscellaneous 

equipment. 

10.2.4 SCR and Flue Installation 

The SCR materials are planned to be received at site in knocked down (flat) sections, consisting 

of casing plate with external stiffeners and attachments welded on in the fabrication shop. The 

materials received would be ground-assembled by site crews in the designated fabrication 

areas, to the maximum extent possible in order to minimize the erection time and congestion in 

the operating units. 

Ground-assembly areas would be designated southeast of Unit 3, and assembly tables for the 

flues and reactors would be constructed there. Several fabricated panels would be assembled 

on the tables into components of pre-determined size and weight that can be safely transported, 

lifted and set into place at final elevation. Based on prior experience, the weight of the groundassembled components would range between 35-55 tons depending on installation access and 

final support details. When those parameters are further determined, the detailed installation 

sequence and final component sizes and weights may be identified, and rigging diagrams and 

analysis completed. The conceptual cost estimates include time for engineered rigging drawings 
 

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to be produced for the critical component lifts, including constructability reviews for lifting lugs, 

spreader beams, etc. 

The flue and reactor components would be ground-fabricated at an elevation that would allow 

for maximum installation of insulation, lagging, platforms and nozzles, and they would be 

accessible during ground-assembly by means of scissor and man-lifts. Some internal scaffolds 

may be required to install trusses and turning vanes, but in most cases it is expected that the 

assembly work would be done with lifts. The component assembly dimensions would vary in 

width and height, not to exceed any existing conditions of the transport route to final location, 

which would be determined during the development of the engineered rigging drawings. The 

ground-assembled components would be moved from the assembly yard to the installation 

crane staging areas by 12-line hydraulic transporter. 

All components that are insulated on the ground would have an un-insulated setback of 

approximately 1’-6” from the erection joint to allow for fit up and welding after the component is 

erected. Scaffolding would be required at these setback areas, when components are at final 

elevation to accomplish fit up, welding, and any remaining insulation that was either left off at 

the erection joints, or that could not be installed because of weight or dimension restrictions. 

For the Unit 1 SCR Option, a 660-ton capacity crawler crane would be positioned south of the 

existing service building, and just west of the new SCR locations. Refer to crane placement 

drawing, Appendix E, Attachment 2, which illustrates the proposed location of the crawler crane 

in plan and elevation views and the associated lifting capacities at various radii. 

For the Unit 2 SCR Option, a 1,250-ton capacity and a 660-ton capacity crawler crane would be 

needed due to the existing Unit 2 chimney blocking access to set certain new flue segments 

from just one location. The 1,250-ton crane would be positioned directly east of the existing 

Unit 1 pump building. The 660-ton crane would be positioned at the identified location north of 

the existing Unit 3 chimney. Refer to Appendix E, Attachment 4, which illustrates the proposed 

location of each crane in plan and elevation views, and the associated lifting capacities at 

various radii. 

For the Unit 3 SCR Option, a 660-ton capacity crawler crane would be positioned in the existing 

parking lot, adjacent to and just south of the existing maintenance facility, which would be 

demolished to allow for the erection of both new SCRs. Refer to Appendix E, Attachment 6, 

which illustrates the proposed location of the crawler crane in plan and elevation views and the 

associated lifting capacities at various radii. 

Structural steel support members and rack components would be ground-assembled into bents 

and structural modules where applicable, and are not expected to be critical lifts due to weight 

or size restrictions. 

Piping would be double-jointed for rack piping and shop-fabricated to the maximum extent, 

including valves, that would allow for transport and erection. 
 

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10.2.5 SCR Tie-In Work 

Prior to the outage, the SCR and the new inlet and outlet flues would be installed up to the tie-in 

points for the precipitator plenums and the air pre-heater inlet plenums. The new SCR inlet 

flues, outlet flues and support steel would be installed to a point that would allow for the 

demolition of the existing flues and the installation of the new flues and blanking plates. Since 

the tie-in to the air pre-heater plenums is under the existing lower precipitator plenum, the 

existing flues would be cut and lowered down to the new support steel bridging between the 

boiler structure and the precipitator structure. The demolished flues would be rolled out on a 

temporary handling system to a staging area where they can be lifted with the erection crane. 

The new SCR outlet flues (or air pre-heater inlet flues) and blanking plates would then be set on 

the same staging area and rolled into place. The blanking plates would be set on top of the air 

pre-heater inlet flues, so that once they are rolled into place they can be fit and welded to the 

bottom of the remaining lower precipitator plenum. After the air pre-heater inlet flues are in 

place, the remaining SCR inlet support steel and flues would be erected and tied into the 

precipitator upper and lower plenums. Because of the proximity of the new versus the existing, it 

is expected that the air pre-heater inlet flues and blanking plates would be installed without 

being insulated in the ground-assembly area, and would be insulated after they are installed at 

elevation. 

It is also expected that the startup and commissioning procedures would allow for the SCR 

catalyst and seals to be installed prior to the tie-in outage. 

10.2.6 Baghouse Installation 

The individual baghouse cells are expected to be shipped in shop-assembled modules. The 

hopper and roof sections would be ground-assembled in sections that can be safely transported 

and erected. The lower sections of the baghouse can be erected and accessed by man-lifts; 

however, after the lower sections are installed, scaffolding would be installed to complete the 

installation and for insulation purposes. 

Because of the handling, fit-up and weld-out activities associated with the external sections of 

the baghouse, it would be erected bare, and insulated after all the seal welds have been leak 

tested. All flue sections from the baghouse to the axial fans and up to the tie-ins would be 

installed, leak-tested, and insulated prior to the outage. All seal welds on the flues, baghouses, 

SCR reactors, and air ducts would be leak-tested with bio-diesel and accepted by site quality 

inspectors prior to insulating. Final tie-ins would be accepted with the same process. 

The two booster fans per unit would be completely installed with the exception of the tie-ins to 

the existing flues prior to the outage. 

For the Unit 1 SCR and Baghouse Option, a second 660-ton capacity crawler crane would be 

required to install the baghouses and associated flues, in addition to the 660-ton capacity crane 

for the SCRs. For the elevated baghouse, the crane would be positioned in the existing roadway 

directly north of the new baghouse location. For the baghouse located at grade, the crane would 

be positioned in the existing roadway northeast of the new baghouse location. Refer to 
 

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Appendix E, Attachment 3 (4 sheets), which illustrates the proposed location of the crawler 

crane in plan and elevation views and the associated lifting capacities at various radii. 

For the Unit 2 SCR and Baghouse Option, only the 1,250-ton capacity crawler crane would be 

required, with one relocation necessary. The relocation is necessary due to the existing Unit 2 

chimney blocking access for setting certain new flue segments and baghouse components. One 

crane setup position would be located directly east of the existing Unit 1 pump building, and 

directly north of the existing ash dewatering system. The other crane setup position would be 

located directly east of the existing Unit 2 pump building, and directly south of the existing ash 

dewatering system. Refer to Appendix E, Attachment 5, which illustrates the proposed location 

of each crane in plan and elevation views, and the associated lifting capacities at various radii. 

For the Unit 3 SCR and Baghouse Option, a second 660-ton capacity crawler crane would be 

required to install the baghouses and associated flue sections north of the baghouse and west 

of the Unit 3 chimney. The second crane is in addition to the 660-ton capacity crane for the 

SCRs. The second crane would be positioned along the existing roadway directly south of the 

new baghouse locations. Refer to Appendix E, Attachment 7, which illustrates the proposed 

location of the crawler crane in plan and elevation views and the associated lifting capacities at 

various radii. 

10.2.7 Outage requirements 

In order to relocate existing plant utilities and equipment to make room for the SCR and 

baghouse installation, it is anticipated that a short outage on the order of a week in duration 

would be required relatively early in the construction phase for each unit, about eighteen months 

prior to the major tie-in outage. Since this outage is not one of NGS’s regularly scheduled 

outages, the costs for lost generation associated with this outage have been included in the cost 

estimate. As shown in the preliminary construction schedule, it is expected that the major tie-in 

work for the SCRs and baghouses can be accomplished within the station’s scheduled 8-week 

outage durations. Since this major outage is one of NGS’s regularly scheduled outages, no 

additional costs for lost generation associated with this outage have been included in the cost 

estimate. 

10.3 STARTUP AND COMMISSIONING 

The preliminary Level I construction schedule developed in association with this estimate allows 

for approximately four months of startup and commissioning time. The schedule basis is that 

turnover of commissionable systems would start before the tie-in outage, and would conclude at 

approximately the completion of the outage. 

Based on previous experience with retrofit work on existing units, the construction estimate 

includes the cost of startup and commissioning staff and craft labor based on a percentage of 

project direct labor expense. It is anticipated that the startup and commissioning personnel for 

the expected duration would include approximately one (1) commissioning manager, three (3) 

commissioning engineers, and a support craft labor crew of fifteen (15) direct craftsmen and (7) 

indirect craftsmen at peak. The cost of time at site for equipment vendor representatives is not 

included in this estimate. 
 

 

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APPENDIX A.

DESIGN BASIS

Item 

SCR and Baghouse Capital Cost Estimate Design Basis, Revision B – April 16, 2010 
 

 

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APPENDIX B.

CAPITAL COST ESTIMATE EQUIPMENT LIST

Item 

SCR Option Capital Cost Estimate Equipment List 

SCR and Baghouse Capital Cost Estimate Equipment List 
 

 

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APPENDIX C.

CLIMATE DATA
 

 

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APPENDIX D.

PIPING AND INSTRUMENTATION DIAGRAMS

No. Title 

MSK-1002-01/02/03 Unit 1 Compressed Air System SCR and Baghouse (3 sheets) 

MSK-1003-01 Unit 1 Ammonia Vaporizing and Dilution Air Skids 

MSK-1004-01 Unit 1 Dry Sorbent Injection System Silo and Blowers 

MSK-1005-01 Unit 1 Flue Gas System SCR and Baghouse 

MSK-1005-02 Unit 1 Flue Gas System SCR 

MSK-1006-01 Unit 1 Waste Ash System SCR and Baghouse 

MSK-2002-01/02/03 Unit 2 Compressed Air System SCR and Baghouse (3 sheets) 

MSK-2003-01 Unit 2 Ammonia Vaporizing and Dilution Air Skids 

MSK-2004-01 Unit 2 Dry Sorbent Injection System Silo and Blowers 

MSK-2005-01 Unit 2 Flue Gas System SCR and Baghouse 

MSK-2005-02 Unit 2 Flue Gas System SCR 

MSK-2006-01 Unit 2 Waste Ash System SCR and Baghouse 

MSK-3002-01/02/03 Unit 3 Compressed Air System SCR and Baghouse (3 sheets) 

MSK-3003-01 Unit 3 Ammonia Vaporizing and Dilution Air Skids 

MSK-3003-02 Unit 3 Ammonia Vaporizing and Dilution Air Skids 

MSK-3003-02 Units 1-3 Anhydrous Ammonia Unloading Stations and Storage Tank 

MSK-3004-01 Unit 3 Dry Sorbent Injection System Silo and Blowers 

MSK-3005-01 Unit 3 Flue Gas System SCR and Baghouse 

MSK-3005-02 Unit 3 Flue Gas System SCR 

MSK-3006-01 Unit 3 Waste Ash System SCR and Baghouse 
 

 

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APPENDIX E.

CRANE PLACEMENT

Att. No. Title 

1. Level 1 Construction Schedule 

2. Unit 1 SCR Only Lift Options 

3. Unit 1 SCR & Baghouse Lift Options 

4. Unit 2 SCR Only Lift Options 

5. Unit 2 SCR & Baghouse Lift Options 

6. Unit 3 SCR Only Lift Options 

7. Unit 3 Baghouse Only Lift Options 
 

 

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APPENDIX F.

ELECTRICAL SINGLE-LINE DIAGRAMS

No. Title 

ESK-1000 Option A, SCR Option - Units 1-3 and Common 

ESK-1001 Option B, SCR and Baghouse Option - Unit 1 

ESK-1001 Option B, SCR and Baghouse Option - Unit 2 

ESK-1001 Option B, SCR and Baghouse Option - Unit 3 
 

 

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APPENDIX G.

PROJECT SCHEDULES

Item 

Foster Wheeler Schedule 

SCR Option Level 1 Schedule 

SCR Option Level 3 Schedule 

SCR and Baghouse Option Level 1 Schedule 

SCR and Baghouse Option Level 3 Schedule 
 

 

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APPENDIX H.

FOSTER WHEELER BASIS OF LABOR

Att. No. Title 

1. Not Used (see Foster Wheeler Schedule in Appendix G) 

2. SCR and Baghouse Capital Cost Estimate 

3. SCR and Baghouse Construction Estimate – Heavy Lift and Transportation 

4. Mammoet Heavy Lift Proposal 

5. Pullman Power Estimate 

6. Construction Cost Estimate, Rev. 1 
 

 

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APPENDIX I.

GENERAL ARRANGEMENT DRAWINGS

No. Title 

MSK-1000 Units 1-3 SCR Option Site Plan 

MSK-1001 Units 1-3 SCR and Baghouse Option Site Plan (2 sheets) 

MSK-1002 Unit 1 SCR Option Site Plan 

MSK-1002 Unit 2 SCR Option Site Plan 

MSK-1002 Unit 3 SCR Option Site Plan 

MSK-1003 Unit 1 SCR and Baghouse Option Site Plan 

MSK-1003 Unit 2 SCR and Baghouse Option Site Plan 

MSK-1003 Unit 3 SCR and Baghouse Option Site Plan 
 

 

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APPENDIX J.

CONCEPTUAL CAPITAL COST ESTIMATES

Item/No. Title 

Conceptual Cost Estimate Summary 

Detailed Costs 

30621A SCR Option Unit 1 

30622A SCR Option Unit 2 

30623A SCR Option Unit 3 and Common 

30412D SCR with Dry Sorbent Injection Option Unit 1 

30413D SCR with Dry Sorbent Injection Option Unit 2 

30414D SCR with Dry Sorbent Injection Option Unit 3 and Common 

30415D SCR and Baghouse Option Unit 1 

30416D SCR and Baghouse Option Unit 2 

30417D SCR and Baghouse Option Unit 3 and Common 

Risk Analysis to Determine Contingencies 

Quarterly Cash Flows 

O&M Costs 
 

 

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APPENDIX K.

SPECIFICATION SUMMARY PACKAGES

Item 

SCR Option Ammonia Storage and Feed System 

SCR Option Catalyst 

SCR Option Dry Sorbent Injection System 

SCR Option ID Fan Rotor Replacement 

SCR and Baghouse Option Pulse Jet Fabric Filters 

SCR and Baghouse Option Air Compressor 

SCR and Baghouse Option ID Booster Fans 

SCR and Baghouse Option Unit Auxiliary Transformer 
 

 

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APPENDIX L.

MASTER PROCUREMENT LIST
 

 

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APPENDIX M.

MODEL FILES

[.jsm Files] 
 

 

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APPENDIX N.

MODEL VIEWS

Item 

SCR Aerial 

SCR Iso 

SCR Plan 

Unit 1 SCR West 

Unit 2 SCR West 

Unit 3 SCR West 

Baghouse Aerial 

Baghouse Iso 

Baghouse Plan 

Unit 1 Baghouse West 

Unit 2 Baghouse West 

Unit 3 Baghouse West 
 

 

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APPENDIX O.

SRP-PROVIDED DATA

Appendix O.1 - Underground Piping 

No. Title 

A-665-C143 Key Plan 

A-665-C148 Area Plan Sheet 5 

A-665-C149 Area Plan 

A-665-C150 Area Plan Sheet 7 

A-665-C151 Area Plan Sheet 8 

A-665-C152 Area Plan Sheet 9 

A-665-C153 Area Plan Sheet 10 

A-665-C154 Area Plan Sheet 11 

A-665-C155 Area Plan Sheet 12 

A-665-C165 Area Plan Sheet 22 

A-665-C169-1 Area Plan Crystallizer Building, Brine Concentrators, Cooling Tower, Blow Down Surge 

Tanks, Condensate Storage Tank 

A-665-C169-2 Brine Concentrator and Crystallizer Area 

A-665-C262 Water Treatment Area Plan 
 

 

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APPENDIX O.

SRP-PROVIDED DATA

Appendix O-3 – Howden 
 

 

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APPENDIX O.

SRP-PROVIDED DATA

Appendix O-4 – Navajo Questionnaire 
 

 

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APPENDIX O.

SRP-PROVIDED DATA

Appendix O-5 – SGS Coal Analysis 
 

 

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APPENDIX O.

SRP-PROVIDED DATA

Appendix O-6 – Flue Gas 

No. Title 

- APH Flue Gas Inlet Temp 

- ESP Outlet Flue Gas Temp vs Load 

- Historian Data List 

- NOx vs Load 

- O2 vs Load 

SK92-M0018 Air/ Gas Sys. Static Pressure Profile 
 

 

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APPENDIX O.

SRP-PROVIDED DATA

Appendix O-7 – Acid Mist Sampling 

No. Title 

- Rev-Pt1of2 Navajo Acid Mist 264-001 11-16-09 

- Rev-Pt2of2 Navajo Acid Mist 264-001 11-16-09 
 

 

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APPENDIX O.

SRP-PROVIDED DATA

Appendix O-8 – Equipment Data 

No. Title 

- Air Preheater 

- FD Fans 

- ID Fans 

- Precipitator 

- Steam Generator 
 

 

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APPENDIX P.

NATIONAL PARK SERVICE 

&

ENVIRONMENTAL PROTECTION AGENCY 

COMMUNICATIONS

No. Title 

1 Minutes of SRP/ NPS meeting July 20, 2010 

2 Summary of NPS comments and SRP responses 

3 SRP and NPS email communication 

4 SRP Responses to EPA comments in 8/24/2010 meeting 

5 Calculation of cost using EPA Pollution Control Cost Manual (PCCM) 
 

 

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APPENDIX Q.

PRESENTATION FOR NPS 
 

 

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APPENDIX R.

PRESENTATION FOR EPA