Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 1 of 129 Approval of Air Quality Implementation Plans; Navajo Nation; Regional Haze Requirements for Navajo Generating Station

Technical Support Document for Proposed Rule

Docket Number: EPA-R09-OAR-2013-0009

Executive Summary

This document provides the analytical framewor k and technical justific ation to support the proposed determination of the Best Available Re trofit Technology (BART) for the Navajo Generating Station (NGS) pursuant to the Regional Haze Rule (RHR). This BART determination is limited to emissions of oxides of nitrogen (NO

x ) from NGS.

1. Background

Pursuant to the Tribal Authorit y Rule, EPA Region IX (EPA) fi nds that the BART requirement

for NO

x of the RHR is necessary or appropr iate to apply at this time to NGS. 1 In making our BART Determination for these facilities, we examined the following factors as prescribed by the Clean Air

Act: 2

 Factor 1 examines the cost of compliance for the technically feasible control technologies;

 Factor 2 addresses the energy and non-air qu ality impacts of the control technologies;

 Factor 3 considers any existing air pollu tion control technologies at the source;

 Factor 4 considers the remaining useful life of the source; and

 Factor 5 assesses the degree of visibility improvement expected to result from the various control technologies.

These factors are frequently referred to as the “Fiv e Factor Analysis” for a BART determination under

the RHR.

On behalf of Salt River Project (SRP), co-own er and operator of NGS, ENSR Corporation, now AECOM, submitted a BART engineering and vi sibility analysis (dated November 2007) 3 to EPARegion IX. Per requests for additional information and modeling from EPA, SRP submitted a sourcespecific modeling protocol on June 10, 2008 4 and a revised BART Analysis for NGS dated January

2009. 5 Additional submissions from SRP include: letter dated July 29, 2008, 6 letter dated June 3, 2009

with additional informa tion on CALPUFF modeling, 7 and a Conceptual Ammonia Monitoring Plan dated June 18, 2009. 8

1 40 CFR 49.11(a).

2 42 U.S.C. § 7491(g)(2).

3 BART Analysis for the Navajo Generating Station Units 1 – 3, Prepared for Salt River Project – Navajo Generating Station by ENSR|AECOM, Document Number 05830-012-300, November 2007.

4 Source Specific BART Modeling Protocol: Navajo Generating Station by ENSR|AECOM, Document Number 05830-012- 300, September 2007.

5 Revised BART Analysis for the Navajo Generating Station Units 1 – 3, Prepared for Salt River Project – Navajo Generating Station by ENSR|AECOM, Document Number 05830-012-300, January 2009.

6 Best Available Retrofit Technology (BART) Analysis – Cost In formation Navajo Generating Station, from Kevin Wanttaja to Deborah Jordan, June 29, 2008, and Attachment: Salt River Project Navajo Generating Station, SCR and SNCR Cost Study, Final Report, Prepared by Sargent and Lundy, Project Number 11234-028, rev. 3, July 25, 2008.

7 Letter from Kevin Wanttaja to Anita Lee re: May 7, 2009 M eeting on Navajo Generating Station Best Available Retrofit Technology Analysis, dated June 3, 2009 and Attachment: Review of Background Ammonia Concentrations Used inTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 2 of 129 Based on these analyses, SRP recommended that the installation of new combustion controls on Units 1 – 3 represented BART. AECOM did not conduct a BART engineering and vi sibility analysis for particulate matter (PM) because SRP concluded that the current PM cont rols at the facility already met BART. A source-specific Federal Implementation Plan for NGS fi nalized on March 5, 2010 (75 FR 10174) set a PM limit of 0.06 lb/MMBtu on a plant-wide basis. In its January 2009 submittal, SRP

recommended a short-term PM BART limit of 0.05 lb /MMBtu. EPA is not proposing to determine that it is necessary or appropriate to determine BART for PM at NGS.

On August 28, 2009, EPA published an Advanced Notice of Proposed Rulemaking (ANPRM) in the Federal Register (74 FR 44313) and requested comment on the anticipated visibility improvements at surrounding Class I areas and the cost effectiveness of controls for BART at NGS and the Four Corners Power Plant (FCPP). EPA presented results of visibility modeling and cost analyses submitted by SRP as well as results of visibility modeling conducted by EPA and cost analyses submitted by the National Park Service (NPS). The publication of the ANPRM provided an opportunity to begin

consultations with affected tribes and conti nued an on-going consultation with the Federal Land Managers (FLMs) as required under the RHR (40 CF R §51.308(h)(4)(i)(2)). We w ill continue to consult with the tribes and the FLMs during th e comment period for this proposal.

EPA received requests for consultation and co mments on the ANPRM from numerous tribes, including the Ak-Chin Indian Co mmunity, Inter Tribal Council of Arizona, Gila River Indian Community, Hopi Tribe, Navajo Nation, Tohono O’ odham Nation, and the Salt River Pima Maricopa Indian Community. Additionally, EPA received co mments from Federal and State agencies, numerous industry, utility, and water groups, environmental and community-based organizations, cities and municipalities, U.S. and State Representatives, and the Governor and Tr easurer of Arizona. All

comments received on the ANPRM are available in the ANPRM docket. 9 We have reviewed and

considered all comments relevant to NGS and re vised our analyses to address comments as we determined appropriate. We have addressed specific comments resulting from our consultations with affected states, tribes, and the FLMs and included a discussion of those comments in this Technical Support Document (TSD), but will not i ssue a response to comments on the ANPRM.

Subsequent to our publication of the ANPRM , EPA received information from numerous stakeholders, including SRP, Department of Interi or (including the Bureau of Reclamation and the National Park Service), and the Gila River Indi an Community. SRP provided numerous submittals of

additional information to EPA and affirmed its re commendation that the instal lation of new combustion controls on Units 1 – 3 represente d BART: letter dated August 18, 2010 with an updated SCR cost study and a cost estimate for baghouses, 10 a final report and power point presentation on the ambient air measurements of ammonia, 11 letters dated October 15, 2010, and February 22, 2011 with additional

Visibility Improvement Modeli ng for the Navajo Generating Station Regional Haze BART Analysis by Robert Paine, AECOM Environment and Ivar Tombach, Consultant.

8 Conceptual Plan for Ammonia Monitoring in the Vicinity of the Navajo Generating Station, by Robert Paine, AECOM Environment and Ivar Tombach, Consultant, June 18, 2009.

9 See Docket #: EPA-R09-OAR-2009-0598 on www.regulations.gov.

10 SRP Cost Study – Installation of Selective Catalytic Reduction (SCR) and Baghouses at Navajo Generating Station, from Kevin Wanttaja to Anita Lee, August 18, 2010. Attachment: Salt River Project – Navajo Generating Station Units 1, 2, 3 SCR and Baghouse Capital Cost Estimate Report, Prepared by Sargent and Lundy, Project Number 12656-001, August 17,

2010.

11 Measurements of Ambient Background Ammonia on the Colorado Plateau and Visibility Modeling Implications, Prepared by Salt River Project, Contributors: Ivar Tombach and Robert Paine, September 2010. Power Point presentation from SRP dated September 28, 2010.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 3 of 129 modeling information, 12,13 an updated BART analysis on January 20, 2012, 14 additional modeling information by letter dated February 27, 2012, 15 and by electronic mail on February 28, 2012, 16

additional information on SNCR cost information on March 16 and 23, 2012, 17 and an analysis of the broader economic impacts of BART controls on the state of Arizona on April 11, 2012. 18 On July 20, 2012, SRP submitted additional information on SNCR to confirm that it expected SNCR to achieve NO

x emission rates on the upper end of the ra nge it presented in earlier submissions. 19

SRP also provided information to EPA outlining several uncertainties that significantly increase

the financial risk of near-term investments in new ai r pollution controls , including uncert ainties in plant ownership and lease agreements. On e of the owners of NGS, the Los Angeles Department of Water and Power (LADWP), a public utility located in Californi a, is prohibited from c ontinued participation and long-term investments in NGS beyond its current contract term of 2019, under California law. 20 As a result, LADWP has indicated its inte ntion to sell its 21.2 percent owne rship stake in NGS. The future

owner of LADWP’s share of NGS is currently uncertain. 21

In addition, NGS’s current site le ase with the Navajo Nation, as well as several other agreements and contracts, expire in 2019. Although the owners of NGS are in negotiations with the Navajo Nation

for a lease renewal to extend to 2044 and with Peabody Energy for a renewed coal supply contract, the outcomes of these negotiations are also not yet fi nalized. Because NGS is located in Indian country, lease and other rights-of-way agreement renewals must be approved by the Department of the Interior. These approvals, which are an unusual requirement fo r continued operation of a power plant, are federal actions that trigger review unde r the National Environmental Prot ection Act (NEPA). For actions significantly affecting the environm ent, NEPA review requires the de velopment of an Environmental Impact Statement (EIS) and include s a substantial process for public involvement. The Department of

the Interior estimated that NEPA review for approval of leases and other rights-of-way agreements may require approximately 5 years to complete. 22 Therefore, even if the Nava jo Nation and the owners of NGS reach agreement on renewed leases and other ri ghts-of-way shortly, the owners of NGS may not have a lease fully approved by the Departme nt of the Interior until 2017 or later.

To begin discussions of the numerous complexiti es and stakeholder inte rests in NGS, following the ANPRM, in 2011, SRP initiated a seri es of stakeholder meetings f acilitated by EN3 Professionals, LLC with the goal of developing an agreement am ong key stakeholders on an alternative BART

12 Additional Information Requested During Meeting on September 28, 2010 Best Available Retrofit Technology Determination – Navajo Generating Station, from Kevin Wanttaja to Anita Lee, October 15, 2010.

13 Visibility Modeling using Upgraded CALPUFF Model – Salt River Project Navajo Generating Station from Richard Hayslip to Anita Lee, February 22, 2011.

14 Updated Best Available Retrofit Technology Analysis, Navajo Generating Station, from Kelly J. Barr, Esq., to Deborah Jordan, January 20, 2012.

15 Letter from Angelina Cervantes, SRP to Scott Bohning, EPA, dated February 27, 2012. Transmittal of CD of modeling archive files for January 2012. The SRP modeling files are available upon request from EPA because these files cannot be posted to the electronic docket.

16 NGS Modeling Spreadsheet from Grant Smedley to Colleen McKaughan, February 28, 2012, and attachment to email: Navajo BART Emissions and Results from Jan 2012 Archive.xlsx.

17 SNCR Cost Breakdown and Urea Cost Estimate from Grant Smedley to Anita Lee, March 16, 2012 and March 23, 2012.

18 Harvey Economics Report, fro m Kelly J. Barr, Esq., to Deborah Jordan, April 11, 2012.

19 SNCR Letter from Kelly J. Barr to Deborah Jordan, July 20, 2012.

20 See information on Senate Bill 1368 available from: http://www.energy.ca .gov/emission_standards/

21 See, for example, 2012 Draft Integrated Resource Pl an Executive Summary at https://www.ladwp.com/ladwp/f aces/wcnav_externalId/a-p-doc?_adf.ctrl-st ate=a8ti68apu_29&_afrL oop=234058941927000.

22 See email and attachment from Letty Belin, DOI to Janet McCa be, EPA, dated August 20, 2012, in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 4 of 129 proposal to present to EPA for consideration. 23 The stakeholders did not produce a consensus plan, but during the discussion process, the Department of Interior (DOI) de termined that given its various responsibilities relate d to Navajo Generating Station (through th e National Park Service and the Bureaus of Reclamation and Indian Affairs), it would be help ful to contract with th e National Renewable Energy Lab (NREL), under the Department of Energy, to de velop an NGS-specific evaluation of factors relevant to EPA’s BART determination (phase I) , and conduct a more thorough evaluation of renewable energy options (phase II). 24 DOI requested that EPA refrain from proposing a BART determination for

NGS until after December 2011 to allow NREL time to complete and submit to EPA phase I of its study. EPA confirmed that we would not propose a BART determination prior to December 2011 because of our on-going technical analyses, consultations with Tribes and meetings w ith other stakeholders. 25 On January 18, 2012, DOI released the phase I NREL re port for public comment and on March 29, 2012, provided a compendium of all public comments submitted on the NREL report to EPA. 26 On February 13, 2012, Bureau of Reclamation and EPA held a jo int conference call to discuss EPA’s questions

related to the Lower Colo rado River Development Fund, 27 and on April 6, 2012, the National Park Service submitted additional observations on the updated 2012 BART analysis submitted by SRP to EPA and the visibility modeli ng section of the 2012 NREL report. 28

During 2009 – 2012, representatives from EPA Re gion IX and the EPA Office of Air and Radiation held consultation meetings with several tribes in Arizona at various levels of government, including with tribal leaders, tribal councils, a nd staff and management from tribal environmental departments. 29 The Gila River Indian Community (Gila Ri ver) contracted with Harvey Economics to conduct an analysis to estimate the potential impact s to Gila River of poten tial control scenarios for NGS. Gila River provided copi es of these reports, dated N ovember 16, 2011 and March 15, 2012, to

EPA for consideration in our BART analysis. 30 On August 7, 2012, EPA met with Governor Gregory Mendoza and other representatives of the Gila Ri ver Indian Community in Sacaton, AZ, and with President Ben Shelly and represen tatives of the Navajo Nation in San Diego, CA. On August 27, 2012, EPA held a joint consultation session in Phoenix, AZ with interested tribes on NGS and provided the opportunity for tribes to m eet individually with EPA. 31 Chairman Shingoitewa and representatives from the Hopi Tribe, Vice-Chairman William Antone and representatives of the the Ak-Chin Indian Community, Lt. Governor St ephen Roe Lewis and representatives of the Gila River Indian Community the Tohono O’odham Nation, the Navajo Nation, the Fort McDowell Yavapai Nation, the Tonto Apache Tribe , the Yavapai-Prescott Tribe, and the Hu alapai Tribe attended th e consultation meeting. Representatives from the Bureau of Reclamation a nd the Bureau of Indian Affairs also attended.

23 http://en3pro.com/projects/ngs-project/

24 Letter from David J. Hayes, Deputy Secretary of the Interior, to Jared Blumenfeld, Regional Administrator, EPA Region IX, July 12, 2011.

25 Letter from Jared Blumenfeld to David J. Hayes, July 18, 2011.

26 Navajo Generating Station and Air Visibility Regulations: A lternatives and Impacts, David J. Hurlbut, Scott Haase, Gregory Brinkman, Kip Funk, Rachel Gelm an, Eric Lantz, Christina Larney, Davi d Peterson, Christopher Worley (NREL) and Ed Liebsch (HDR Engineering, Inc.), January 2012, NREL/TP-6A20-53024, produced under direction of the U.S. Department of the Interior under Interagency Agreemen t R11PG30024. Report and Co mpendium are available at http://www.doi.gov/navajo-gss/index.cfm

27 See document titled “Information from Reclamation to EPA” in the docket for this proposed rulemaking.

28 Letter from Herbert C. Frost, Ph.D., Associate Director, Na tional Resources Stewardship and Science of the National Park Service, to Jared Blumenfeld, April 6, 2012.

29 See document titled “Timeline of all tribal consultations on BART.docx” in the docket for this proposed rulemaking.

30 See letter from Edward F. Harvey to Linus Everling, General Counsel, Gila River Indian Community re: Proposed EPA BART Changes to NGS dated November 16, 2011, plus attachment and letter from Edward F. Harvey to Linus Everling, re: Updated Impacts of EPA BART Changes at NGS on the GRIC- Revised Cost of Capital Assumption, dated March 15, 2012.

31 See Agenda and handout from August 27, 2012 Tribal Consultation in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 5 of 129 2. EPA’s Five-Factor BART Analysis

Appendix Y to Part 51 – Guidelines for BART Determinations Under the Regional Haze Rule (BART Guidelines) outlines the process for conducti ng a five-factor BART analysis (70 FR 39104, July 6, 2005). The BART Guidelines establishe d numerical presumptive limits for NO

x for coal-fired EGUs greater than 200 MW located at greater than 750 MW power plants and operating without postcombustion controls (i.e., selec tive catalytic reduction – SCR, or selective non-catalytic reduction – SNCR), differentiated by boiler design and type of coal burned. For the three units tangential-fired boilers burning bituminous coal at NGS, the presumptive limit for NO

x is 0.28 lb/MMBtu. Although the BART Guidelines set presumptive limits, the presum ptive limits do not obviate the need to identify the best system of continuous emission control techno logy on a case-by-case basi s considering the five

factors. EPA considered all of the information su bmitted by interested stakeholders in our statutory five-factor BART analysis for NGS . The results of our five-factor BART analysis are summarized in

Table ES-1.

Table ES-1: Summary of EPA’s Five Factor BART Analysis for NGS

LNB/SOFA SNCR+LNB/SOFA SCR+LNB/SOFA

Emission Limit (lb/MMBtu) 0.24 0.18 0.055Factor1 Total Capital Cost $45 million

– already spent $84 million $541 million

Annualized Capital Cost $5.2 million $29 million $64 million

Annual O&M Cost $0 $19 million $11.9 million

Total Annual Cost ($/year) $5.2 million $23.5 million $58.8 million

Emissions Reductions (tpy) 10,865 16,608 28,573

Average Cost Effectiveness $486 / ton $1,745 / ton $2,240 / ton

Incremental Cost Effectiveness ($/ton) n/a $4,110 / ton (vs. LNB) $3,315 /ton (vs. LNB) $2,933 (vs. SNCR)Factor2 Will SCR force NGS to close? (compliance by 2018) No : Increase in Net Present Value from SCR = $648 million vs. NPV from Low Market = $673

million

Electricity Rate in 2018 for SRP

Customers (compliance by 2018) 9.26 ¢/kWh
(Baseline) 9.28 ¢/kWh (0.2%) 9.32 ¢/kWh (0.6%)

CAP Water Rates (Energy only)

in 2018 (compliance by 2018) $58 per acre foot (AF)
(Baseline) $61/AF
(5% increase for Tribes) $66/AF
(14% increase for Tribes)3 Existing Controls at NGS LNB/SOFA was installed on all 3 units at NGS over 2009

– 2011;

Hot

‐ side ESPs for PM and Wet FGD for SO 24 Remaining Useful Life of NGS EPA used a default amortization period of 20 years. Owners of NGS are seeking to extend lease

of NGS to 2044 (over 30 years).5 Largest Single Class I Area Visibility Improvement 2.1 dv (35% change in dv) 3.1 dv (40% change in dv) 5.4 dv (71% change in dv)

Cumulative Visibility

Improvement (11 Class I areas) 16 dv (33% change in dv) 22 dv (45% change in dv) 35 dv (73% change in dv)

AECOM identified six NO

x control technologies and dete rmined that three of those technologies, SCR, SNCR, and low-NO

x burners with separated ove rfire air (LNB/SOFA), are technically feasible for the units at NGS. Of the three technically feasible options, SCR in combinationTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 6 of 129 with LNB/SOFA results in the largest reduction in NO

x emissions. EPA is proposing to determine that an SCR system, in combination with LN B/SOFA, can be designed to meet a NO

x emission limit of 0.055 – 0.080 pounds of NO

x per million British Thermal Units of heat input (l b/MMBtu) at NGS, depending on the number of catalyst layers in the syst em, i.e., more layers of catalyst result in greater

levels of NO

x control. EPA is requesting comment on the im pact of these two different control levels (0.055 and 0.08 lb/MMBtu) on the ability of NGS to retain its current 6-year cycle for major outages.

The first factor evaluates the cost of controls . EPA finds that even using the cost analysis submitted by Sargent and Lundy (S&L) for SRP, the costs per ton of NO

x removed from SCR (average of $2,926 per ton, not including the LN B/SOFA already installed) are within a range that has been

determined reasonable for BART. EPA used S&L’s cost estimates and made several revisions to assumptions based on guidelines in the EPA Control Cost Manual to generate cost projections that are more consistent with the BART guidelines. EPA estim ated an average cost effectiveness of less than $2,300 per ton to install SCR+LNB/SOFA on all three units at NGS. EPA estimates that the incremental cost effectiveness of SCR+LNB/SOFA compared to LNB/SOFA (the technology SRP recommended as BART) is about $3,300 per ton, and the incrementa l cost effectiveness of SCR+LNB/SOFA to SNCR+LNB/SOFA is about $2,900 per ton. Based on the cost data presented by SRP, EPA’s revisions to SRP’s cost estimates, and our analysis of av erage and incremental cost effectiveness, EPA is proposing to determine that SCR in combination with LNB/SOFA at NGS to achieve 0.055 lb/MMBtu

is cost effective.

The second factor involves consideration of th e energy and non-air quality impacts of controls. Because NGS is not located on a commercial rail line, the installation of SCR or SNCR would result in increased truck traffic deliveries of anhydrous amm onia or urea to NGS. EPA conducted analyses of the potential air quality impacts associat ed with emissions from increased tr uck traffic, and also considered potential risks associated with tr ansportation and use of anhydrous a mmonia, and determined that SCR and SNCR are not likely to result in a significant health risk to th e local population. Because of the importance of NGS to the economy of the Navajo Nati on and the Hopi Tribe, EPA also considered the concern expressed to EPA that requiring SCR as BART will cause NGS to shut down and result in a loss of jobs at NGS and the Kayenta Mine. The Navajo Nation receives taxes and lease payments directly from NGS, and both the Navajo Nation and Hopi Tr ibe receive royalties and taxes from Peabody Energy associated with coal mined from the Kayenta Mi ne and used at NGS. EPA conducted an affordability analysis to determine whether it would be more ec onomical for the owners of NGS to install new NOx controls and continue operating, or to close and purchase an e quivalent amount of power on the wholesale power market. Based on this 25-year Net Pr esent Value analysis, the increase in electricity generation costs associated with SCR is expected to be lower than the cost to purchase electricity on the wholesale market, suggesting that the cost increase from SCR should not cause NGS to shut down. This analysis further estimates that the NGS cost of elect ricity generation as a result of SCR will increase by 16%, or 0.6 cents per kilowatt-hour (kWh ). This generation cost increase tr anslates into an increase of

less than 1% to electric ity customers of SRP.

In addition to impacts on electricity customer s, numerous parties submitted comments to EPA that raised concerns about the potential impact to water customers of the Central Arizona Water Conservation District (CAWCD) th at operates, maintains, and is responsible for repayment to the Federal Government for the Central Arizona Project (CAP). Reclamation’s 24% ownership share of power produced by NGS is used by CAP to pump surf ace water from the Colorado River to municipal, industrial, agricultural, and tribal water users in central Ariz ona. Excess power owned by Reclamation that is not used by CAP is sold and profits ar e deposited into the Lower Colorado River Basin Development Fund (Development Fund). This fund was originally authorized under the Colorado RiverTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 7 of 129 Basin Act of 1968 for the purpose of repaying the fede ral government for the cost to build CAP, and subsequent settlement acts with several Indian Tribes located in Arizona authorized use of the fund to pay the delivery portion of the co st of CAP water (fixed operations, maintenance, and replacement, or OM&R, costs) for certain Indian Tribes, and to pay th e costs to construct the de livery systems to bring CAP water to those Tribes. Reclamation, CAWCD, and several Tribes submitted detailed comments on the ANPRM outlining the potential effects that requi ring SCR as BART for NGS might have on the cost of water and on Indian water settlement agreements.

Costs associated with Reclamation’s share of capital improvements at NGS are passed onto CAP customers in the variable OM&R costs, i.e., “pumpi ng energy rate”. Tribal and non-Indian agricultural (NIA) users of CAP water pay onl y variable OM&R. Municipal and Industrial (M&I) CAP customers pay both the variable OM&R costs and fixed OM&R (delivery charges). EP A estimates that the increased electricity generation cost at NGS from th e installation of SCR on all 3 units may result in an energy rate (variable OM&R) increas e of $8.40 per acre-foot (AF). Base d on projected water rates, an increase of $8.40 per AF represents an estimated 6% increase in the CAP water rate paid by M&I users,

and a 14.5% increase in the CAP water rate paid by NIA and Indi an water users.

EPA understands that at least sixt een tribes in Arizona either ha ve water settlement agreements that allocate CAP water to the tribes in exchange for releasing rights and cl aims to other surface and groundwater resources in Arizona (see nine tribes listed in first column of Table ES-2), or are in the process of negotiating CAP water settlement agreemen ts (see eight tribes listed in second column of Table ES-2). Additionally, Table ES-2 lists five tribes located in Arizona where EPA lacks information on the tribe’s relationship to CAP water. EPA understand s that all tribes generally each have different CAP allocations and unique water settlement agreemen ts; therefore, potential impacts may be different for each tribe and should be considered individually. EPA’s preliminary assessments are based on limited available information, and EPA requests commen ts or additional information from the tribes listed in Table ES-2, and other tr ibes that may be affected by EP A’s proposed rulemaking for NGS.

Table ES-2: List of Tribes Located in Arizona and Relationships to CAP Water 32

Tribes with CAP Allocations Tribes in Process of Developing Water Settlement Agreements Tribes Where Relationship to

CAP is Not Known to EPA
Gila River Indian Community Navajo Nation Colorado River Indian Tribes

Ak-Chin Indian Community Yavapai-Apache Nation (Camp Verde) San Juan Southern Paiute Tribe of

Arizona Tohono O’odham Nation Hopi Tribe Cocopah Indian Tribe San Carlos Apache Tribe Pascua Yaqui tribe Quechan Indian Tribe White Mountain Apache Indian Tribe* Tonto Apache Tribe Chemehuevi Indian Tribe of the

Chemehuevi Reservation Fort McDowell Yavapai Nation* Havasupai Tribe of the Havasupai

Reservation Salt River-Pima Maricopa Indian Community* Hualapai Indian Tribe of the Hualapai

Reservation Navajo Nation Kaibab Band of Paiute Indians of the

Kaibab Reservation Yavapai-Prescott Tribe*

32 Tribes marked with an asterisk (*) lease all or most of their CAP allocations to cities in Arizona. The Navajo Nation has an

allocation of CAP water defined in the Arizona Water Settleme nt Act of 2004, but has not yet reached agreement on the terms of receiving the allocation.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 8 of 129 For the second factor, EPA concludes that NGS is unique compared to other coal-fired power plants in the nation because of its relationship to CAP and tribes located in Arizona. EPA’s affordability analysis suggests that th e cost to produce power at NGS with S CR installed on all units should be below the market prices of wholesale power and therefor e SCR should not cause NGS to close. Additionally, increased electricity rates to cust omers of the utilities that own NGS should be relatively low.

EPA understands that a potential incr ease in water rates to tribes is a critical issue for them. We note that, as described in the followi ng section, past polluti on control investments at this facility have made use of alternative financing methods that limited impacts on CA P water rates. Furthermore, the NREL report indicated that mechanisms may exist to help avoid or mitigate the estimated level of impact. EPA, in conjunction with DOI and DOE, have committed to work togeth er on several short- and long-term goals, including innovative clean energy options for electricity generation and seeking funding to cover expenses for the fede ral portion of po llution control at NGS. Howeve r, it is not clear at this time whether or what type of mechanisms might be available to lessen increased costs. Therefore, as explained further below, EPA believe s that the potential economic impacts discussed in this section argue for thoughtful consideration of how flexibil ity in the compliance timeframe can be provided consistent with the air qualit y goals of the Clean Air Act.

EPA is specifically seeking comment on opportunities to reduce and/or avoi d significant impacts on water settlement tribes while maintaining visibili ty protection for the 11 affected Class 1 areas. In addition, EPA, in conjunction with Interior and the Department of Energy, have committed to work together on several short- and long-term goals, in cluding seeking funding to cover expenses for the federal portion of pollu tion control at NGS. 33 EPA understands that if f unds are available to cover Reclamation’s portion of air pollution control costs at NGS, water rate incr eases to tribes and others that

use CAP water would not occur as a result of BART. The agencies will wo rk together with stakeholders to identify and implement actions that support implementation of BA RT, including seeking funding to cover expenses for plant pollution control or othe r necessary upgrades for the federal portion of NGS. The agencies will also work to jointly support a phase 2 report on NGS clean energy options and work with stakeholders to develop a roadmap for acco mplishing the goals described above. Although this collaboration may span several years, EPA expect s the alternative strategies resulting from the collaboration may also cont ribute to reductions in NO

x emissions at NGS.

Factor three explores the existing controls at the source. Units 1 – 3 at NGS are equipped with flue gas desulfurization units to re duce emissions of sulfur dioxide (SO 2 ) and electrostatic precipitators to reduce emissions of particulate matter. In 2 008, EPA issued a pre-construction permit authorizing

SRP to install low-NO

x burners plus separated ov erfire air (LNB/SOFA) on Units 1 – 3 at NGS. Over the 2009 – 2011 timeframe, one unit per ye ar at NGS was retrofit with new NO

x combustion controls to meet a permitted emission limit of 0.24 lb/MMBt u. Because SRP, and Grand Canyon Trust, an environmental organization that fi led comments on the proposed permit, agreed that EPA’s issuance of the PSD permit authorizing SRP to install and oper ate LNB/SOFA on Units 1 – 3 should not prejudice the analysis of additional NO

x controls under the BART requireme nt of the Regional Haze Program,

EPA has determined that consideration of the exis ting controls at NGS does not warrant eliminating SCR as the most stringent, techni cally feasible, cost effective NO

x emission control technology in our BART analysis. EPA notes that over the period fro m 2009 – 2018, the early inst allation of LNB/SOFA at NGS will result in over 90,000 tons more NO

x reductions than would have been achieved if

33 See Joint Federal Agency Statement Regarding Navajo Generating Station, dated January 4, 2013, in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 9 of 129 LNB/SOFA were installe d in conjunction with a BART determ ination (i.e., by 2018). EPA is proposing to determine that existing controls at NGS do not warrant elimination of S CR as BART, but that the early NO

x reductions achieved from SRP’s voluntary installation of LNB/SOFA in 2009 – 2011

warrants further consideration wh en weighing all five factors.

The fourth factor considers th e remaining useful life of the f acility. Although comments to the ANPRM have cited the age of NGS and impending leas e and right-of-way negotia tions with the Navajo

Nation as a rationale to consider a shorter useful life, EPA is proposi ng to determine that the default 20- year amortization period is most appr opriate to use as the remaining us eful life of the facility. Without an enforceable obligation to shut down early, EPA ca nnot consider a shorter am ortization period in our analysis. Additionally, EPA further understands that the owners of NGS are pursuing a lease agreement with the Navajo Nation to operate until 2044. EPA is proposing to determine that there are no issues with the remaining useful life of NGS that warrant rejecting SCR as BART.

The fifth factor examines the visibility impr ovement resulting from co ntrols. The anticipated visibility benefits were mode led using CALPUFF Version 5.8. B ackground ammonia concentrations assumed in the model are an important component of the visibility impacts mode l. Based on results from four different ammonia background scenarios, EPA de termined that although th e assumed concentration impacts the absolute modeled visibil ity benefits, it does not change the ranking of controls, i.e., the most stringent control technol ogy, SCR+LNB/SOFA, results in the highest modeled visibility improvement. All ammonia background scenarios resu lt in perceptible improvements in vi sibility at the most impacted Class I areas. EPA’s modeling shows th at the baseline impairment at the eleven Class I areas affected by NGS ranges from over 1 deciview at the least-impacted Class I areas to over 8 deciviews at the mostimpacted Class I area. The installation of SCR in co mbination with LNB/SOFA on all 3 units at NGS is anticipated to reduce the visibi lity impairment caused by NGS by 5.4 deciviews at the two mostimpacted Class I areas (Grand Canyon National Park and Capitol Reef Nationa l Park). The greatest visibility benefits from LNB/SOFA alone and SNCR in combinati on with LNB/SOFA is anticipated to be 2.1 and 3.1 deciviews, respectively. See Table ES-1. EPA is proposing to determine that the visibility benefits of SCR are significant and do not warrant its elimination as the top control option for BART.

3. EPA’s Proposed BART Determinatio n and Proposed BART Alternative

The BART Guidelines give states (and EPA) di scretion in determining the relative weight of each factor in making a BART determination. EPA is proposing to determine that the average and

incremental costs of SCR are cost effective. Ad ditionally, the visibility benefits from SCR are anticipated to be significant, and given the long expected useful life of NGS (at least until 2044), EPA is proposing to determine that a NO

x emission limit of 0.055 lb/MMBtu, achievable with the installation of SCR systems with four layers of catalyst on all three units, in combin ation with the existing LNB/SOFA,

is BART for NGS.

However, as discussed in Factor 2, NGS is unique compared to all other co al-fired power plants in the nation in terms of its relationship with wate r and tribal water users in Arizona. Because of the potential adverse economic impacts of higher water co sts on tribes located in Arizona, EPA is proposing a BART Alternative consistent with the RHR (40 CFR §51.308(e)(2)). Under the RHR, Alternatives to BART must achieve greater reasonable progress th an would be achieved through the installation and operation of BART, and all necessary emission reductions must take place during the period of the first long-term strategy for regional haze, which, for states that were required to submit RH SIPs in December 2007, ends in 2018. EPA is also proposing that consideration of compliance schedulesTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 10 of 129 beyond 2018 for alternative measures at NGS is appr opriate for several reasons, including the singular importance of NGS to many tribes located in Arizona and their water settlement agreements with the federal government, the numerous uncertainties faci ng the owners of NGS, the requirement for NEPA review of a lease extension, and th e early and voluntary installation of modern combustion controls over

the 2009 – 2011 timeframe.

We are proposing, as an alternative to BART, to require NGS to meet a NO

x limit of 0.055 lb/MMBtu on one unit per year in 2021, 2022, and 2023. As shown in Table ES-3 below, EPA has

calculated that the total amount of NO

x that will be emitted from NGS over the 2009 - 2044 timeframe under EPA’s proposed BART determination (i.e., compliance by 2018) will equal 358,974 tons. EPA

has also calculated that the total NO

x emissions over 2009 – 2044 under Alte rnative 1, with credit for the early and voluntary emission reductions, will be 338,189 tons.

EPA is proposing to find that the an alternative is “b etter than BART” if the adjusted total NO

x emissions over the 2009 – 2044 timeframe (i.e., emi ssions remaining after subtracting 92,715 tons for the LNB/SOFA credit for early and voluntary emissi on reductions) are less th an total emissions under our proposed BART determination for the same peri od (i.e., 358,974 tons). Based on its adjusted total

NO

x emissions, Alternative 1 meets this threshol d (i.e. 338,189 tons is less than 358,974 tons). Therefore, EPA is proposing Altern ative 1 (compliance with BART emission limits on one unit per year in 2021, 2022, and 2023) as a better-tha n-BART alternative th at results in greater reasonable progress

than would be achieved under BART.

Table ES-3: Analysis of Proposed BART Alternative

BART Alternative 1 Installation Years by 2018 2021, 2022, and 2023 Total Emissions over 2009 - 2044 (tons) 358,974 430,904 LNB/SOFA Credit (tons) n/a 92,175 Adjusted Emissions (tons) n/a 338,189

Better than BART? n/a Yes (338,189 tons < 358,974 tons)

EPA recognizes that some limited additiona l flexibility beyond the 2021 – 2023 compliance schedule under Alternative 1 may be appropriate, gi ven the importance of NGS to a broad range of

interests. EPA has evaluated two other alternative schedules, using the “bette r than BART” analysis framework described above, to evaluate additional time for compliance, i.e., compliance on one unit per year in 2023, 2024, and 2025 (Alternative 2) and compliance on one unit per year in 2024, 2025, and 2026 (Alternative 3).

As shown in Table ES-4, Alternatives 2 and 3 do not by themselves meet the “better than BART” threshold because the adjusted emissions (accounting for the LNB/SOFA credit) exceed total emissions under BART. In Table ES-4, the amount total emissions from the alternative exceeds BART

is the NO

x emissions reduction deficit. For Alternatives 2 and 3, the NO

x emission reduction deficits are 15,179 tons and 33,160 tons, respecti vely, showing that as the compliance dates under a given alternative extend further into the future, the NO

x emission reduction deficit grows. Because

Alternatives 2 and 3 do not meet th e “better than BART” threshold, EP A views Alternatives 2 and 3 as viable only if the owners of NGS achieve additiona l emission reductions to bridge the deficit in NO

x emission reductions. These additional emission reductions could be implemented as short-term (i.e., for some subset of the period 2009 - 2044) or long -term (i.e., achieved annually until 2044) measures.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 11 of 129 Because Alternatives 2 and 3 do not currently meet the “better than BART” threshold we are not proposing to approve them in this action, but we are soliciting comment on them. If we receive additional information supporting approval of Altern ative 2 and/or 3, we will publish a supplemental proposal.

As shown in Table ES-4, if the owners of NG S complied with the sche dule under Alternative 2, a short-term emission reduction bridge (implement ed, for example, over a 10-year period from 2013 – 2023), the owners of NGS would need to achieve additional NO

x emission reductions of 1,518 tons per year. Similarly, implementing a long-term emission reduc tion bridge (for exampl e, over the period of 2013 – 2044) would require additional NO

x emission reductions of 490 tons per year. The short and long term emission reduction bridges in Table ES-4 provi de examples of how additional emission reductions might be distributed over time. The actual annual emi ssion reductions that NGS would need to bridge

the NO

x deficit would depend, not only on the size of th e deficit, but on the specific measures and time periods chosen by the owners of NGS.

Table ES-4: Analysis of Additional Alternatives

BART Alternative 2 Alternative 3

Installation Years by 2018 2023, 2024, and 2025 2024, 2025, and 2026 Total Emissions (tons) 358,974 466,869 484,849 LNB/SOFA Credit (tons) n/a 92,175 92,175 Adjusted Emissions (tons) n/a 374,154 392,134

Better than BART? n/a No No

Emission Reduction Deficit (tons) n/a 15,179 33,160

Short-term Emission Bridge (tpy) (years in place) n/a 1,518 tpy over 2013-2023 3,015 tpy over 2013-2024

Long-term Emission Bridge (tpy) (years in place) n/a 490 tpy over 2013-2044 1,070 tpy over 2013-2044

EPA is requesting comment on technically an d economically feasible technologies or

mechanisms to serve as enforceable emission reducti on bridges (whether short or long term) that would

allow consideration of alternatives that would not otherwise meet th e “better than BART” threshold for

NO

x (e.g., Alternatives 2 or 3 or ot her alternatives suggested by stak eholders during the public comment period for this proposed rule).

In weighing the statutory f actors, EPA believes that our BART determination for NO

x is appropriate for NGS. NGS is among the largest power pl ants in the nation, both in terms of its heat input capacity and in terms of total emissions of NO

x . Therefore, EPA is proposing that SCR, which is cost effective and will result in signifi cant visibility improvement, is BART for NGS, because it is expected to continue operation for at leas t three more decades and is surrounded by eleven mandatory Federal Class I areas, including the Grand Canyon National Pa rk. Because of the potential adverse economic impacts to tribes located in Arizona , we are proposing Alte rnative 1 as a “better than BART” Alternative that provides Reclamation and the other owners of NGS flexibility in the schedule for compliance, to resolve outstanding lease and rights -of-way agreements to ensure c ontinued operation of NGS, and to

allow time for Reclamation to work with other federa l agencies to seek funding for the federal portion ofTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 12 of 129 the cost of controls, recognizing th e importance of the continued opera tion of NGS to numerous tribes located in Arizona and the broader regional economy.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 13 of 129 Table of Contents

1. Introduction Page A. Brief History and Descripti on of Navajo Generating Station 18 B. Regional Haze Rule 19 C. Relationship between Air Polluta nts and Visibility Impairment 20

D. A BART Determination for NO

x is Necessary or Appropriate 21 E. Discussion of BART Presumptive Limits for NO

x 24 F. Advanced Notice of Proposed Rulemaki ng and EPA Approach to Consultation with Affected States, Tribes, and FLMs 25 G. An Extended Time to Comply with BART is Necessary or Appropriate 26

i. Consideration of Uncertainties 27

ii. Consideration of Impacts to Tribes 27

iii. Consideration of Federal Collaboration 28 2. Technology Available 29 A. NGS Approach to this Factor 29

B. Discussion of Factor in ANPRM 30 C. Affected State, Tribe, and FLM Consultation 31 D. EPA Conclusions Regarding this Factor 31 3. Factor 1: Costs of Compliance 34 A. NGS Approach to this Factor 35

B. Discussion of Factor in ANPRM 36 C. Affected State, Tribe, and FLM Consultation 38 D. EPA Conclusions Regarding this Factor 41 4. Factor 2: Energy and Non-Air Quality Environmental Impacts of Compliance 50 A. NGS Approach to this Factor 50

B. Discussion of Factor in ANPRM 50 C. Affected State, Tribe, and FLM Consultation 51 D. EPA Conclusions regarding this Factor 53 i. Energy and Non-Air Quality Environmental Impacts 53 ii. Economic Impacts of Compliance 56 a. Projected Impacts on Electricity Generation Costs and Retail Rates 57 b. Projected Impacts on Water Rates in Arizona 60 c. Sensitivity to Other Uncertainties 61 d. Potential Impacts to Tribes Located in Arizona 64 e. Potential Impacts to Non-Indian Agriculture Users 75 f. Potential Impacts to Municipal and Industrial Users 76 g. Broader Economic Impacts to Arizona 76 iii. EPA’s Proposed Determination for Factor 2 77 5. Factor 3: Any Existing Pollution Control Technology at the Source 78 A. NGS Approach to this Factor 78

B. Discussion of Factor in ANPRM 78 C. Affected State, Tribe, and FLM Consultation 78 D. EPA Conclusions regarding this Factor 79 6. Factor 4: Remaining Useful Life of the Source 80 A. NGS Approach to this Factor 80

B. Discussion of Factor in ANPRM 80Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 14 of 129 C. Affected State, Tribe, and FLM Consultation 80 D. EPA Conclusions regarding this Factor 81 7. Factor 5: Degree of Improvement in Visi bility Which May Reasonably Anticipated to Result From the Use of Such Technology 81 A. BART Guidelines and Modeling Protocols 81

B. Ammonia 90

C. Sulfuric Acid 90 D. NGS Approach to this Factor 91

E. Discussion of Factor in ANPRM 93 F. Affected State, Tribe, and FLM Consultation 98 G. EPA Conclusions regarding this Factor 102

8. Overall BART Determination 121 A. NGS Approach to this Factor 121 B. Affected State, Tribe, and FLM Consultation 121 C. EPA Conclusions regarding this Factor 123Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 15 of 129 List of Tables

Table 1: NGS Operational Characteristics ...................................................................................... .......... 18 Table 2: Facility-wide NO

x Emissions from NG S from 2001 – 2012 ...................................................... 22

Table 3: Leases and Contract Rene wals for NGS and Kayenta Mine ...................................................... 27 Table 4: Analysis of Available NO

x Control Options for NGS Presented by AECOM ........................... 30

Table 5: Annual NO

x emissions and Projected Emissions (lb/ MMBtu) from Control Options as reported by AECOM in November 2007 Submittal to EPA ................................................................................... 31 Table 6: AECOM and S&L Capital and Annual Cost Estimates, Percent Emissions Reductions, and Cost

Effectiveness for NO

x Controls (from January 2009 revised BART analysis) ........................................ 36

Table 7: Cost Estimates for SCR+ LNB/SOFA presented in ANPRM ..................................................... 37 Table 8: Cost Estimates for LNB/SOFA presented in ANPRM ............................................................... 37 Table 9: 2010 Capital and Annual Cost Estimates fo r SCR and Additional Polluta nt Controls Estimated by S&L for SRP ................................................................................................................ ........................ 39

Table 10: Revised SNCR and LNB/SOFA Co st Estimates from SRP in 2012 ........................................ 40 Table 11: Cost Effectiveness Calculated by SRP, as reported in its 2012 Revised BART Analysis ....... 41 Table 12: Summary of EPA Revisions to S&L Cost Inputs for SCR on Unit 2 ...................................... 41 Table 13: EPA Revisions to Cost Estimates for SCR (2010 dollars) ....................................................... 42 Table 14: Cost Comparison of SCR+LNB/SOFA React or Sizes Based on EPA Revisions to 2010 S&L

Costs ......................................................................................................................... ................................. 45 Table 15: Average and Incremental Cost Effectivene ss of Dominant Control Options Calculated by EPA

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

Table 16: Estimated Cost Effectiveness of SCR for Several Western Power Plants................................ 49 Table 17: Increase in Electricity Generation Costs ($/kWh) from NO

x Controls at NGS Presented in

ANPRM ......................................................................................................................... ........................... 51 Table 18: Summary of Cost after Installing SNCR and SCR versus Mark et Trends if Compliance with BART by 2018 .................................................................................................................. ........................ 58

Table 19: Increase in Electric ity Generation Costs in 2018 .................................................................... . 59 Table 20: Estimated Pumping Cost Increase from SCR ........................................................................... 61 Table 21: Lease, Permit and Contract Renewa ls Required for NGS or Kayenta Mine ............................ 63 Table 22: Summary of Tribes with CA P Allocations or Using CAP Water ............................................ 69 Table 23: Flue Gas Flow Sequence and Air Pollution C ontrol Equipment at NGS as reported in its July 3, 2008 Part 71 Operating Permit .............................................................................................. ............... 78 Table 24: Measured Visibility Impairment at Class I areas (2006 – 2008 average), from IMPROVE monitoring network ............................................................................................................ ....................... 81

Table 25: Class I Areas in CALPUFF Modeling for NGS ....................................................................... 83 Table 26: Selected CALMET settings for NGS .................................................................................... ... 88

Table 27: AECOM Mode ling Inputs (lb/hr) ...................................................................................... ...... 91 Table 28: Assumptions Used by AECOM for H 2 SO 4 Emission Estimates .............................................. 92 Table 29: Ammonia backgr ound concentration in ppb ............................................................................. 92 Table 30: Impacts of NGS on Visibility (98 th Percentile of daily maximum dv) at Eleven Class I Areas as Modeled by AECOM and as reported by EPA in ANPRM ................................................................. 93 Table 31: Ammonia background concentrations in ppb determined by EPA used in ANPRM ............... 95 Table 32: Visibility Impairment ( 98th Percentile dv) of NGS on Eleven Class I Areas as Modeled by EPA as reported in our ANRPM .................................................................................................. ............. 96 Table 33: Percent Improvement in Deciview Impair ment based on EPA modeling for Each Class I Area

from NO

x Controls at NGS as reported in ANPRM ................................................................................. 96 Table 34: Alternative Visibility Metric as reported in ANPRM ............................................................... 97Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 16 of 129 Table 35: NPS Modeling Results – Average 8 th High Baseline and Delta dv Improvement from 2001 –

2003........................................................................................................................... .............................. 100 Table 36: Assumptions used in Sulfuric acid (H 2 SO 4 ) Emissions Calculations ..................................... 104 Table 37: Class I area groupings for ammoni a background used in this proposal ................................. 106 Table 38: Ammonia background concentrations in ppb modeled by EPA used in proposal ................. 107 Table 39: Ammonia background concentrations in ppb for modeled by EPA for nitrate check ............ 110 Table 40: Scenarios Modeled by EPA fo r our BART Analysis for NGS ............................................... 112 Table 41: EPA Modeling Inputs (lb/hr) ......................................................................................... ......... 112 Table 42: EPA Modeling Results – 8 th High Delta dv Baseline Impacts of NGS on 11 Class I Areas from 2001 – 2003 for the Different Ammonia Background Scenarios ........................................................... 115 Table 43: EPA Modeling Results – 8 th High Delta dv Improvement and Percent Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Ammonia Background Scenario Am1

............................................................................................................................... .................................. 117 Table 44: EPA Modeling Results – 8 th High Delta dv Improvement and Percent Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Ammonia Background Scenario Am2

............................................................................................................................... .................................. 118 Table 45: EPA Modeling Results – 8 th High Delta dv Improvement and Percent Change in Delta dv Impact Compared to Baseline Impacts from 2001 – 2003 using Ammonia Background Scenario Am5

............................................................................................................................... .................................. 119 Table 46: Number of days with delta deciview imp acts greater than or equal to 0.5 dv in 2001-2003 . 120 Table 47: Analysis of Proposed BART Alternative ............................................................................... 127 Table 48: Analysis of Additional Alternatives ................................................................................. ...... 128Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 17 of 129 List of Commonly Used Acronyms and Abbreviations

AECOM AECOM Environmental ANPRM Advanced Notice of Proposed Rule Making

BART Best Available Retrofit Technology

CAA Clean Air Act CFR Code of Federal Regulations

DV or dv Deciview ENSR ENSR Corporation EPA U.S. Environmental Protection Agency ESP Electrostatic Precipitator

FGD Flue Gas Desulfurization FIP Federal Implementation Plan FLM Federal Land Manager FR Federal Register

FS U.S. Forest Service

FWS U.S. Fish and Wildlife Service

H 2 SO 4 Sulfuric Acid

LNB Low NO

x Burners NAAQS National Ambient Air Quality Standards NGS Navajo Generating Station

NH 3 Ammonia

NO

x Oxides of Nitrogen

NPS National Park Service

NSPS New Source Performance Standard

NSR New Source Review

OFA Over Fire Air OM&R Operation, Maintenance, and Replacement

PJFF Pulse Jet Fabric Filter

PM Particulate Matter PSD Prevention of Significant Deterioration

RGFF Reverse Gas Fabric Filter SCR Selective Catalytic Reduction S&L Sargent and Lundy SNCR Selective Non-Catalytic Reduction

SO 2 Sulfur Dioxide SOFA Separated Over Fire Air SRP Salt River Project TPY (tpy) Tons Per Year TSD Technical Support DocumentTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 18 of 129 

### 1. Introduction

A. Brief History and Description of Navajo Generating Station

The Navajo Generating Stati on (NGS) is a mine-mouth coal -fired power plant located on the Navajo Nation Indian Reservation, near Pa ge, Arizona and consists of three 750 megawatt (MW) coal-fired electric utility steam generating units with a total net capacity of 2250 MW (See Table 1). NGS was constructed before many of the statutory programs required by the Clean Air Act Amendments (CAAA) of 1977 such as New Source Review (NSR) and Prevention of Significant Deterioration (PSD). The facilities that predate these preconstruction review programs are generally referred to as “grandfathe red” facilities and are not required to comply with subsequently enacted statutory provisions.

Units 1, 2, and 3 are over 35 years old and ar e co-owned by several entities: the U.S. Bureau of Reclamation (Reclamation) owns 24.3%, Salt River Project (SRP), which also serves as the facility operator owns 21.7%, Los Ange les Department of Water and Power (LADWP) owns 21.2%, Arizona Public Service (APS) ow ns 14%, Nevada Power Company owns 11.3%,

and Tucson Electric Power owns 7.3%. These utilit ies serve electricity customers in Arizona, California, and Nevada.

Table 1: NGS Operational Characteristics

Unit 1 Unit 2 Unit 3
Boiler Type Dry Bottom, Tangential

Fired Dry Bottom, Tangential

Fired Dry Bottom, Tangential

Fired Year Operation Began 1974 1975 1976

Capacity (net MW) 750 750 750
Average Heat input (gross) (MMBtu/hr) 34 8,007 8,420 7,845

Average Operating Hours per

year 7,616 8,120 7,913

NO

x Baseline emission rate (lb/MMBtu) 35 0.36 0.36 0.34

PM Baseline emission rate (lb/MMBtu) 36 < 0.03 < 0.03 < 0.03

Federal participation in NGS was authorized in the Colorado River Basin Project Act of 1968 as a preferred alternative to building hydroelectric dams in the Grand Canyon for providing power to the Central Arizona Project. 37 The Central Arizona Project (CAP) is a 336-mile water distribution system that was built to deliver about 1.5 million acre-feet (AF) per year of Colorado

River water from Lake Havasu in western Arizon a to agricultural water users, Indian tribes located in Arizona, and municipal water users in Maricopa, Pinal, and Pima counties in central

Arizona. 38 This CAP water is used to meet the te rms of a number of Indian water rights

34 Average heat input and operating hours reported to EPA Clean Air Markets Division for 2001 – 2003.

35 Average NO

x emissions reported to EPA Clean Air Markets Division for 2001 – 2003.

36 From ENSR BART Analysis for SRP-NGS, page ES-1.

37 http://www.usbr.gov/projects//ImageServer?imgName=Doc_1303158888395.pdf

38 http://www.cap-az.com/Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 19 of 129 settlements and to reduce groundwater usage in the region. Electricity from NGS powers the pumps to move CAP water to its destin ations along the distribution system. 39

Several tribes located in Arizona have allo cations of CAP water through water settlement agreements that have been approved through acts of Congress. In excha nge for allocations of

CAP water at reduced cost and ac cess to funds for the development of water infrastructure, these

tribes have released their claims to other surface or sub-surface water in Arizona. Excess NGS power owned by Reclamation that is not used by CAP is sold a nd revenues are deposited into a fund to support of water settlement agreements. R eclamation and the Department of Interior play an important role in the development of these settlement agreements and the management of funds for water infrastructure development for tribes. The coal used by NGS is supplied by the Kayenta Mine, operated by Peabody Energy and locat ed on reservation lands of both the Navajo Nation and the Hopi Tribe. Taxes and royaltie s from NGS and the Kayenta Mine paid to the Navajo Nation and Hopi Tribe contribute si gnificantly to the a nnual revenues for both

governments.

Yet, NGS is located near many of our mo st treasured National Parks and Wilderness Areas. Congress mandated heightened protection for these areas in designating them as mandatory Class I Federal areas. The Federal La nd Managers of National Parks and Wilderness Areas, the National Park Service and the U.S. Fish and Wildlife Service, under the Department of Interior, and the U.S. Forest Service, under the Department of Agriculture, play important roles in the protection of visibility in the mandatory Class I Federal areas.

B. Regional Haze Rule

The visibility protection requirements in the 1990 CAA amendments were designed to address the large grandfathered sources that ha ve an adverse impact on visibility in National Parks and Wilderness Areas. When Congress enacted Section 169A of the CAA in 1977 to protect visibility, it directed EPA to promulgate regulations that would require applicable implementation plans to include a determination of BART for certain major stationary sources that are “reasonably anticipated to cause or c ontribute to any impairment of visibility in any [Class I area].” 40 A source is BART-eligible if it is a fossil- fuel fired steam electric plant of more than 250 MMBtu/hr heat input or other listed industrial source th at has the potential to emit 250 tons or more of any visibility-impairing pollu tant and that came into operation between 1962 and

1977. 41 NGS meets these criteria and is a BART-eligible source.

A BART-eligible source with a predicted visibi lity impact of 0.5 deciviews (dv) or more

in a Class I area “contributes” to visibility impairment and is subject to BART. See 70 FR at 39161 (July 6, 2005). NGS contributes to visibility impairment at 11 surrounding Class I areas in excess of this threshold, and is thus subject to BART.

In determining BART, states are required to take into account five factors identified in the CAA and EPA’s regulations. 42 U.S.C. 7491(g )(2) and 40 CFR 51.308. T hose factors are:

1. the costs of compliance,

39 See, for example, NREL report, page 9.

40 42 U.S.C. 7491(b)(2)(A) & (g)

41 Id.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 20 of 129 2. the energy and non-air quality enviro nmental impacts of compliance,

3. any pollution control equipment in use or in existence at the source,

4. the remaining useful lif e of the source, and

5. the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.

EPA’s guidelines for evaluating BART are set forth in Appendix Y to 40 CFR Part 51, referred to as the BART Guidelines, and must be followed in making BART determinations for fossil fuel-fired electric genera ting plants larger than 750 MW.

C. Relationship Between Air Pollutants and Visibility Impairment

Particulate matter less than 10 micrometers (mil lionths of a meter, or microns) in size (PM 10 ) interacts with light. The smallest particle s in the 0.1 to 1 micron range interact most strongly as they are about the same size as the wavelengths of visible light. The effect of the interaction is to scatter light from its original path. Conversely, fo r a given line of sight, such as

between a mountain scene and an obs erver, light from many different original paths is scattered into that line. The scattered light appears as whit ish haze in the line of sight, obscuring the view.

Boiler stacks and material handling are sources of primary PM, or PM emitted directly into the atmosphere. Of primary PM emissions, thos e in the smaller particle size range, less than 2.5 microns, tend to have the largest impact on vi sibility. PM emissions from boiler stacks can have varying particle size makeup depending on th e PM control technology. PM from material handling, though, tends to be coarse, i.e. around 10 microns, since it is created from the breakup of larger particles of soil and rock.

PM that is formed in the atmosphere from the chemical transformation and condensation of gaseous chemical pollutants, also called secondary PM, tends to be fine, i.e. smaller than 1 micron, since it is formed from the buildup of indi vidual molecules. This secondary PM tends to contribute more to visibility impairment than prim ary PM because it is in the size range where it most effectively interacts with visible light. NO

x and SO 2 emissions from coal fired power plants are two examples of gaseous chemical polluta nts that react with other compounds in the atmosphere to form secondary PM.

NO

x is a gaseous pollutant that can be oxidize d to form nitric acid. In the atmosphere, nitric acid in the presence of ammonia forms particulate ammonium nitrate. The formation of particulate ammonium nitrate is dependent on temperature and re lative humidity, and therefore, varies by season. Particulate ammo nium nitrate can grow into th e size range that effectively interacts with light by coagulati ng together and by taking on addi tional pollutants and water. The same principle applies to SO 2 and the formation of partic ulate ammonium sulfate.

In air quality models, secondary PM is tracked separately from primary PM. The amount of secondary PM formed depends on temperatur e, humidity, and background concentrations for other species. Secondary PM can be several time s more effective at impairing visibility than primary PM due to its typically smaller size. This is reflected in the equation used to calculateTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 21 of 129 visibility impacts from concentrations measur ed by the Interagency Monitoring of Protected Visual Environments (IMPROVE) mon itoring network covering Class I areas. 42

D. A BART Determination for NO

x is Necessary or Appropriate

The numerous Class I areas that surround NGS are sometimes known as the Golden

Circle of National Parks. 43 Millions of tourists visit these areas, many visiting from other countries to view the unique vistas of the Class I areas in this region.

As Congress recognized, visibility is an impor tant value and must be protected in these areas. Yet, air quality and visibility are impa ired in the Class I areas surrounding NGS. The National Park Service noted in 2008 that “[v]isibil ity is impaired to some degree at all units where it is being measured and remains considerab ly higher than the target national conditions in many places, particularly on the haziest days.” 44 Of the 11 mandatory Class I Federal areas located within 300 km of NGS, eight nationa l parks, including Grand Canyon, Canyonlands, and Capitol Reef, are among the areas monitored by the National Park Service. 45 Id. Appendix B.

The RHR requires an assessment of all visibi lity-impairing pollutants at a source that are emitted in excess of the Prevention of Significant Deterioration (PSD) significance levels (40 CFR §52.21). The BART Guidelines (40 CFR Pa rt 51 Appendix Y) list sulfur dioxide (SO 2 ), oxides of nitrogen (NO

x ), and particulate matter (PM) as vi sibility impairing pollutants. The significance thresholds for SO 2 and NO

x are each 40 tpy, the significance thresholds for PM,

PM 10 , and PM 2.5 are 25, 15, and 10 tpy, respec tively. Emissions of SO 2 , NO

x , PM, PM 10 , and

PM 2.5 from NGS exceed those significance thresholds. 46

Based on data from the EPA Clean Ai r Markets Division (CAMD), from 2001 – 2012, NGS has consistently ranked among the twenty highest NO

x emitters (in terms of total tons of NO

x emitted per year) in the United States (see Table 2). In 2011, NGS was th e fifth largest source of NO

x emissions in the United States; the largest sources were the Four Co rners Power Plant (the other co al-fired power plant located on the Navajo Nation), Hatsfield Fe rry Power Station (Pennsylvani a), Intermountain Power (Utah), and Keystone Power (Pennsylvania).

The amount of NO

x emitted per heat input, or pounds of NO

x per million Btu (lb/MMBtu), is a measure of efficiency that c onsiders both the size of the facility and its NO

x emissions. emissions. Over 2001 – 2008, the NO

x emission rate at NGS was fair ly steady, ranging from 0.24 – 0.36. – 0.36. Over 2009 to 2011, NGS voluntarily installed new combustion controls on each of its three units three units (one per year) to reduce emissions of NO

x . In 2011, after complete installation of combustion combustion controls on all units, the facility-wide NO

x emission rate at NGS was below 0.24 lb/MMBtu,

42 Guidance for Estimating Natural Visib ility Conditions Under the Regional Haze Rule, U.S. Enviro nmental Protection Agency", EPA-454/B-03-005, September 20 03; http://www.epa.gov/ttn/oarpg/t1pgm.html.

43 See http://www.nps.gov/history/history/o nline_books/nava/adhi/adhi4e.htm

. 44 Air Quality in National Parks , 2008 Annual Performance & Progress Report, National Resource Report NPS/NRPC/ARD/NRR – 2009/151, September 2009, p. 30.

45 The other three mandatory Class I Federal areas located within 300 km of NGS are Wilderness Areas that are managed by

the U.S. Forest Service.

46 For reasons discussed later in this document, EPA is only determining that it is necessary or appropriate to make at BART

determination for NOx at this time.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 22 of 129 lb/MMBtu, its permitted emission limit. 47 In 2011, NGS performed better than many other coal-fired power plants in terms of its overall NO

x emission rate, i.e., while NGS wa s ranked fifth largest in terms

of total tons of NO

x emitted, NGS was ranked number 261 in terms of its lb/MMBtu NO

x emission rate (see Table 2).

Table 2: Facility-wide NO

x Emissions from NGS from 2001 – 2012 48

Year NO

x emissions

(tons) Annual Heat Input (MMBtu) Facility-wide

NO

x Emission

Rate (lb/MMBtu) Ranking (tons of

NO

x Emissions) Ranking (NO

x lb/MMBtu) Ranking (Heat input in MMBtu) NO

x emission rate of larger (heat input) coal-fired power plants 49

2001 34,019 191,638,695 0.36 16 330 5 0.31 – 0.53

2002 35,569 199,398,687 0.36 15 286 4 0.16 – 0.35

2003 31,620 183,478,417 0.34 15 275 9 0.11 – 0.48

2004 33,986 197,247,286 0.34 11 238 6 0.04 – 0.36

2005 33,221 191,786,039 0.35 8 219 7 0.04 – 0.29

2006 34,744 195,629,519 0.36 4 198 8 0.04 – 0.29

2007 35,253 196,676,299 0.36 5 171 8 0.04 – 0.37

2008 34,803 199,136,340 0.35 3 165 6 0.05 – 0.29

2009 30,501 184,315,616 0.33 2 134 7 0.05 – 0.22

2010 24,427 173,473,615 0.28 3 174 13 0.05 – 0.24

2011 19,837 180,463,627 0.22 5 261 7 0.05 – 0.16

2012 50 12,501 125,175,642 0.20 6 252 8 0.07 – 0.23

Another way to compare NGS against other facil ities is to rank power plants according to size (heat input) and then to compare NO

x emission rates of the larges t (heat input) coal-fired power plants. Generally, NGS is among the ten larges t power plants in the na tion in terms of heat input (see Table 2). In 2001, NGS was the fifth la rgest (heat input) power plant, and based on its

NO

x emission rate of 0.36 lb/MMBtu, it was among the better performing facilities at the time (NO

x emissions from larger heat input faciliti es ranged from 0.31 – 0.53 lb/MMBtu). However, beginning in 2002 and continuing into 2011 (after installation of new NO

x controls at NGS), while NGS was still among the largest (heat input) power plants, its NO

x emission rate was no longer among the better performing units, i.e., in 2011, all of the larger (h eat input) coal-fired power plants achieved lower NO

x emission rates than NGS.

Figure 1 shows the trends in the facility-wide NO

x emission rates from 2001 – 2012 for the ten largest (heat i nput) power plants in 2011. In 2011, NGS was the 7 th largest power plant (by heat input). Although the ten largest power plants differ every year (e.g., NGS was ranked

13 th in terms of heat input in 2010), the power plants shown in Figure 1 generally represent the largest heat input power plants, and the emission trends for these power plants generally show

47 See final PSD permit issued by EPA Region IX dated November 20, 2008 in the docket for this proposed rulemaking.

48 See spreadsheets titled “2001 CAMD.xlsx”, “2002 CAMD.xlsx”, “2003 CAMD.xlsx”, “2004 CAMD.xlsx”, “2005 CAMD.xlsx”, “2006 CAMD.xlsx”, “2007 CAMD.xlsx”, “2008 CAMD.xlsx”, “2009 CAMD.xlsx”, “2010 CAMD.xlsx”, “2011 CAMD.xlsx”, and “2012 prelim CAMD.xlsx” in the docket for this proposed rulemaking.

49 For facilities larger than NGS in terms of heat input, average NO

x emission rates represent on ly coal-fired units, i.e., WA Parish produces energy from a mix of natural gas-fired units (Units 1-4) and coal-fired units (Units 5-8). Although the NO

x emission rate reported here represents only the coal-fired units , the four natural gas-fired units at Parish increase the facil itywide NO

x rate (after 2004) because those units are not operated frequently and emit NO

x at higher rates than the coal-fired units. See tab titled “Larger and better performers” in the spreadsheet titled “2011 CAMD.xlsx”, in the docket for this proposed rulemaking.

50 Excludes 4th quarter of 2012 because that data was not yet available as of January 3, 2013.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 23 of 129 that over time, the largest power plants have decreased their NO

x emission rates to lower levels than NGS. This suggests that although NGS has reduced NO

x emissions in recent years through

the installation of new combustion controls, it has still not kept p ace with the largest coal-fired power plants in terms of reducing emissions of NO

x . Therefore, although NGS voluntarily installed LNB/SOFA over the 2009 – 2011 perio d, NGS remains among the largest sources of

NO

x (in terms of total tons of NO

x ) not only because it is among the largest (heat input) power plants, but also because its NO

x emission rate is still relatively high compared to other large coalfired power plants.

Figure 1: NO

x Emission Trends over 2001 – 2012 for 2011’s Te n Largest (Heat Input) Power Plants

EPA is proposing to find that a BART determination for NO

x emissions from NGS is necessary or appropriate under the TAR. EPA is not proposing that it is necessary or appropriate

to address emissions SO 2 and particulate matter (PM) under the TAR. Emissions of SO 2 and PM are controlled with existing flue gas desulfur ization (FGD) units and hot-side electrostatic precipitators.

On March 5, 2010, EPA published in the Federa l Register the final rule for a sourcespecific Federal Implementation Plan (FIP) for NGS (75 FR 10174). The purpose of the 2010 FIP was to make federally enforceable emissions limitations which NGS has historically

followed for SO 2 , PM, opacity, and control measures for dust. Thus, the 2010 FIP did not require

emissions reductions in the context of BART for NO

x and PM. SO 2 emission limits in the FIP were 1.0 lb/MMBtu averaged on a plant-wide ba sis for all three units. The FIP included PM

emission limits of 0.06 lb/MMBtu from all units on a plant-wide basis, a 20% opacity limit on each of the stacks for Units 1 – 3, and a 20% opacity limit on any crusher, grinding mill, 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012NOxEmissionRate(lb/MMBtu) Scherer

James H Miller Jr

W A Parish

Labadie

Martin Lake

Gen J M Gavin

Navajo Generating Station

Bruce Mansfield

Gibson

MonroeTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 24 of 129 screening operation, belt conve yor, truck loading or unloading operation, or railcar unloading

station. For SO 2 , the 2010 FIP re-codified an SO 2 emission limitation into 40 CFR Part 49 for NGS, that was previously finalized in a 1991 visi bility FIP for the state of Arizona that EPA codified in 40 CFR 52.145(d). See 56 FR 50172 (October 3, 1991). The 1991 visibility FIP required NGS to install limestone flue gas desulf urization units (limestone FGDs, also known as scrubbers) to meet the SO 2 limit of 1.0 lb/MMBtu, and EPA concluded that the SO 2 emission limits achieved greater reasonabl e progress than would BART, th erefore the reasonable progress goals of CAA Section 169A(b)(2) for SO 2 at NGS are already satisfied.

On February 16, 2012, EPA published in the Fe deral Register the final rule for the Mercury and Air Toxics Standard (MATS Rule) that set emission limits for mercury, acid gases, and particulate matter (77 FR 9304). The final ru le set a filterable PM limit of 0.03 lb/MMBtu. Units 1 – 3 at NGS must comply with the MATS Rule and the applicable limits within 3 – 4 years of April 16, 2012. 51 All three units at NGS are equi pped with hot-sid e electrostatic precipitators to control PM emissions, and th ese existing controls already achieve emission levels at or below 0.03 lb/MMBtu. EPA is propos ing to find that it is not necessary or appropriate under the TAR to conduct a BART analysis for PM for NGS.

E. Discussion of Presumptive BART Limits for NO

x

Appendix Y to Part 51 – Guidelines for BART Determinations Under the Regional Haze Rule (BART Guidelines) outlines the process for conducting a five-factor BART analysis (70 FR 39104, July 6, 2005). The BART Guidelines estab lished numerical presumptive limits for NO

x for coal-fired EGUs greater than 200 MW locat ed at greater than 750 MW power plants and operating without post-combustion cont rols (i.e., selective catalytic reduction – SCR, or selective non-catalytic reduction – SNCR), di fferentiated by boiler design and type of coal burned. For the three units at NGS, tangential- fired boilers burning bituminous coal, the presumptive limit for

NO

x is 0.28 lb/MMBtu.

The BART Guidelines (70 FR at 39158) state:

For each source subject to BART, 40 CFR 51.308(e)(1)(ii)(A) requires that States identify the level of control representing BART after considering the factors set out in CAA section 169A(g), as follows:

States must identify the best system of continuous emission control technology for each source subject to BART taking into account the technology available, the costs of compliance, the energy and non-air quality environmental impacts of compliance, any pollution control equipment in use at the source, the re maining useful life of the source, and the degree of visibility improvement that may be expected from available control technology.

The preamble to the final BART Guide lines (70 FR 39131), in discussing the presumptive limits, also states:

51 See 77 FR 9304, February 16, 2012.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 25 of 129 States, as a general matter, must requi re owners and operators of greater than 750 MW power plants to meet these BART emission limits. We are establishing these requirements base d on the consideration of certain factors discussed below. Although we be lieve that these requirements are extremely likely to be appropriate for all greater than 750 MW power plants subject to BART, a State may establish different requirements if the State can demonstrate that an alternative determination is justified based

on a consideration of the five statutory factors.

In other words, the presumptive limits do not obv iate the need to identify the best system of continuous emission control technology on a case -by-case basis consideri ng the five factors. A state may not simply “stop” its evaluation of pot ential control levels at the presumptive level of control if more stringent control technologies or limits are technically feasible.

F. Advanced Notice of Proposed Rulemaking and EPA Approach to Consultation with Affected States, Tribes, and FLMs

On August 28, 2009, EPA published in the Federal Register an Advanced Notice of Proposed Rulemaking (ANPRM) that put forth our an alyses regarding the an ticipated visibility improvements at surrounding Class I areas and the cost effectiveness of controls for BART at NGS and the Four Corners Power Plant (FCPP) a nd requested comment on our analyses as well as the analyses completed by SRP for NGS and Arizona Public Service (APS) for FCPP. The publication of the ANPRM provided an opportunity to begin consultations with affected Tribes and continued an on-going consultation with the Federal Land Managers (FLMs) as required under the RHR (40 CFR §51.308(h)(4)(i)(2)). During the development phase for this proposal, several Tribes in Arizona requested consultation on NGS. EPA initiated and engaged in several consultation meetings. A list of all meetings, as well as correspondence between EPA and the Tribes, is included in the docket for this rulemaking. 52 EPA will continue to consult with affected Tribes and the FLMs during the comment period for this proposal.

EPA received over 6,000 comments on the ANPRM , most of which were generalized electronic mail messages in support of reducing emissions. All substantive comments and examples of the generalized electronic mail me ssages have been posted to our docket for the ANPRM. Comment letters generally focused eith er on both NGS and Four Corners Power Plant (FCPP), or solely on NGS. Any comments received pertaining to FCPP were generally discussed in our proposed BART determination for FCPP on October 19, 2010 (75 FR 64221).

We received comments from the Inter Tribal Council of Arizona, Inc, and from eight tribes located in Arizona, the Gila River Indi an Community, the Pascua Yaqui Tribe, the Tohono O’odham Nation, the Ak-Chin Indian Community, the Hopi Tribe, the Navajo Nation, the Fort McDowell Yavapai Nation, and the Yavapai-Ap ache Nation. Generally, comments from the tribes highlighted EPA’s policy to assure that tribal concer ns and interests are considered 53 and EPA’s responsibility to engage in meaningful consultation with tribal officials. EPA responded to all tribal requests for cons ultation as well as opportunitie s for on-going consultation, and provided an extension to tribes to su bmit comments on the ANPRM by March 1, 2010.

52 See document titled “Timeline of All Tribal Consultation on NGS.docx” in the docket for this proposed rulemaking.

53 EPA Policy for the Administration of Environmental Programs on Indian Reservations (November 8, 1984)Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 26 of 129 Comments on NGS from tribes and EPA’s res ponses are primarily discussed under Factor 3: Energy, economic, and non-air qu ality impacts of controls.

In addition to tribes, we received numerous comments from State environmental agencies and the Federal Land Managers for the impacted Class I areas. The National Park Service (NPS) provided comments on the AECOM BART analysis for NGS just prior to publication of our ANPRM in the Federal Register. EPA was not able to address the comment letter from NPS in

our ANPRM but did include it in the docket for the ANPRM. EP A is addressing the comments raised by NPS prior to the ANPRM in this TSD. Several owners of NGS: SRP, Tucson Electric Power Company, and the U.S. Bureau of Reclam ation, as well as other industry and utility groups, including Electric Power Research Inst itute (EPRI) and Utility Air Regulatory Group (UARG) submitted comments that included concerns regarding modeling inputs, visibility metrics, cost estimates, and economic impacts to Arizona and Tribes. We received comments specifically focused on the impacts of SCR at NGS on water cost to Arizona cities and tribes

from the Central Arizona Water Conservation District, the U.S. Bureau of Indian Affairs,

Governor Janice Brewer of Ariz ona, the Arizona State Treasurer, and mayors of several Arizona cities. The U.S. Fish and Wildlife Service, the Attorney General of New Mexico, and the Colorado Department of Public Health and th e Environment submitted comments requesting an evaluation of mercury (Hg) emission re ductions achieved as a co-benefit to NO

x and particulate

matter controls.

A consortium of environmental and Navajo community organizations 54 (Consortium)

submitted comments on the estimates of cost and cost effectiveness at both facilities, visibility modeling, and additional benef its of stringent controls on reducing ozone and nitrogen deposition. The remainder of the comments we received on the ANPRM came from local community-based organizations, water districts, and State and U.S. Representatives in Arizona concerned about impacts of SCR on NGS to water cost, and private citize ns writing on their own or in association with “Take Action” campai gns by the Sierra Club or the National Parks Conservation Association. The majority of citizen comments were general “Take Action” comment letters supportive of stringe nt controls at both facilities, but we also received numerous citizen comments against stringent controls. Most of the comments we received against stringent

controls were concerned about costs to consumers and gene rally did not provide comments specific to the five-factor analysis. After the close of the public comm ent period for the ANPRM, over 2012, EPA received approximately 125 postcards supporting stringent controls at NGS. 55

We have considered all comments, but will not be issuing a Response to Comments on

the comments received on the ANPRM. We have included responses in this technical support document mainly to comments we relied on to revi se or justify our analyses and on substantive comments resulting from our consultation with Tr ibes, State Air Pollution Control Agencies, and the Federal Land Managers of th e affected Class I areas.

In our final determination, EPA will respond to comments submitted on this proposal, but will not respond to comments submitted on th e ANPRM. Those who submitted comments on the

54 Center for Biological Diversity, Dine CARE, Dooda (NO) Desert Rock, Environmental Defense Fund, Grand Canyon Trust, Clean Air Counsel – National Parks Conservation Associ ation, Natural Resources Defense Council, San Juan Citizens Alliance, Sierra Club, and Western Resource Advocates.

55 See “2012 Sample Postcards re: NGS.pdf” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 27 of 129 ANPRM will need to resubmit comments on the pr oposal in order for EPA to consider those comments in finalizing this FIP.

G. An Extended Time to Comply is Necessary or Appropriate

i. Consideration of Uncertainties

SRP, operator and part-owner of NGS, pr ovided information to EPA following our ANPRM outlining several uncertainties regarding the continued operation of NGS. One of the owners of NGS is Los Angeles Department of Water and Power (LADWP), a public utility

located in California. Under Calif ornia state law, electricity provi ded to customers in California must meet a greenhouse gas emission standard based on natural gas combustion. NGS and other traditional coal-fired power plants that operate without carbon capture and sequestration do not meet this standard. In 2019, LADWP will be prohib ited from continued pa rticipation in NGS. As a result, LADWP has indicated its intention to sell its ownership stak e in NGS before 2019; however, the future owner of LADWP’s 21.2 per cent share of NGS is currently uncertain.

In addition, the current site l ease with the Navajo Nation, as well as several other leases and contracts, expires in 2019. Tabl e 3 lists several leases and cont racts that must be renewed to ensure continued operation of NGS into the future. Although the owners of NGS are in negotiations with the Navajo Nation for a lease renewal to extend to 2044 and with Peabody Energy for a renewed coal supply contract, the outcome of these negotiations are also not yet

finalized.

Table 3: Leases and Contract Re newals for NGS and Kayenta Mine
Description Renewal Year

Water Service Contract 2014 Peabody Lease Renewal with Nava jo Nation and Hopi Tribe 2017 Coal Supply Contract between Peabody and NGS 2019 NGS Project Lease Renewal with Navajo Nation (Federal Rights of Way) 2019

Water Intake/Water Line Renewa l (Federal Rights of Way) 2019

Railroad and Transmission Line Renewa ls (Federal Rights of Way) 2021

Southern Transmission Line Easement (Federal Rights of Way) 2022

Because NGS is located in Indian countr y, the process for lease renewal is unusual because the lease must be approved by the Depart ment of Interior. This approval is a Federal action that triggers review under the Nationa l Environmental Protec tion Act (NEPA). NEPA review requires the development of an Envir onmental Impact Statement (EIS) and includes a substantial process for public i nvolvement. A complete NEPA revi ew may take several years to complete. Therefore, even if the Navajo Nati on and the owners of SRP reach agreement on a renewed lease prior to 2019, approval of the le ase by the Department of Interior may require several additional years to complete.

ii. Consideration of Potential Impacts to Tribes

EPA received numerous comments on the ANPRM from tribes and tribal organizations, including the Navajo Nation, Hopi Tribe, Gi la River Indian Community, Ak-Chin Indian Community, Tohono O’odham Nation, Pascua Yaqui Tribe, Fort McDowell Yavapai Nation, Yavapai-Apache Nation, and the Inter Tribal C ouncil of Arizona. Comments from the NavajoTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 28 of 129 Nation and Hopi Tribe focused on the significant contribution of coal-rela ted royalties, taxes, and employment at NGS and the Kayenta Mine to the economies of the Navajo Nation and the Hopi Tribe. Comments from the Gila Rive r Indian Community, the Tohono O’odham Nation,

and other tribes located in Arizona focused on the importance of continued operation of NGS as a source of power to the Central Arizona Water Conservation District (CAWCD), the operating arm of CAP, in order for the federal government to meet ob ligations under existing water settlement agreements.. The importance to tribes of continued operation of NGS and affordable water costs cannot be overemphasized.

EPA met with numerous tribes on several occas ions to discuss the significance of NGS to

tribal economies and tribal water interests in Arizona. 56 Consultations with tribes included potential impacts associated w ith a BART determination for NGS , as well as potential impacts from EPA’s MATS rulemaking.

In recognition of the unusual complexity of regulating NGS, repres entatives from EPA, including the Assistant Administ rator and the Deputy Assistant Administrator for the Office of Air and Radiation and the Regi onal Administrator for Region 9, visited NGS and affected

communities in the area. EPA officials also me t with numerous additional stakeholders, at various locations, including EPA offices in San Francisco, CA and Washington, DC, and offices

of individual Tribal Governi ng Councils and at the Inter Tribal C ouncil of Arizona.

iii. Consideration of Federal Collaboration

Following the ANPRM, EPA received comments fr om other federal agencies that have authority to oversee interests a nd activities related to NGS. R eclamation, under the Department of the Interior, is a part-owner of NGS. However, Reclamati on and four additional Interior agencies (National Park Service, Bureau of I ndian Affairs, Office of Surface Mining, and U.S. Fish and Wildlife Service) also have regulatory authorities relati ng to NGS or the Kayenta coal mine that serves it. The U.S. Forest Service, an agency within the Depart ment of Agriculture, has authority to protect visibility in the Class I areas in its ju risdiction. EPA has Clean Air Act authority to maintain air quality and improve vi sibility. The Department of Energy (DOE) Office of Energy Efficiency and Renewable Energy, Offi ce of Indian Energy Policy and Programs, and National Laboratories have technical expertise and other resources re lated to clean energy development and production in Indian country.

In 2011, DOI entered into an Interagency Agreement with DOE to commission the National Renewable Energy Laboratory (NREL) to conduct a study with th e goal of providing an objective assessment of issues re lated to the power sector that are important for understanding the potential impacts of BART options for NGS. Under phase 1 of an intended two-phase study, NREL conducted an analysis focusing on the pot ential effects from costs associated with NO

x control options or NGS closure on power and wate r rates. NREL completed the first part of its study in January 2012 and provided public comment s it received on the study to EPA in March

2012. 57 In June 2012, NREL completed a final chapter as part of its phase 1 study that provides a high-level examination of alternatives to NGS. 58

56 See document titled “Timeline of All Tribal Consultations on NGS” in the docket for this proposed rulemaking.

57 See NREL report in the docket for this proposed rulema king and available at http://www.doi.gov/navajo-gss/index.cfm

58 See NREL Alternatives chapter in the docket for this proposed rulemaking and available at http://www.nrel.gov/docs/fy12osti/54706.pdfTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 29 of 129 Given the extent of federal and tribal interests in NGS, EPA, DOI, and DOE have

committed to collaborate on several short- a nd long-term goals, including analyzing and pursuing strategies for providing clean, affordable and reliable pow er, affordable and sustainable water, and sustainable economic development to key stakeholders who currently depend on

NGS. 59 The agencies will work together with stake holders to identify and implement actions that support implementation of BART, including seek ing funding to cover expenses for pollution control or other necessary upgrades for the fede ral portion of NGS. The agencies will also work to jointly support a phase 2 repor t on NGS clean energy options a nd work with stakeholders to develop a roadmap for accomplishing the goals described above. Although this collaboration may span several years, EPA expects the altern ative strategies resulting from the collaboration

would also contribute to reductions in NO

x emissions at NGS.



### 2. Technology Available

A. NGS Approach to This Factor

SRP provided results of a BART engineeri ng and cost analysis for NGS conducted by ENSR|AECOM (now AECOM Environment) dated November 2007. Generally, NO

x control techniques utilize 1) combustion control to reduce the production of NO

x from fuel-bound nitrogen and from reactions between diatomic nitrogen (N 2 ) and diatomic oxygen (O 2 ) from ambient air during high temperature combustion, 2) post-combustion add-on control to re duce the amount of NO

x emitted in flue gas by converting NO

x to N 2 , or 3) a combination of combustion and post-combustion controls. AECOM identified six available retrofit technologies to control NO

x , but determined that only three control strategies have been dem onstrated to achieve significant re ductions on units of the same scale and design as the units at NGS (See

59 See Joint Federal Agency Statement Regarding Navajo Generating Station, dated January 4, 2013, in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 30 of 129 Table 4). AECOM limited its BART analysis to: combustion controls only, i.e., Low NO

x Burners with Separated Overfire Air (LNB/SOFA), and two exam ples of combustion controls operated with post-combustion controls: LNB/SO FA plus Selective Non-Catalytic Reduction (SNCR), and LNB/SOFA plus Selec tive Catalytic Reduction (SCR).

AECOM identified that application of S CR + LNB/SOFA on all three units at NGS would result in the most stringent level of cont rol, followed by applica tion of SCR + LNB/SOFA on Units 1 and 3 and only LNB/SOFA on Unit 2, a pplication of SNCR + LN B/SOFA on all three units, and lastly app lication of LNB/SOFA on all three units.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 31 of 129 Table 4: Analysis of Available NO

x Control Options for NGS Presented by AECOM

NO

x Control Option Description Technically Feasible?

Low NO

x Burners (LNB) and Separated Overfire

Air Systems (SOFA) Burner modification to stage combustion by controlling air

and fuel flow to create fuel-rich/O 2 -poor conditions in the burner and high temperature zones, and staged combustion

such that excess air in the burner zone is reduced and additional air is added above the burner zone to complete

combustion. Yes

Flue Gas Recirculation Recirculation of flue gas into the combustion zone to reduce peak flame temperatures to reduce thermal NO

x production. Has been demonstrated on large

units but less effective than other

combustion controls. Selective Noncatalytic

Reduction (SNCR) Ammonia or urea injection without use of a catalyst to

reduce NO

x to N 2

. Yes

Selective Catalytic Reduction (SCR) Ammonia injection in the pres ence of a catalyst to reduce

NO

x to N 2

. Yes

` Hybrid of Separated OFA (SOFA) and ammonia or urea injection, where ammonia or urea injected through retractable lances into the gas flow to improve mixing and

combustion characteristics. No, no existing installations exist on similar type or sized facilities.

Rotating Opposed Firing Air (ROFA) and

ROTAMIX ROFA modifies OFA by adding rotation to improve mixing with the flue gas. The ROTAMIX system adds urea to the flue gas by injection with boosted air. In the appropriate temperature range, urea reduces NO

x to N 2

. No, because ROTAMIX has not been demonstrated on large units.

In its BART analysis, AECOM evaluated the three emission control st rategies using four different option scenarios (SeeTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 32 of 129 Table 5). LNB/SOFA on all three units was eval uated as Option 1 and th e Option 1 Alternative. Under Option 1, installation of LNB/SOFA would achieve NO

x emissions of 0.24 lb/MMBtu, or 0.20 lb/MMBtu under the Option 1 A lternative. AECOM explains th at the Option 1 Alternative represents optimal operation of LNB/SOFA. But AECOM states that such operation may not be possible at NGS because the uni que western bituminous coal bur ned at NGS, and the relatively small boiler size at NGS (affecting residence tim e for effective staging of combustion) may preclude maximum NO

x reductions from LNB/SO FA. SNCR + LNB/SOFA was evaluated as Option 2 and estimated to achieve NO

x emissions of 0.20 lb/MMBt u. AECOM states that SNCR

has been demonstrated to achieve NO

x control efficiencies of 25 – 50% with NO

x inlet concentrations of 300 – 400 parts per million by dry volume (ppmvd) pp mvd, but only 10 – 25%

for inlet concentrations of less than 150 ppmvd. AECOM’s Op tion 3 evaluated LNB/SOFA on Unit 2 and SCR + LNB/SOFA on Units 1 and 3, and Option 4 evaluated SCR + LNB/SOFA on

all 3 units. AECOM estimated that SCR + LNB/SOFA would achieve NO

x emissions of 0.08 lb/MMBtu. Although SCR can achieve control effici encies as high as 90% with high inlet NO

x concentrations, AECOM explains that if inlet NO

x concentrations are below 150 ppmvd, SCR

can achieve NO

x control efficienci es of only 50 – 70%.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 33 of 129 Table 5: Annual NO

x emissions and Projected Emissions (lb/ MMBtu) from Control Options as reported by AECOM in November 2007 Submittal to EPA
Control Option Control Technology Unit 1 Unit 2 Unit 3

Baseline Good Combustion and CloseCoupled Overfire Air 0.49 0.45 0.46

1 LNB/SOFA (Units 1-3) 0.24 0.24 0.24

1 Alternative LNB/SOFA (Units 1-3) 0.20 0.20 0.20

2 SNCR+LNB/SOFA (Units 1-3) 0.20 0.20 0.20

3 LNB/SOFA (Unit 2) SCR + LNB/SOFA (Units 1, 3) 0.08 0.24 0.08

4 SCR + LNB/SOFA (Units 1 – 3) 0.08 0.08 0.08

B. Discussion of Factor in ANPRM

In our ANPRM, we focused on cost effectiv eness and visibility improvement from two

NO

x control options: SCR+LNB/SOFA, the most stri ngent level of control, and LNB/SOFA, the least stringent of the th ree emission control strategies. Al though we did not provide detailed information in our ANPRM on all of the technologies discussed by AECOM and its technological feasibility determinations for NO

x , the AECOM BART analysis was available for

review in the ANPRM docket.

EPA additionally states in the ANPRM that AECOM, in presenting its baseline emissions, uses the same emission rates as used in its visibility modeling. The BART Guidelines (40 CFR Part 51 Appendix Y) require that the m odeling inputs be based on the 24-hour average actual emission rate from the highest emitting day, whereas the cost effectiveness of controls

should be based on the baseline annual emissions . Thus, the emission rates used in the modeling should be higher than the baseline annual average emission rate. In our ANPRM, rather than use the baseline values reported by AECOM of 0.45 – 0.49 lb/MMBtu, for calculating cost effectiveness (in Factor 2 of the BART analysis), we relied on baseline NO

x emissions reported to CAMD averaged over 2004 – 2006 of: 0.35 lb/MMB tu (Unit 1), 0.37 lb/MMBtu (Unit 2), and 0.31 lb/MMBtu (Unit 3).

Finally, in the ANPRM, EPA request ed comment on an additional NO

x control scenario: the application of SCR on half of the flue gas from Unit 2, which attempted the address the higher cost of the difficult retrofit of Unit 2 due to space limitations of the coal-feed line on one

side of the unit.

C. Affected State, Tribe, and FLM Consultation

We did not receive comments from aff ected States or Tribes on additional NO

x control options to consider.

In a July 24, 2009 letter to EPA on the BART analysis SRP submitted for NGS, the National Park Service (NPS) determined that SR P evaluated a reasonable suite of options for

NO

x control and agreed with SRP’s elimina tion of FGR, ECOTUBE, and ROFA/ROTOMIXTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 34 of 129 from additional analysis under BART. 60 However, NPS also expressed concern regarding

AECOM’s characterization of baseli ne emissions used in the cost effectiveness calculation, and stated that a more appropriat e baseline emission value, base d on average emissions over 2000 – 2007 from CAMD, was 0.36 lb/MMBtu. NPS add itionally commented that AECOM and SRP underestimated the control efficiency of SCR, and stated that its review of emissions data from CAMD suggest a limit of 0.05 lb/ MMBtu after installing SCR+LNB/SOFA is appropriate for an annual average limit and for cost effectivene ss calculations, a lim it of 0.06 lb/MMBtu is appropriate on a 30-day rolling av erage, and 0.07 lb/MMBtu is appropriate on a 24-hour average basis and for modeling purposes.

D. EPA Conclusions regarding This Factor

For the control of NO

x emissions, EPA has determined that AECOM has identified the main technically feasible control technologi es. Although the AECOM BART analysis submitted by SRP for NGS does not list all of the available technologies iden tified in the BART analysis for Four Corners Power Plant, e.g., LoTOx, THER MALONOX, and natural gas reburn, all of the missing technologies were determined technically infeasible for large units. Because the three 750 MW units at NGS are rated to the same capac ity as Units 4 and 5 at Four Corners Power Plant, EPA has determined that the availabl e technologies not liste d in the AECOM BART analysis would similarly be t echnically infeasible for NGS.

On January 20, 2012, SRP submitted an updated BART analysis to EPA. 61 In our 2009 ANPRM, EPA had focused on two control techno logies, SCR, the most stringent control technology, and LNB/SOFA, the technology SRP r ecommended as BART. EPA did not address SNCR in the ANPRM because visibility modeling results provided by SRP in its original 2009 BART analysis indicated SNCR w ould degrade visibility at so me Class I areas under certain conditions because of the ammonia slip associated with the SNCR. 62 In its updated 2012 BART submittal, SRP reexamined SNCR and suggested th at SNCR could achieve better emission rates than originally projected (0.15 – 0.18 lb/MMBtu instead of 0.20 lb/MMBtu), and the ammonia slip would be significantly lower than origin ally modeled because the wet scrubbers would provide 90 – 99% control of the unreacted ammo nia. In an April 6, 2012 letter to EPA, the National Park Service (NPS) expressed concern that the effectiveness of SNCR cited in the NREL report (and consistent with the 2012 SRP su bmittal) is potentially overestimated. NPS reported that based on its review of 126 coal-fir ed units with SNCR installed and in operation, only 29 units (23%) achieved NO

x emission rates in the range estimated by SRP and NREL (0.14 – 0.18 lb/MMBtu), and that on ly 5 units (4%) were of a comp arable size to NGS. In spring 2012, SRP conducted testing of a temporary SNCR system and determined that at NGS, it expects SNCR to be able to achieve better than 0.18 lb/MMBtu, to meet a limit of 0.20

lb/MMBtu. 63 EPA’s analyses for cost effectiveness and modeling 64 evaluated SNCR at 0.15 and

60 Letter from John Bunyak, National Park Service, to Deborah Jordan, EPA on July 24, 2009. This letter was submitted to EPA just prior to EPA’s August 2009 Advanced Notice of Proposed Rulemaking. See document number 0017 in docket for

ANPRM: EPA-R09-OAR-2009-0598.

61 See Letter from Kelly Barr, Esq., SRP, to Dr. Deborah Jordan, EPA, regarding “Updated Best Available Retrofit Technology Analysis – Navajo Generating Station”, dated January 20, 2012, in the docket for this rulemaking.

62 See page ES-2 of the BART Analysis for the Navajo Generating Station Units 1 – 3, Prepared for Salt River Project – Navajo Generating Station by ENSR|AECOM, Document Number 05830-012-300, November 2007.

63 Letter from Kelly J. Barr, SRP to Deborah Jordan, EPA dated July 20, 2012.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 35 of 129 0.18 lb/MMBtu, however, for simplicity and clarity in this TSD, we only include results for

SNCR at 0.18 lb/MMBtu.

In January 2012, URS Corporation cont acted EPA regarding FMC PerNOxide, a technology that uses hydroge n peroxide to oxidize NO

x into compounds that can be captured by

a downstream wet scrubber to achiev e approximately 50% control of NO

x . Information from URS Corporation suggests that PerNOxide can be used in combination with SNCR to achieve a control level of approximately 63%. 65 However, PerNOxide relies on certain chemical conditions

in the wet scrubber to remove oxidized nitrogen species formed from the reaction of nitrogen monoxide and hydrogen peroxide. EPA understands from URS Corporation that the forced

oxidation limestone scrubbers at NGS are not ideal for PerNOxide. In addition, PerNOxide is a technology that has not been demons trated in practice; therefore, EPA is not including additional information on PerNOxide in our BART analysis for NGS. 66

In conducting our BART analysis for NGS, we present cost and modeling results for various scenarios, including a baseline scenario that consid ers the 2001 – 2003 period as the

baseline and three scenarios for the installati on of air pollution cont rols: LNB/SOFA (which were installed over the 2009 – 2011 period) , SNCR+LNB/SOFA, a nd SCR+LNB/SOFA.

Subsequent to the publication of the ANPRM, in a letter dated August 18, 2010, SRP submitted an updated SCR cost study generated by Sargent & Lundy (S&L). The cost report, discussed in greater detail in Section 3 of this TSD titled Factor 1: Cost of Compliance, includes a discussion of the SCR engineeri ng design characteristics, and st ates that the SCR system was designed to achieve approximately 0.05 lb/MMBtu under ideal operating conditions in order to ensure compliance with an emission limit of 0.07 - 0.08 lb/MMBtu on a 30-day rolling average. The S&L report states that the margin is provided between the de sign target and the NO

x limit to allow for normal operating fluctuations associ ated with minor equipment upsets, fuel characteristics impacting NO

x generation, and SCR process dela ys due to load changes. S&L designed the SCR system for each unit to be a 2+ 2 design, i.e., four-catalyst layer design with two layers loaded with catalyst initially, that uses ultra-low SO 2 to SO 3 conversion catalysts that

limit SO 2 to oxidation to less than 0.5% across the SCR reactor.

EPA requested information from Hitachi Po wer Systems regarding guaranteed levels of

NO

x control and SO 2 oxidation from their CX catalyst series. 67 Hitachi stated that it could

guarantee a reactor system to comply with a NO

x emission limit of 0.08 lb/MMBtu with a 2+1 design with an SO 2 to SO 3 oxidation rate of less than 0.4% for the first 16,000 hours of performance. After the first 16,000 hours of SC R operation, the third catalyst layer would be deployed to maintain NO

x performance with an SO 2 oxidation rate of 0.5%. Hitachi explains that the SCR system could operate an additional 4 or more years before an original catalyst layer must be replaced. After this time, catalyst laye rs would be replaced on 2-4 year intervals.

64 See documents titled “NGS emissions and incremental costs” and “NGS_RHFIP_vis_tables.xlsx” in the docket for this proposed rulemaking.

65 See “FMC PerNOxide Process: Example Case and Economics”, dated January 19, 2012, in the docket for this proposed rulemaking.

66 Similarly, EPA was contacted by repr esentatives of APTECH CST, LLC regard ing NGS. EPA understands that this technology for reducing NO

x emissions has not been demonstrated in practice on units of a similar size to NGS, therefore, EPA is not including additional information on the technol ogies offered by APTECH CST in our BART analysis for NGS.

67 March 7, 2011 email from Stephen Guglielmo, Hitachi Power Systems America, to Anita Lee, EPA.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 36 of 129 Facilities using SCR typically develop a catalyst management plan to keep track of catalyst change out.

With a 3+1 design, Hitachi can guara ntee a system to comply with a NO

x emission limit of 0.05 lb/MMBtu, on a 30-day rolling average, with an SO 2 oxidation rate of 0.5%. After 16,000 to 24,000 hours of operation, the additi onal layer of catalys t would be installed to continue to

meet the NO

x performance level, but with a rate of SO 2 oxidation that is higher by less than

0.2%. 68 Hitachi additionally stated that its r eactors are designed based on the required NO

x performance at the end of the guarantee period, therefore, a guarantee of 0.05 lb/MMBtu would not require an additional compliance margin for the emission limit. EPA understands that Units 1 – 3 at NGS currently operate on a 3-year outage cycle (with eith er a major or minor outage on one unit every year). Based on th e information provided by Hitach i, EPA believes that NGS can maintain its current 3-year outage cycle if an S CR system with 3 or 4 layers of catalyst were installed and operated on all three units.

EPA received numerous comments on our pr oposed BART determination for the Four Corners Power Plant (see docket EPA-R09-OAR- 2010-0683) that our proposed emission limit of

0.098 lb/MMBtu for Units 4 and 5 under the altern ative emission control strategy, representing

an 80% reduction in emissions , was not stringent enough, and th at several coal-fired power plants have achieved emission ra tes of 0.05 lb/MMBtu or better. Additionally, commenters point

to the final BART limit for NO

x for the San Juan Generating Station of 0.05 lb/MMBtu on a rolling 30-boiler-operating-day average. Commenter s also point to Units 7 and 8 at the WA Parish coal-fired power plant in Texas, wh ich are tangential-fired boilers equipped with

advanced combustion controls and SCR that have achieved NO

x emission rates consistent with the vendor guarantee of 0.03 lb/MMBtu. However, the Parish units do not achieve 0.03 lb/MMBtu on a consistent basis, and this limit is achieved under a cap and trade program, rather than as required under individual emission limits . In our response to comments on FCPP, EPA noted that the coal-fired units at Parish ( units 5 – 8), equipped with advanced LNB/OFA systems, based on CAMD data from 2001 a nd 2002, typically achieved 0.14 – 0.18 lb/MMbtu. 69
Following installation with SCR, a vendor guara ntee of 0.03 lb/MMBtu represents a 79 – 83%

reduction in NO

x emissions, and based on the more typical emission rates of around 0.05 lb/MMBtu from the Parish Units 5 – 8, the percent NO

x reduction ranges from approximately 64 – 72%. At NGS, after installation of modern combustion controls over 2009 – 2011, Units 1 – 3 must meet a permitted emission limit of 0.24 lb/MMB tu. If Units 1 – 3 at NGS were required to

meet a NO

x emission limit of 0.08 or 0.05 lb/MMBtu, these limits would represent a 67 – 77%

reduction in NO

x from levels achieved using combustion co ntrols, which is generally consistent

with reduction efficiencies achie ved at the WA Parish units.

EPA concludes that SCR + LNB/SOFA is the most stringent NO

x control option available for NGS and that the SCR system can be designed to comply with an emission limit of 0.08 or 0.05 lb/MMBtu on a rolling 30-boiler-opera ting-day average. For clarity in compliance and enforcement, we are using two significant fi gures when we refer to the emission limit for SCR, therefore, a rate of 0.05 lb/MMBtu is being expressed throughout this document as 0.055 lb/MMBtu. EPA expects that a limit of 0.055 lb/ MMBtu will provide an adequate compliance

68 EPA estimates that each catalyst layer represents an SO 2 oxidation rate of 0.167%, based on a guarantee from Hitachi of 0.5% oxidation from 3 layers of catalyst.

69 See spreadsheets in document 0236 in Four Corners Power Plant BART docket: EPA-R09-OAR-2010-0683, e.g., “WA Parish CAMD Monthly 2001-2010”.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 37 of 129 margin for normal operational fluctuations. For the higher rate of 0.08 lb/MMBtu, we are considering this rate at 0.080 lb/M MBtu. EPA anticipates that the us e of three versus four layers of catalyst would result in diffe rent costs of compliance, different impacts to sulfuric acid emissions, and different impacts to the antici pated visibility improvement from controls. Therefore, EPA evaluated three la yers of catalyst to achieve 0.08 lb/MMBtu separately from four of catalyst to achieve 0.055 lb/M MBtu in our factor analysis.



### 3. Factor 1: Costs of Compliance

In assessing the cost of compliance, the analyses by AECOM and S&L examined the total

and annual costs of the control techno logies, as well as the cost effec tiveness of controls, in terms of 2008 or 2010 dollars per ton of pollutant removed ($/to n) and cost of the visibility improvement, in terms of dollars per average deciview improvement ($/dv). The cost effectiveness of controls should be calculated using emissions based on an annual average emission rate, whereas the degree of visibility improvement should be calculated usin g emissions based on the highest 24-hour emission

rate. 70 In this section, we will discuss the estimates of total and annual cost of controls and the cost

effectiveness of controls. We discuss visibility improvement from controls in Section 7.

A. NGS Approach to This Factor Prior to ANPRM

AECOM provided cost estimates for cont rol options in its November 2007 BART analysis. SRP submitted to EPA updated cost st udies by S&L for SNCR and SCR in 2008. The S&L cost estimates are not based on or equivale nt to the EPA Control Cost Manual. The BART

Guidelines recommend that cost estimates be based on the OAQPS Control Cost Manual (now known as the EPA Control Cost Manual), where possible, in order to maintain and improve consistency of cost estimates, and requir e documentation for any information supplied by vendors that affects assumptions regarding elemen ts that differ from the Control Cost Manual. However, the BART Guidelines also recommends taking into account any site-specific design or

other conditions identified above that affect the cost of a particular BART technology option.

Table 6 lists the total capital and total a nnual costs provided by AECOM in its January 2009 Revised BART Analysis, and EP A’s calculation of the percent NO

x reduction and the cost effectiveness ($/ton), calculated by di viding the annual cost ($/year) by the NO

x emissions reductions (ton NO

x /year) based on the information provided by AECOM.

70 Appendix Y to 40 CFR Part 51, “Guidelines for BART Determinations Under the Regional Haze Rule” IV.D.4.b. and IV.D.5.; “Regional Haze Regulations and Gu idelines for Best Availabl e Retrofit Technology (BART) Determinations; Final Rule”, 70 FR 39170, July 6, 2005Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 38 of 129 Table 6: AECOM and S&L Capital and Annual Cost Estimates, Percent Emissions Reductions, and Cost

Effectiveness for NO

x Controls (from January 2009 revised BART analysis) 71

Option (#) Cost or Cost Effectiveness Unit 1 Unit 2 Unit 3

Baseline Rate 0.49 lb/MMBtu 0.45 lb/MMBtu 0.46 lb/MMBtu

SCR + LNB/SOFA (Units 1 – 3) (Option 4) Total Capital Investment ($) $212,000,000 $281,000,000 $212,000,000 Total Annual Cost ($/yr) $28,951,500 $36,945,000 $28,951,500
Expected Emission (lb/MMBtu) 0.08 0.08 0.08

% NO

x Reduction from Baseline 84% 82% 83%

TPY NO

x Reduced 72 12,500 12,650 11,795 Cost Effectiveness ($/ton) $2,316 $2,921 $2,455

LNB/SOFA on Unit 2,

LNB/SOFA +

SCR on Units 1

and 3 (Option 3) Total Capital Investment ($) $212,000,000 $14,000,000 $212,000,000 Total Annual Cost ($/yr) $28,951,500 $1,622,000 $28,951,500
Expected Emission (lb/MMBtu) 0.08 0.24 0.08

% NO

x Reduction from Baseline 84% 47% 83%

TPY NO

x `Reduced 12,500 7,180 11,795 Cost Effectiveness ($/ton) $2,316 $226 $2,455

LNB/SOFA +

SNCR on Units 1

– 3 (Option 2) Total Capital Investment ($) $26,000,000 $26,000,000 $26,000,000 Total Annual Cost ($/yr) $8,809,333 $8,809,333 $8,809,333
Expected Emission (lb/MMBtu) 0.20 0.20 0.20

% NO

x Reduction from Baseline 59% 56% 57%

TPY NO

x Reduced 8,842 8,547 8,070 Cost Effectiveness ($/ton) $996 $1,031 $1,092

LNB/SOFA on

Units 1 – 3 (Option 1a) Total Capital Investment ($) $14,000,000 $14,000,000 $14,000,000 Total Annual Cost ($/yr) $1,622,000 $1,622,000 $1,622,000 Expected Emission (lb/MMBtu) 0.20 0.20 0.20

% NO

x Reduction from Baseline 59% 56% 57%

TPY NO

x Reduced 8,842 8,547 8,070 Cost Effectiveness ($/ton) $183 $190 $201

LNB/SOFA on

Units 1 – 3 (Option 1) Total Capital Investment ($) $14,000,000 $14,000,000 $14,000,000 Total Annual Cost ($/yr) $1,622,000 $1,622,000 $1,622,000 Expected Emission (lb/MMBtu) 0.24 0.24 0.24

% NO

x Reduction from Baseline 51% 47% 48%

TPY NO

x Reduced 7,622 7,180 6,829
Cost Effectiveness ($/ton) $213 $226 $238

B. Discussion of Factor in ANPRM

In our ANPRM, we presented two sets of capital and annual cost estimates for SCR+LNB/SOFA – costs estimated by S&L a nd presented in the AECOM revised BART analysis, and costs estimated by the Na tional Park Service (NPS) using the EPA Control Cost

Manual (Table 9). NPS provided cost estimates us ing the EPA Control Cost Manual because the BART guidelines state that “[i]n order to improv e consistency, cost estimat es should be based on

71 The cost estimates presented in the November 2007 BART Analysis were amended in a July 29, 2008 letter from Kevin Wanttaja, Manager of Environmental Services at SRP to Deborah Jordan, EPA Region IX Air Division Director. Costs for LNB/SOFA were revised from $10 million to $14 million per unit, which would increase all total capital cost figures from the November 2007 BART Analysis by an additional $12 million. The cost estimates in Table 12 represent the revised costs

for all control scenarios. These revised costs are reflected in AECOM’s January 2009 Revised BART Analysis for NGS.

72 EPA estimated ton per year (tpy) NO

x reductions using baseline and controlled emissions as reported by AECOM, and used average 2001 – 2003 heat input and operating hours repo rted to CAMD for each unit. Ho wever, as we stated in the ANPRM, EPA believes average, not maximum, baseline emissions should be used in calculating cost effectiveness.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 39 of 129 the OAQPS Control Cost Manual , where possible.” The OAQPS Control Cost Manual is now

called the EPA Air Pollution Control Cost Manual . The EPA Air Pollution Control Cost Manual (Sixth Edition, January 2002) 73 provides guidance and methodologies for estimating the cost and economic feasibility of a project, with a nom inal accuracy of ± 30%. Cost estimates for LNB/SOFA presented in the ANPRM are reprodu ced below in Table 7. NPS did not conduct a separate cost estimate for LNB/SOFA. Additi onally, EPA presented costs for Option 3 (SCR + LNB/SOFA on Units 1 and 3, LNB/SOFA on Unit 2) in the ANPRM but those costs are not reproduced here.

EPA did not make any revisions to the capit al and annual cost estimates presented by AECOM or NPS in our ANPRM, however, we did include our estimates of cost effectiveness (see Table 7) using average baseline NO

x emissions over 2004 – 2006 (0.35, 0.37, and 0.31 lb/MMBtu for Units 1 – 3, respectively), av erage heat input over 2004 – 2006 (8,184; 8,050; 7,814 MMBtu/hr for Units 1 – 3, respectively) , and average operat ing hours over 2004 – 2006 (8,126; 7,841; 8,352 hours per year for Units 1 – 3, respectively) , rather than 24-hour average emissions from the highest emitting day of the modeling period. In the ANPRM, EPA estimated

installation of SCR + LNB/SOFA on all three units at NGS would result in controlled NO

x emission rates of 0.06 lb/MMBtu each. EPA r ecalculated cost effec tiveness of LNB/SOFA controls using the same 2004 – 2006 average emi ssion, heat input, and op erating hour values

used to calculate SCR cost e ffectiveness (see Table 8).

Table 7: Cost Estimates for SCR+ LNB/SOFA presented in ANPRM

AECOM for SRP EPA NPS Total Capital Costs of SCR + LNB/SOFA

Unit 1 $212,000,000 EPA did not revise AECOM Total Capital Cost estimates in

the ANPRM $71,983,100

Unit 2 $281,000,000 $66,138,162

Unit 3 $212,000,000 $68,642,323

Total Annual Costs of SCR + LNB/SOFA

Unit 1 $28,951,500 EPA did not revise AECOM Total Capital Cost estimates in

the ANPRM $12,065,299

Unit 2 $36,945,000 $14,589,766

Unit 3 $28,951,500 $11,870,003 Cost Effectiveness ($/ton) of SCR + LNB/SOFA

Unit 1 $1,833 $3,002 $1,059

Unit 2 $2,419 $3,736 $1,528

Unit 3 $1,900 $3,549 $1,317

Table 8: Cost Estimates for LNB/SOFA presented in ANPRM
Total Capital Cost Total Annual Cost AECOM Cost

Effectiveness EPA Cost Effectiveness

Unit 1 $14,000,000 $1,622,000 $168 / ton $443 / ton

Unit 2 $14,000,000 $1,622,000 $187 / ton $385 / ton

Unit 3 $14,000,000 $1,622,000 $184 / ton $710 / ton

In the ANPRM, in addition to the three NO

x control scenarios (AECOM Option 1, 3, and 4), EPA considered another SCR control opti on. EPA understood the location of the coal-feed

73 http://epa.gov/ttn/catc/ products.html#cccinfoTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 40 of 129 line and physical layout of Unit 2 to result in higher cap ital and annual cost estimates for installing SCR on Unit 2. Therefore, EPA requested comment on installation of SCR to half of the Unit 2 flue gas because as currently configured, the flue gas is already split with each half containing its own separate hot -side electrostatic precipita tor (HS-ESP) and flue gas desulfurization unit (FGD). B ecause EPA anticipated the coal line would not need to be relocated under the “half-SCR” option, EPA estim ated half-SCR on Unit 2 to require a total capital investment of $106 million, a total annual cost of $14.5 million, with a cost-effectiveness of $2,000/ton. Finally, in the ANPRM, EPA also estim ated the increase in electricity generation

costs from NO

x controls at NGS in terms of dollar per k ilowatt-hour ($/kWh). In this TSD, we discuss increased electricity generation costs under Factor 3 – Energy and Non-Air Quality Impacts (See Section 4).

C. Affected State, Tribe and FLM Consultation

The Arizona Department of Environmental Quality (ADEQ) 74 commented that it is inappropriate to include projected costs of controls to consumers in our BART analysis without a description of the unusual circumstances that jus tify consideration of these costs. Additionally, ADEQ commented that the BART guidelines do not strictly require use of the EPA Control Cost Manual and allow companies to use other sources, such as vendor estimates, when appropriate, that EPA should include an analysis of increm ental costs of controls, and that EPA should

address the additional cost asso ciated with the use of an ultra-low conversion catalyst.

The Navajo Nation 75 recommended that EPA accept the cost estimates provided by SRP because the costs appeared to fall within the scope of the BART guidelines. The Navajo Nation and the Hopi Tribe 76 both recommended that EPA include an incremental cost analysis because of the potential importance the high incrementa l costs of SCR may have on the final BART determination. The Hopi Tribe also noted that th e cost estimates did not include th e costs of potential releases of ammonia dur ing transportation and storage.

NPS 77 commented that based on data from th e EPA Clean Air Markets Division, SCR

retrofits can result in controlled emissions of 0.05 lb/MMBtu. Theref ore, NPS recommended setting NO

x limits of 0.07 lb/MMBtu on a 24-hour basis, 0.06 lb/MMBtu on a 30-day rolling basis, and 0.05 lb/MMBtu on an annual averag e basis. NPS recommended using an annual average limit of 0.05 lb/MMBtu for determini ng cost effectiveness. Additionally, NPS

commented that the EPA Control Cost Manual sh ould be the primary source for developing cost analyses that are transparent and consistent , and that without vendor quotes or adequate justification for its cost estimates NPS conc luded that the capital and annual costs were overestimated when comparing typical dollar per kilowatt ($/kW) costs from a survey of SCR

cost data.

SRP 78 commented that the cost estimates developed by NPS using the EPA Control Cost

Manual are underestimated and fail to consid er current-day market prices and unique configuration and erection challenges at NGS. A dditionally, in response to EPA’s request for

74 Letter dated October 28, 2009 from Benjamin Grumbles, ADEQ to EPA Docket Center.

75 Letter dated March 1, 2010 from President Joe Shirley, Jr., Navajo Nation, to Anita Lee, EPA.

76 Letter dated March 1, 2010 from Chairman Leroy Shingoitewa, Hopi Tribal Council to Jared Blumenfeld, EPA.

77 Letter dated July 24, 2009 from John Bunyak, National Park Service, to Deborah Jordan, EPA.

78 Letter dated October 28, 2009 from Richard Hayslip, Salt River Project, to Anita Lee, EPA.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 41 of 129 comment on potential installation of SCR on half of the flue ga s on Unit 2, SRP commented that this option would not work due to engineering difficulties associated with maintaining similar pressures and temperatures between the split fl ues from Unit 2. SRP further recommended that EPA account for potential costs associated with Best Available Cont rol Technology (BACT) requirements under the Prevention of Significant Deterioration (PSD) permitting program that might be triggered if SCR caused a significant emi ssions increase (greater than 7 tons per year)

of sulfuric acid mist. SRP stated that if there is chance that sorb ent injection would be determined BACT for sulfuric acid mist, EPA s hould consider the cost of sorbent injection as well as downstream impacts of this technology tr iggering the additional need for a new polishing baghouse to control the increase in PM resulting from the so rbent injection. Finally, SRP

commented that EPA’s use of 0.06 lb/MMBtu as the NO

x emission limit for the cost effectiveness calculations and modeling was inap propriate because the original SCR design was

for 2+1 reactor to meet an emission limit of 0.08 lb/MMBtu. To meet an emission limit of 0.06 lb/MMBtu, SRP stated that a 3+1 reactor and would increase capital costs by $10 million per

unit.

On August 18, 2010, SRP submitted a revised co st estimate report generated by S&L to EPA that provided updated costs for SCR (in 2010 dollars), costs for SCR plus dry sorbent injection (DSI) to control sulfuric acid mist emissions, and costs for SCR plus DSI plus new polishing baghouses. S&L explained th at the SCR would be designed as a 2+2 reactor to achieve

an actual NO

x emission rate of approximately 0.05 lb/ MMBtu to ensure compliance with an anticipated NO

x emission limit of 0.07 – 0.08 lb/MMBtu on a 30-day rolling average basis. S&L states that the 40 – 60% margin of complia nce is provided to allow for normal operating fluctuations associated with minor equipment upsets, fuel characteristics that impact NO

x formation, and SCR process delays due to load changes. The design and cost estimates for the SCR system include use of ultra low SO 2 to SO 3 conversion catalysts that will limit SO 2 oxidation to below 0.5% across th e reactor. The 2010 revised cost estimates for SCR, and the cost estimates provided for SCR plus downstream sulfuric acid and particulate matter controls, are provided in Table 9.

Table 9: 2010 Capital and Annual Cost Estimates fo r SCR and Additional Polluta nt Controls Estimated by S&L for SRP
Capital Costs SCR only SCR + DSI SCR + DSI + Baghouse

Unit 1 $151,825,000 $154,946,000 $372,184,000

Unit 2 $205,808,000 $209,324,000 $410,919,000

Unit 3 $186,528,000 $189,772,000 $347,869,000

Total $544,161,000 $554,042,000 $1,130,972,000

Annual Cost

Unit 1 $21,579,000 $22,215,000 $50,014,000

Unit 2 $27,835,000 $28,518,000 $54,504,000

Unit 3 $25,601,000 $26,252,000 $47,196,000

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

The 2010 cost estimates generated by S&L for SCR are lower than previous cost

estimates. S&L states that costs estimates for th e SCR decreased from earlier studies because its most recent 2010 analysis showed that new or up graded induced draft fan motors and auxiliary power systems would not be required to s upport the new SCR system. Additionally, the 2010

cost estimates do not include costs for LNB/SO FA (which were volunta rily installed by theTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 42 of 129 owners of NGS over the 2009 – 2011 period). On November 20, 2008, EPA issued a final PSD permit to NGS to allow the installation of LNB/SOFA on all three units over 2009 – 2011. The

installation of LNB/SOFA is disc ussed further in Section 5 of th is TSD. Unlike previous cost estimates from S&L, the 2010 costs for Unit 3 also include common costs associated with all

three units.

On January 20, 2012, SRP submitted revised co st information for LNB/SOFA and SNCR (see Table 10). The updated SRP cost information for SNCR included total facility-wide capital

costs and annual O&M and total annual cost s. SRP did not provide unit-specific cost information, therefore, EPA assumed in our anal ysis that total facili ty-wide LNB/SOFA and SNCR costs would be divided equally betw een the three units. On March 16, 2012, SRP provided additional information on the SNCR cost estimate, including more detail than was originally provided in the January 20, 2012 SRP submittal on specific capital and annual costs

for SNCR. 79 On March 23, 2012, SRP submitted additional detail on its estimate for the cost of dry urea, which is almost 80% of the total annual cost of SNCR. 80

Table 10: Revised SNCR and LNB/SOFA Cost Estimates from SRP in 2012

Unit 1 Unit 2 Unit 3 Total

LNB/SOFA Total Capital Cost $15,000,000 $15,000,000 $15,000,000 $45,000,000

Annual O&M Costs 0 0 0 0

Total Annual Costs $1,738,000 $1,738,000 $1,738,000 $5,214,000

SNCR Total Capital Cost $13,066,667 $13,066,667 $13,066,667 $39,200,000

Annual O&M Costs $6,333,333 $6,333,333 $6,333,333 $19,000,000

Total Annual Costs $7,847,333 $7,847,333 $7,847,333 $23,542,000
SNCR+LNB/SOFA (calculated by EPA as the sum of LNB/SOFA and SNCR, above) Total Capital Cost $28,066,667 $28,066,667 $28,066,667 $84,200,000

Annual O&M Costs $6,333,333 $6,333,333 $6,333,333 $19,000,000

Total Annual Costs $9,585,333 $9,585,333 $9,585,333 $28,756,000

In its 2010 report, S&L did not directly calcul ate cost effectiveness of controls, however in its 2012 submittal, SRP did calculate average and incremental cost effectiveness of LNB/SOFA, SNCR at two different emission leve ls, SCR, and SCR+baghouses. Table 11 shows average and incremental cost es timates calculated by SRP in its 2012 Revised BART Analysis. SRP calculated incremental costs of SNCR agains t LNB/SOFA, and calcula ted incremental cost of SCR against the costs of both SNCR cases. Although not explicitly stated in SRP’s 2012 Revised BART Analysis, it appears that the incremental cost of SCR+baghouses are also calculated against both SNCR cases. Incremental cost is calculated by dividing the difference

between total annual cost s of two control options (numerat or) by the difference between total tons of pollutant reduced of the same two control options (denominator). It appears SRP only

included NO

x emissions in its average and incremen tal cost calculations for the SCR+baghouse

79 See document titled “Email from Grant Smedley, SRP 3-16-12_pl us attachments.pdf” in the docket for this proposed rulemaking.

80 See document titled “Email from Grant Smedley, SRP 3-23-12 Urea cost breakdown.pdf” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 43 of 129 control case. EPA notes that baghouses do not provide NO

x control, and if installed at NGS, would provide control of filterable and condensab le particulate matter (including sulfuric acid mist), and mercury, and would not be associat ed with BART. Therefor e, EPA believes SRP’s inclusion of an SCR+baghouse scenario is not correct.

EPA does not consider dry sorbent injection (D SI) or DSI plus baghouses as costs related to BART compliance. EPA cannot anticipate what a future control technology determination for

sulfuric acid mist under PSD or Tribal Minor NSR might requir e, and the BART Guidelines do not require the inclusion of poten tial future costs that might be associated with pre-construction permit requirements into the cost estimates for BART. EPA has determined that it is inappropriate to include the cost of DSI and baghouses into our BART cost analysis; however, we do provide some sensitivity discussion of the cost of baghouses, if they needed to comply with MATS, in our affordability anal ysis (See Section 6 of this TSD).

Table 11: Cost Effectiveness Calculated by SRP, as reported in its 2012 Revised BART Analysis

LNB/SOFA SNCR (0.18 lb/MMBtu) SCR SCR+Baghouses

Average Cost

Effectiveness $519/ton $1,481/ton $2,926/ton $5,918/ton

Incremental Cost

Effectiveness $519/ton $3,135/ton $5,282/ton $13,153/ton

D. EPA Conclusions Regarding This Factor

EPA contracted with EC/R Incorporated to conduct a detailed comparison of the capital and annual cost estimates presented by S&L ag ainst the EPA Control Cost Manual. The spreadsheets are included in the docket for this proposed rulemaking. 81 In general, as recommended by the Navajo Nation, EPA relie d on SRP’s own cost estimates, with the exception of any line item costs that are not expl icitly included in the EPA Control Cost Manual (CCM) or where EPA determined alternate cost s were more appropriate, e.g., interest rates. 82

See Table 12 for the list of revisions EPA made to the cost estimates from SRP.

Table 12: Summary of EPA Revisions to S&L Cost Inputs for SCR on Unit 2 83

S&L/ SRP EPA Revision EPA Rationale for Revision

Owners Construction Management, O&M Support,

Contract Services $8,163,050 $0 These costs are not included in the CCM and are not

included in the revised cost estimate.

Owners Legal Support and

Insurance $5,000,000 $0 CCM does not include legal fees, and states that insurance on an SCR system is a minimal cost and is included in the capital recovery.

Allowance for Funds Used During Construction (AFUDC) $4,059,526 $0 CCM sets AFUDC to zero for the retrofit of a SCR.

Interest Rate 9.8% 7% CCM uses 7% interest rate.

81 See spreadsheet titled “EPA Cost Analysis for NGS.xlsx” in the docket for this proposed rulemaking.

82 See http://www.whitehouse.gov /omb/circulars_a004_a-4/#e

83 Details for each unit are included in the EPA Cost Analysis spre adsheet. Unit 2 is simply used as an example in this TSD.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 44 of 129 EPA generated revised cost estimates based on the comparison of the 2010 S&L cost estimates against the EPA Control Cost Manual. The line item costs EPA revised are listed in Table 12, and the revised capital and annual cost estimates, and estimates of cost effectiveness

are shown in Table 13. EPA cal culated the cost effectivenes s of SCR assuming an emission limit of 0.055 lb/MMBtu. EPA’s revised total cap ital costs for SCR on all three units is approximately 9% lower than S&L’s cost estimate, and the total annual cost for SCR on all three units is 22% lower. The larger difference be tween annual costs estimated by EPA and S&L is primarily a result of the lower interest rate (7%) used by EPA compared to the rate assumed by S&L (9.8%). EPA did not adjust the annual O& M cost estimate (which does not include annualized cost of capital) by S&L. Annual cost s reported in Table 13 below represent the sum

of the annual O&M cost for each unit and EPA’s calculation of the annuali zed cost of capital.

Table 13: EPA Revisions to Cost Estimates for SCR (2010 dollars)
SCR Only SCR+LNB/SOFA
Total Capital Cost Total Annual Cost Total Capital Cost Total Annual Cost

Unit 1 $137,527,000 $16,963,576 $152,527,000 $18,701,576

Unit 2 $188,585,000 $21,783,090 $203,585,000 $23,521,090

Unit 3 $170,294,000 $20,056,549 $185,294,000 $21,794,549

Total $496,406,000 $58,803,215 $541,406,000 $64,017,215

The NREL report commissioned by DOI relies on capital and annual cost estimates for

SCR from S&L and the National Park Service (NPS) to “establish high and low bounds of a plausible range of future SCR costs” for NGS. 84 The NPS cost estimates rely on “the Modified Cost Manual Approach developed by EPA and in corporates several inpu ts provided by Navajo GS operating partner SRP”. NPS cost estima tes for SCR on Units 1 – 3 ranged from $134 million to $177 million, totaling $465 million on all three units. Our cost estimate for SCR on all units at NGS is over $30 million higher than the NPS cost estimate reported by NREL (see Table 3-6 of the NREL study). SCR cost estimates from S&L reported by NREL ar e identical to those we present in Table 9 above for Units 1 and 2, however, NREL cost estimates for Unit 3 ($188.25 million) differs slightly than estimat es from S&L and in Table 9 ($186.5 million). NREL reports total capital costs from the S&L study to equal $545.88 million, whereas the S&L study estimates total capital costs of SCR to equal $544.16 million. Our cost estimate for SCR on all units at NGS is roughly $48 million lower than the cost estimate from S&L. The NREL report describes the NPS and S&L capital cost estimates to represent a plausibl e range for SCR. EPA’s total capital cost estimate for SCR at NGS is within this plausible range.

The NREL report also relied on annual O&M costs (not includi ng annualized capital costs) from NPS and S&L. The annual O&M cost s for SCR on Units 1 – 3 at NGS from NPS were nearly $5 million higher (40% higher) than the S&L annual O&M costs. NPS’s higher estimate for annual O&M costs results mainly fr om higher estimated annual maintenance costs. 85

EPA used cost estimates for annual O&M costs from S&L. To calculate annualized capital costs, NPS applied a 7% interest rate, and the S&L study applied a 9.8% interest rate. In its economic analysis, NREL applied interest (d iscount) rates that were specific to each owner, i.e., 5% for Reclamation’s share (through an assumed muni cipal bond issued by CAWC D), 6% for LADWP,

84 See Table 3-6 and explanatory text on page 47 of NREL report.

85 See the three “updated NPS SCR modified cost manual approach” excel spreadsheets in the docket for this rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 45 of 129 approximately 8% for the investor-owned u tilities (APS, NV Energy, and TEP), and 9.8% for

SRP. 86 NREL states that the rate provided by SRP includes a risk premium. As discussed above, for the purposes of calculating cost effectiveness, EPA applied an interest rate of 7%, which is recognized as the appropriate inte rest rate for EPA control cost analyses and was used in the Regulatory Impact Analysis for the BART Guidelines. 87 Our application of a 7% interest rate is consistent with other EPA rulemakings and comp arable to the ownership-weighted average of the interest rates applied by NR EL of 7.3%. However, to create a more refined affordability analysis, as discussed in detail under the En ergy and Non-Air Quality Impacts of Compliance Factor, EPA also applied different interest rates to the individu al owners of NGS. See Section 4

of the TSD for additional information.

Several commenters, including NPS, suggested that the calcul ations of cost effectiveness should be based on the most stringent level of co ntrol possible. NPS stated that data from many existing facilities with SCR controls show a nnual average emission rates of 0.05 lb/MMBtu. An emission limit of 0.05 lb/MMBtu represents approximately an 86% reduction in NO

x emissions compared to the average baseline emission rate over 2001 – 2003. If we consider the new NO

x limit of 0.24 lb/MMBtu (30-day rolling average) set by the PSD permit issued to NGS in 2008 to

install advanced combustion controls on each unit, a post-SCR emission limit of 0.055 lb/MMBtu represents nearly an 80% reduction in the permitted NO

x emission limit. SRP’s voluntary installation of LNB/SO FA on Units 1 – 3 at NGS over 2009 – 2011 is discussed in

more detail in Section 5.

In EPA’s October 19, 2010 proposed BART dete rmination for Four Corners Power Plant,

EPA set a NO

x emission limit based on NO

x reduction efficiency from SCR of 80%. This NO

x reduction efficiency was chosen to be conser vative and was based on the minimum level of control estimated by Hitachi Power Systems. 88 In subsequent correspondence between EPA and Hitachi specific to Navajo Generating Station, Hi tachi guaranteed that a 2+1 SCR reactor system could comply with a 0.08 lb/MMBtu emission li mit (30-day rolling average), and a 3+1 SCR reactor system could comply with a 0.05 lb/M MBtu emission limit (30-day rolling average). Hitachi explains that its NO

x guarantees are based on what the SCR system achieves at the end of the catalyst life, 89 therefore, Hitachi designs its syst ems down to the level of the emission limit, rather than including a large complia nce factor (40 – 60%) as included by S&L. 90

Based on (1) the survey of CAMD data from NPS indicating that 0.05 lb/MMBtu on annual average has been achieved on several coal-fired power plants nationally; (2) the

information from Hitachi that an 80% NO

x reduction efficiency is achievable and conservative; (3) the current NO

x limit at NGS, following installation of LNB/SOFA on all three units, is 0.24 lb/MMBtu and a nearly 80% re duction of 0.24 lb/MMBtu is 0.05 lb /MMBtu; (4) the design basis

from S&L is a 2+2 reactor to achieve 0.05 lb/MMB tu to provide a wide compliance margin for a limit of 0.07 – 0.08 lb/MMBtu; (5) based on info rmation related to NGS EPA provided to Hitachi, Hitachi can guarantee compliance with a NO

x emission limit of 0.05 lb/MMBtu (30-day rolling average) with a 3+1 reactor; EPA concl udes that an emission limit of 0.055 lb/MMBtu is

86 See Table 1-10 of the NREL report.

87 http://www.whitehouse.gov/o mb/circulars_a004_a-4/#e

88 Email from Anthony Favale, Hitachi Power Systems, America to Anita Lee, EPA, quotes a re duction efficiency range of 80 – 90%., April 21, 2010.

89 Email from Stephen Guglielmo, Hitachi Power System s America, to Anita Lee, EPA, March 7, 2011.

90 S&L in its August 17, 2010 cost report stated that it designe d the SCR reactor system as a 2+2 system to achieve 0.05 lb/MMBtu in order to meet an anticipated emission limit of 0.07 – 0.08 lb/MMBtu on a 30-day rolling average.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 46 of 129 achievable at NGS, on a rolling average basis of 30 boiler operating days, and should not require more than four (2+2 or 3+1 reactor design) SCR catalyst layers, thus the capital and annual costs should not be substantially different from the costs estimated by S&L in its 2010 cost analysis and as revised by EPA according to the EPA Control Cost Manual.

The design basis associated with the cost estimate (in 2008 dollars) provided in the

ANPRM was a 2+1 reactor. In its comment lette r on the ANPRM to EPA, SRP stated that an additional layer of catalyst (from 2+1 to 3+1 or 2+2) would increase capital costs by $10 million per unit. 91 However, the SCR cost estimates provided in the ANPRM (2008$) for smaller 2+1 reactors are higher than the costs estimated by S&L following the ANPRM in 2010 (2010$) for 2+2 reactors. Because the 2010 SCR cost analysis was for 2+2 reactors (4 layers of catalyst), EPA believes that this cost analysis is generally representative of the reactor system Hitachi guarantees using 3+1 reactors to achieve 0.055 lb/MMBtu. Assuming the $10 million per unit cost for an additional catalyst layer cited by SRP in its comment letter on the ANPRM includes the material and construction costs for housing an additional layer of catalyst and is also applicable to the 2010 costs, EP A infers that increasing the NO

x limit to 0.080 lb/MMBtu, thus removing one catalyst layer, would reduce costs by $10 million per unit.

EPA is requesting comment on how the 2010 capital cost estimates would change based on 2+1 reactors, rather than 2+2 reactors. Additionally, EP A understands that Units 1 – 3 at NGS are currently on a 3-year outage cycle. EPA does not intend to for ce more frequent outages to accommodate the SCR system, therefore, EPA is also requesting comment on if and how the 0.055 and 0.080 lb/MMBtu emission limits, for 3+1 and 2+1 reactors, respectiv ely, may impact the current 3-year outage schedule and costs of controls. EPA’s estimated changes to the capital and annual costs and cost effectiveness

based on reactor size are shown in

91 This statement was made in reference to EPA’s use of a 0.06 lb/MMBtu post-SCR NO

x emission rate in cost effectiveness and modeling calculations in the August 19 , 2009 ANPRM. SRP’s orig inal pre-ANPRM design was for a 2+1 reactor. The design basis for the SCR system in the 2010 cost analysis conducted by S&L was a 2+2 reactor that included an additional layer of catalyst to further enhance NO

x removal.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 47 of 129 Table 14. Unless the cost cited by SRP of an additional $10 million per unit for an additional catalyst layer is overestimated, four layers of catalyst (3+1 or 2+2 reactors) are slightly more cost

effective in terms of NO

x removal than three layers of catalyst (2+1).Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 48 of 129 Table 14: Cost Comparison of SCR+LNB/SOFA React or Sizes Based on EPA Revisions to 2010 S&L

Costs

Unit 1 Unit 2 Unit 3 Total
Total Capital Cost

4 catalyst layers (0.055 lb/MMBtu) $152,527,000 $203,585,000 $185,294,000 $541,406,000

3 catalyst layers (0.080 lb/MMBtu) $142,527,000 $193,585,000 $175,294,000 $481,406,000

Total Annual Cost

4 catalyst layers (0.055 lb/MMBtu) $18,701,576 $23,521,090 $21,794,549 $64,017,215

3 catalyst layers (0.080 lb/MMBtu) $17,757,647 $22,577,161 $20,850,620 $61,185,427

Average Cost Effectiveness ($/ton) 92

4 catalyst layers (0.055 lb/MMBtu) $2,011 $2,256 $2,464 n/a

3 catalyst layers (0.080 lb/MMBtu) $2,080 $2,359 $2,584 n/a

EPA recognizes that emissions of sulfuric aci d mist may increase with higher levels of

NO

x control, if the higher levels of NO

x control require additional laye rs of catalyst, representing a potential adverse impact on visibility that would offset visibility benefits from NO

x reductions, especially at the Grand Canyon or other nearby Class I areas. EPA also notes that in the 2010 cost estimate for NGS, S&L included in the design the use of ultra-low SO 2 to SO 3 conversion catalysts to limit SO 2 oxidation to below 0.5% across the reactor. 93 With three layers of catalyst in use, Hitachi guarantees an SO 2 to SO 3 conversion rate of 0.5%, thus EPA estimates that each layer of catalyst contributes approximately 0.167% conversion. This means that the addition of another layer of catalys t to further enhance NO

x removal would result in additional SO 2 to SO 3 conversion. In considering NO

x emission limits of 0.08 lb/MMBtu and 0.05 lb/MMBtu, Hitachi stated that it can guarantee compliance with a limit of 0.05 lb/MMBtu with a 3+1 reactor and compliance with a limit of 0.08 lb/MMBtu using a 2+1 reactor. EPA mo deled the visibility impacts of SCR achieving a limit of 0.05 lb/MMBtu and an SO 2 to SO 3 conversion rate of 0.67% with 4 total layers of catalyst (3+1) and S CR achieving a limit of 0.08 lb/MMBtu and an SO 2 to

SO 3 conversion rate of 0.5% with 3 total layers of catalyst (2+1). Th e modeling results are

discussed in Section 7 of this TSD.

In assessing the cost of SCR, EPA evalua ted cost estimates from SRP against the EPA Control Cost Manual and determined that capita l cost estimates for SCR should be reduced by approximately 9% to be consistent with the EPA control cost manual. Because total capital costs of SNCR are low (nearly 14 times lower) in comparison to the total capital costs of SCR, EPA has determined that it is not necessary at th is time to evaluate SN CR costs against the EPA Control Cost Manual and will use the total capita l costs provided by SRP in our analysis (see

92 Average cost effectiveness of SCR is cal culated compared to a 2001-2003 baseline, but includes the total annual cost of

LNB/SOFA because the SCR and combustion controls would both contribute to the total estimated NO

x reductions.

93 The 2010 S&L study did not appear to sp ecify whether the 0.5% conversion was th e design for the reactor using with all four catalyst layers in use, or three catalyst layers in use. To be conservative and consistent with the Hitachi guarantee, EPA

assumes a 0.5% conversion over th ree layers rather than four.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 49 of 129 Table 10). In our assessment of total annual co sts for SCR, EPA used a 7% interest rate, compared to the 9.8% rate used by SRP, resultin g in total annual costs estimated by EPA to be 22% lower than those estimated by SRP. If EPA a pplied a 7% interest rate to the total capital

cost of SNCR and amortized over 20 years, the total annual cost would not change significantly ($22.7 million using a 7% interest rate 94 versus $23.5 million using a 9.8% interest rate) because

the total annual cost of SNCR is dominated by the annual O&M costs, consisting mostly of expenses associated with dry urea ($18,640,000). Because total annual costs for SNCR would not change significantly using th e interest rate recommended in the EPA Control Cost Manual, EPA has determined it is not necessary at this time to revise total annual cost estimates for

SNCR and will use the total annual cost estimates provided by SRP in our analysis (see Table 10).

ADEQ suggested that it was inappropriate to include the anticipated increase in electricity costs to consumers in our ANPRM w ithout explanation of the unusual circumstances justifying its consideration. Th e BART guidelines state that under the Energy and Non-Air Quality Impacts factor, the reviewing authority may consider whether a given alternative would result in significant economic disruption or unem ployment. EPA determined that an increase in electricity generation costs warran ted review as a potential economic impact and we include this discussion in Section 4 of this TSD. ADEQ also suggested that EPA should address the

additional cost associated with the use of an ultra-low conversion ca talyst. Because the 2010 S&L study included in its design the use of an ultra low conversion catalyst, and because EPA relied on the 2010 S&L cost estimates, EPA has determined that the new cost estimates appropriately include the cost of the ultra-low conversion catalyst.

The Hopi Tribe commented that the cost estim ates did not include th e costs of potential releases of ammonia during tr ansportation and storage. S&L included the direct costs of

ammonia in its annual cost estimates. EPA has determined that costs associated with potential releases of ammonia during tran sportation and storage are not in cluded in the EPA Control Cost

Manual and should not be included in cost of compliance estimates in a BART determination. However, EPA acknowledges that risks do exist from the transportation and storage of ammonia,

and we discuss results from a risk analysis examining emissions of pollutants associated with the transport of ammonia to NGS and risks associated with ammonia itself in Section 4 of this TSD – Energy and Non-Air Quality Impacts of Compliance (Factor 3).

Many commenters suggested that EPA consider the incremental cost effectiveness, which compares the annual cost and performance level (tons per year reduced) of a control option to those of the next most stringent option. The BART Guidelines requi re consideration of the costs of compliance, and recommends two types of co st effectiveness calculations – average cost

effectiveness and incremental cost effectiveness. In our ANPRM, we did not present incremental cost comparisons and instead focused on averag e cost effectiveness because average cost effectiveness is the more commonly used and repo rted metric to compare costs between different facilities. Thus, average cost effectiveness is generally a more valuable metric in determining whether a given cost is reasonable because it can more easily be compared to other similar facilities. In considering incremental cost eff ectiveness, comparisons fo r reasonableness are less comparable between facilities, t hus incremental cost effectiveness is generally a more subjective metric than average cost effec tiveness. We presented SRP’s calculations of incremental cost

94 See “Cost comparisons tab” in the spreadsheet titled “EPA cost analysis for NGS.xlsx” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 50 of 129 effectiveness in Table 10 above. Because SRP in stalled LNB/SOFA on one unit per year at NGS over 2009 – 2011, consideration of incremental cost of SCR (compared to LNB/SOFA) is particularly useful because it cap tures the cost effectiveness from the perspective of a different baseline period. The baseline period used in the BART analysis for emissions and meteorological data is 2001 – 2003. Calculati ng the incremental cost effectiveness of SCR+LNB/SOFA compared to LNB/SOFA over the 2001 – 2003 baseline is generally equivalent to the average cost effectiveness of SCR+LNB/SOFA using a baseline period after

LNB/SOFA has been instal led on all three units (e.g., a baseline of 2011 – 2013).

The BART Guidelines caution that: “You should ex ercise care in deriving incremental costs of costs of candidate control options. Incremental cost-effectiveness comparisons should focus on

annualized cost and emission reduction differences between “dominant” alte rnatives”. The BART BART Guidelines describes the process for generating a graphical plot of total annualized costs for all for all control options on the y-axis and each co ntrol options’ corresponding emission reductions on the on the x-axis. This plot identifies the “least-cost enve lope”, representing “a set of options that should be should be dominant in the choice of a specific op tion”. See 70 FR at 39167 and 39168. The main control control options that SRP has focused on have be en LNB/SOFA, SNCR, and SCR. Of these, SRP identified two possible scenarios for SNCR at equivalent cost (i .e., SNCR may achieve NO

x emissions emissions of 0.15 lb/MMBtu or 0.18 lb/MMBtu), and EPA has identified two possible scenarios for for SCR at differing costs (i.e., SCR may achieve NO

x emissions of 0.05 lb/MMBtu or 0.08 lb/MMBtu). lb/MMBtu). Of these 3 control options with 5 emissi on rate scenarios, EPA’s graphical plot indicates

indicates that the “least-cost envelope” (dominant) control opt ions are LNB/SOFA, SNCR (at 0.015 0.015 lb/MMBtu), and SCR (at 0.055 lb/MMBtu). 95 However, because SRP indicated by letter on July on July 20, 2012 that it expected SNCR to achieve roughly 0.18 lb/MMBtu to meet a limit of 0.20 0.20 lb/MMBtu, we report results base d on 0.18 lb/MMBtu for SNCR.

95 See “least cost envelope” tab in spreadsheet titled “NGS em issions and incremental costs.xlsx” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 51 of 129 Table 15 below summarizes average and increm ental cost estimates EPA calculated for the dominant control options using EPA’s cost estimates for SCR (Table 13) and SRP’s 2012 estimates for LNB/SOFA and SNCR (Table 10).

Note that although EPA used the total cap ital and total annual cost estimates for LNB/SOFA and SNCR from SRP, ou r calculated average and increm ental cost effectiveness of LNB/SOFA and SNCR differ slightly from SRP’s estimates (Table 11), in part because EPA and SRP likely used slightly different baseline emi ssion values. EPA calculated baseline emissions using average NO

x emission rates and heat input values over 2001 – 2003 for each unit. 96 EPA

did not find sufficient information in SRP’s 2012 Updated BART analysis to determine how their baseline emissions (and thus, emission reductions) for NO

x were calculated.

96 See spreadsheet titled “NGS emissions and incremental co sts.xlsx” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 52 of 129 Table 15: Average and Incremental Cost Effectivene ss of Dominant Control Options Calculated by EPA

Unit 1 Unit 2 Unit 3 Average

Average Cost Effectiveness ($/ton) 97

LNB/SOFA $475 $424 $560 $486

SNCR+LNB/SOFA $1,747 $1,558 $1,930 $1,745

SCR+LNB/SOFA $2,011 $2,256 $2,464 $2,240
Incremental Cost Effectiveness ($/ton)

SNCR+LNB/SOFA (vs. LNB/SOFA) $4,290 $3,826 $4,214 $4,110

SCR+LNB/SOFA (vs. SNCR+LNB/SOFA) $2,392 $3,261 $3,147 $2,933

SCR+LNB/SOFA (vs. LNB/SOFA) $3,008 $3,444 $3,493 $3,315

The estimated incremental cost of S CR+LNB/SOFA (compared to LNB/SOFA) is similar to the average cost effectiveness of SCR+LNB/SOFA. Additionally, incremental cost effectiveness of SCR+LNB/SOFA (compared to SNCR+LNB/SOFA), is lower than the

incremental cost effectiveness of SNCR+LNB/ SOFA (compared to LNB/SOFA). The BART guidelines provide a hypothetical example of two control options where the incremental cost effectiveness of Option 1 (compared to Opti on 2) is $20,000/ton, 11 times larger than the average cost effectiveness of Option 1 of $1,900. In this example, the BART guidelines 98 state
that:

[w]hile $1,900 per ton may still be deemed r easonable, it is useful to consider both the average and incremental cost in making an overall cost-effectiveness finding. Of course, there ma y be other differences between these options, such as, energy or water use, or non-air environm ental effects, which also should be considered in selecting a BART technology.

Although SRP is correct in stating that the increm ental cost effectiveness of SCR (compared to LNB/SOFA) is greater than the incremental co st effectiveness of LN B/SOFA (compared to baseline), the BART guidelines do not provide a th reshold for a level of incremental (or average)

cost effectiveness that is reasonable or unreason able. Because the incremental cost effectiveness of SCR, compared to LNB/SOFA and SNCR, is co mparable to the average cost effectiveness of SCR, EPA considers the incremental cost effec tiveness of SCR to suggest that SCR is cost effective on both an average and incremental basis.

For comparison of average cost effectiveness values,

97 Average cost effectiveness of SNCR and SCR include the total annual cost of LN B/SOFA, which are already installed and aid post-combustion controls in achieving the anticipated NO

x reductions.

98 See 70 FR at 39167 (July 6, 2005).Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 53 of 129 Table 16 shows cost effectiveness for SCR retrof its estimate for several Western power plants. This table simply serves as a means to compar e the cost effectiveness estimates between a few

different facilities in the West and should not be misconstrued to suggest that SCR was required

at all of the facilities listed below.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 54 of 129 Table 16: Estimated Cost Effectiveness of SCR for Several Western Power Plants
Facility Year of Cost Size Cost Effectiveness ($/ton) Craig (Unit 2) Not specified 428 MW $6,300 99
Hayden Station (Units 1 and 2) 2006 190 and 275 MW $3,400 – $4,100 100
PacifiCorp Naughton (Units 1 – 3) 2006 160 – 330 MW $2,751 – $2,848 101
Four Corners Power Plant (Units 4 and 5) 2008 750 MW $2,600 – $2,900

Four Corners Power Plant (Units 1 – 3) 2008 170 – 220 MW $2,500 – $3,200 102

Navajo Generating Station (Units 1 – 3) 2010 750 MW $2,240 San Juan Generating Station (Units 1 – 4) 2010 350 – 544 MW $1,987 - $2,652 103

In its comment letter on the ANPRM, SRP stat ed that the costs associated with dry sorbent injection (DSI) and new baghouses must be included in the cost estimate for SCR because DSI and new baghouses might be required as Best Available Control Technology (BACT) in a possible future Prevention of Si gnificant Deterioration (PSD) permit if a BART determination requiring SCR causes a significant emission increase (greater than 7 tpy) of sulfuric acid mist. EPA does not agree that the cost of DSI and baghouses should be included in

the cost estimates for SCR as BART. Without undertaking a source-s pecific top-down PSD BACT analysis, EPA cannot determine what may be required as BACT fo r potential significant

emission increases for sulfuric acid mist. Th erefore, EPA cannot speculate what BACT for sulfuric acid mist might be in the event a PSD permit is required for NGS.

EPA notes that for a 2009 PSD permit issued to the Coronado Gene rating Station (CGS) by the Arizona Department of Environmental Quality (ADEQ) 104 for the installation of SCR on Unit 2 at CGS, the BACT determination for sulfur ic acid mist required use of an ultra-low SO 2 to

SO 3 conversion catalyst, with an interim sulfuric acid mist BACT limit of 0.012 lb/MMBtu. ADEQ required a testing program to determine if DS I would be effective at CGS to consistently

reduce the sulfuric acid emission rate to 0.006 lb /MMBtu. If the testing program showed that Unit 2 at CGS could consistently meet the lower limit, the lower limit would become the BACT

limit. If Unit 2 at CGS could not meet the lower limit, ADEQ required CGS to conduct a minimization analysis to evaluate additional options to achieve 0.005 lb/MMBtu or less while maintaining PM emissions below the permitte d emission limit of 0.03 lb/MMBtu. However, ADEQ stated that the minimization analysis will not require the use of additional PM control equipment, such as a baghouse. 105 Although EPA cannot determine at this time what a potential

sulfuric acid mist BACT determination for NGS might require, EPA does not agree with SRP that the possibility for additional controls to comply with BACT for PSD warrants the inclusion of those costs under the BART requirement of th e Regional Haze Rule. Therefore, EPA does not include DSI or baghouses in the cost of compliance for SCR.

99 See Colorado BART Analysis for Craig Units 1-2, in the docket for this proposed rulemaking.

100 See Colorado BART Analysis for Hayden 1-2, in the docket for this proposed rulemaking.

101 77 FR 33022 (June 4, 2012)

102 The average cost effectiveness report ed in the October 19, 2010 proposed FIP for Four Corners Power Plant (75 FR 64221), were based on EPA revisions to cost es timates submitted by Arizona Public Service.

103 The average cost effectiveness, reported in supporting documents (EPA–R06–OAR–2010–0846-0128) to the October 22, 2011 final FIP for New Mexico (76 FR 52388), were generally based on an EPA Region VI analysis using the EPA Control

Cost Manual.

104 See Final PSD Permit for Coronado, in the docket for this proposed rulemaking.

105 Permit Condition II.H.4.a of the January 21, 2009 Final permit for Coronado Generating Station issued by ADEQ. Significant Permit Revision Number #46236.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 55 of 129 In addition to the potential need for installa tion of new baghouses at NGS to comply with a future control technology determination for pre-construction permitting for possible emission increases of sulfuric acid mist, EPA unders tands that SRP has been evaluating whether

installation of one or more new baghouses would be needed at NGS to comply with the recently promulgated National Emission Standard for H azardous Air Pollutants (NESHAP) for emissions of mercury and other acid gases from electric generating units (EGUs), known as the Mercury and Air Toxics Standard (MATS). 106 The final MATS set a mercury emission standard of 1.2 pounds per trillion British therma l units heat input (lb/TBtu). 107 Technical information provided with the final MATS rule estimated Hg emissi ons to range from 1.14 to 1.30 lb/TBtu from Units

1 – 3 at NGS in 2009. 108 However, information reported to the EPA Toxics Release Inventory suggests facility-wide average Hg em issions from NGS to be 3.26 lb/TBtu. 109 SRP indicated to EPA that it would be testing units at CGS that are similar to NGS to assess the feasibility of calcium bromide injection without the installati on of new baghouses to meet the MATS limit for

mercury. 110 The MATS compliance date for existing facilities is by Apr il 16, 2015, however, an additional year may be granted at the discre tion of the permitting authority for its Part 71 operating permit (Navajo Nation Environmental Protection Agency) if additional time is needed

for the installation of new controls. SRP has indi cated to EPA that based on initial testing of calcium bromide injection, it is cautiously optimis tic that new baghouses will not be needed at NGS to comply with MATS.

As stated in the previous paragraph, EPA believes the cost of baghouses, if needed for MATS or for PSD, should not be included as co mpliance costs for BART. Therefore, EPA has not included the cost of DSI or baghouses in our analysis of cost effectiveness of NO

x control technologies under consideration for BART. Howe ver, if baghouses are needed at NGS for MATS, these costs would likely be incu rred before the installation of any NO

x control technologies, therefore, our economic analysis includes some discussion and consideration of possible costs and economic effects of baghouse in stallation. See Section 4 (Energy and Non-Air Quality Impacts of Compliance) of this TSD for additional information.

Based on the cost data presented by SRP, as well as EPA’s revisions to SRP’s cost estimates, and our analysis of average and increm ental cost effectiveness, EPA has determined that SCR is cost effective; therefore, EPA will continue evaluating SCR in the BART five-factor analysis.



### 4. Factor 2: Energy and Non-Air Qualit y Environmental Impacts of Compliance

The BART Guidelines describe the energy and n on-air quality impacts of compliance factor as

an examination of whether the use of the control technology would result in di rect energy penalties or

106 77 FR 9304, February 16, 2012.

107 See Table 2 to Subpart UUUUU of Part 63, 77 FR at 9490, February 16, 2012.

108 See spreadsheet titled “Emissions Spreadsheet” and dated 12/16/11 on the following website: http://www.epa.gov/ttn/atw/utility/utilitypg.html , or identical spreadsheet: “mats_final_current_base_hap_inven.xlsx” in the docket for this proposed rulemaking.

109 Calculated from total facility Hg emissions of 566 pounds in 2010 and total facility heat input of 173 million MMBtu. See http://www.epa.gov/tri/tridata/index.html , or spreadsheet titled “NGS TRI 2010 data .xlsx” in the docket for this proposed rulemaking.

110 Based on MATS discussion on January 6, 2012 between representatives of Salt River Project and several EPA offices: Office of Air and Radiation, Clean Ai r Markets Division, and Region IX.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 56 of 129 benefits, and whether there are environmental impact s other than air quality due to emissions of the pollutant in question or due to the control technology.

A. NGS Approach to This Factor

In its January 2009 BART analysis, AECO M identified the follo wing potential non-air quality impacts resulting from the addition of SCR at NGS: the addition of ammonia or urea storage and handling systems and the potential for accidental rele ases, the need to develop and implement Risk Management Plans (RMP) and Pr ocess Safety Measures (PSM) for ammonia, and increased emissions of criteria pollutants as sociated with ammonia deliveries by truck to NGS. In addition to those impacts, AECOM liste d several additional impacts from SNCR also associated with the use of ammonia, including affect of ammonia on fl y ash salability, and formation of particulate ammonium. However, b ecause the use of SNCR results in higher levels of un-reacted ammonia (ammonia slip) than S CR, AECOM did not associate these additional impacts with SCR. In its 2010 cost study, SRP incl uded the costs for direct energy impacts, i.e., power consumption associated with SCR in the cost analyses, as an annual cost for auxiliary and ID fan power ($1.8 million / year). The indirect energy impacts, such as the energy to produce raw materials, were not considered, c onsistent with the BART guidelines.

B. Discussion of this Factor in ANPRM

In the ANPRM, EPA outlined several energy and non-air quality environmental impacts of the control technologies, including increased unburned carbon in the fly ash (loss of ignition or LOI) resulting from LNBs, increased emissions of sulfuric acid that may trigger permitting requirements under the Prevention of Significant Deterioration ( PSD) program from the use of traditional SCR catalysts, particularly those that are vanadium-based, and the parasitic load resulting from the operation of SCR. Although not presented under this f actor in the ANPRM, EPA also projected the increase in electricity generation costs resul ting from LNB/SOFA and

SCR+LNB/SOFA from NO

x controls. See Table 17.

Table 17: Increase in Electricity Generation Costs ($/kWh) from NO

x Controls at NGS Presented in

ANPRM

LNB/SOFA SCR + LNB/SOFA

Unit 1 $0.0003 $0.006

Unit 2 $0.0003 $0.007

Unit 3 $0.0003 $0.006

C. Affected State, Tribe, and FLM Consultation

The Arizona Department of Environmental Qu ality (ADEQ) submitted comments that the non-air quality impacts of SCR, such as trucki ng of ammonia and challenges associated with ammonia storage and handling, as well as the energy efficiency losses resulting from the installation of SCR, should be assessed. The Colorado Department of Public Health and Environmental (CDPHE) 111 commented that EPA should address any potential particulate

111 Letter dated September 25, 2009 from James B. Martin, CD PHE to Laura Yoshii, EPA; Document number 0071 in the

docket for the ANPRM: EPA-R09-OAR-2009-0598.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 57 of 129 emission control options in a comprehensive cont ext that considers the possible co-benefits of mercury (Hg) emissions reductions. The Attorney General of New Mexico 112 commented that

EPA should consider the interrela tionship between BART controls and Hg emissions, and stated

that EPA must initiate Section 7 Consultation under the Endangered Spec ies Act with the U.S. Fish and Wildlife Service for potential increases in air pollutant emissions and because it

believes that EPA has discretion to achieve re ductions in Hg emissions. The State Treasurer 113

and Governor of Arizona 114 both commented that power from NGS is used by the Central Arizona Project (CAP) to pump water to much of Arizona. Construction of CAP was authorized by Congress in 1968 under the Colorado River Basi n Project Act to deliver the Arizona’s 2.8 million acre-feet (AF) surface water entitlement of the Colorado River to the state. The 336-mile CAP delivery system was completed in 1993 and delivers 1.5 million AF of water to Maricopa, Pima, and Pinal Counties through a series of can als and pumping stations to lift water up an elevation of 3,000 feet from Lake Havasu to cl ose to the city of Tu cson. CAP water currently

meets over 20% of Arizona’s total water dema nds, and within CAP’s service area, which encompasses about 80% of Arizona’s water user s and taxpayers, CAP water meets about 50% of the municipal demands. Additionally, 40% of CAP wa ter supply is dedicated to Native American

use.

The Navajo Nation (the Nation) submitted comm ents raising concerns that requiring SCR as BART for NGS could potentially force the faci lity to shut down, resulting in great economic harm to the Navajo directly and indirectly, through lost employme nt at NGS, at the Kayenta Coal Mine that supplies 8.3 million tons of coal to NGS , as well as the revenue to the Nation in the form of royalties and taxes. 115 The Nation stated that in 2005-2006, the NGS payroll was $47 million, with 512 permanent employees, 69% of whom are Native American, 300 seasonal employees, 93% of whom are Native American. The Nation reports th at the Kayenta Mine payroll is $44 million, with approximately 400 employees, of whom a large percentage are Native American. The Navajo Nation provided additional and updated information during our consultation with tribes prior to our proposed rulemaking for NGS. 116 The Navajo Nation

reiterated their recommendati on that LNB/SOFA be determin ed BART for NGS to ensure continued operation of the facility and preserva tion of jobs and revenues, and also highlighted the importance of title V operating permit emission fees from NGS to the continued development of the Air Quality Program at the Navajo Nation EPA.

The Hopi Tribe commented that the Hopi supply coal and water to NGS, thus an significant fraction of the annual Hopi tribal budget comes from revenue derived or associated

with NGS. 117 Comments from the Hopi Tribe describe th at the tribe is geographically isolated from Arizona, there is no on-site industrial de velopment and because the Hopi have rejected gaming as a potential source of revenue becau se gaming conflicts with the Hopi culture,

112 Letter dated September 28, 2009 from Seth Cohen, Attorney General of New Mexico, to Anita Lee, EPA; Document

number 0072 in the docket for the ANPRM: EPA-R09-OAR-2009-0598.

113 Letter dated October 26, 2009 from Dean Martin, Arizona State Treasurer, to Laura Yoshii, EPA; Document number 0174

in the docket for the ANPRM: EPA-R09-OAR-2009-0598.

114 Letter dated October 13, 2009 from Janice Brewer, Arizona Governor, to Laura Yoshii, EPA; Document number 0078 in

the docket for the ANPRM: EPA-R09-OAR-2009-0598.

115 Letter dated March 1, 2010 from Joe Shirle y, Jr., President, Navajo Nation, to Anita Lee, EPA; Document number 0209 in

the docket for the ANPRM: EPA-R09-OAR-2009-0598.

116 Letter dated September 21, 2012 from Ben Shelly, Presiden t, Navajo Nation to Jared Blumenfeld, EPA; Follow up to August 7, 2012 Consultation on Proposed BART Rule for Navajo Generating Station in the docket for this proposed rule.

117 Letter dated March 1, 2010 from Leroy Shingoitewa, Chai rman, Hopi Tribal Council, to Jared Blumenfeld, EPA;

Document number 0211 in the docket for the ANPRM: EPA-R09-OAR-2009-0598.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 58 of 129 employment opportunities on Hopi land are lim ited. The Hopi stated that the Federal Government has a trust and fiduciary responsibilit y to Indian Tribes, wh ich includes the duty to administer programs in such as way to avoid adverse impacts to Indian Rights and natural resources owned by Tribes. The Hopi comm issioned and provided to EPA a study by ICF International (ICF) to examine the economic viab ility of NGS if (1) SCR were implemented at NGS by 2015, (2) CO 2 controls were implemented by 2012, a nd (3) stringent Hg controls were required by 2015. ICF concluded that the capital investments associated with SCR, CO 2 controls, and Hg controls were required, NGS would not be economically sound and the facility may be retired, assuming natural gas prices were at or below $5.60/MMBtu (in 2008 dollars). The Hopi tribe commented that if NGS closed, the economic impacts to the Tribe would be catastrophic and include curtailment of critical social progr ams, lost employment, and loss or slowing of critical infrastructure programs . The Hopi Tribe also commente d about risks associated with

ammonia use for the SCR.

Several Tribes in Arizona sent comments to EPA expressing con cern over the potential impact of BART on Tribal water settlement agre ements, rates, and infrastructure development.

The Tohono O’odham Nation 118 raised concerns regarding the impact of stringent controls at NGS on the fund that pays for delivery of CAP water. The Ak-C hin Indian Community 119

commented that it relies on CAP for its entire wa ter supply, and that EPA must ensure regulation

of NGS will not have an advers e impact on its water rights. The Gila River Indian Community (Gila River) 120 commented that if EPA requires SCR at NGS, the cost of CAP water will increase significantly, and the revenue genera ted for the fund created by the 2004 Arizona Water Settlement Act to defray cost of Tribes of obtaining and using its water entitlements will

decrease. Gila River stated th at requiring SCR has clear environmental justice implications because this determination would have dispropo rtionate impacts on Indian Tribes. Gila River

further commented that the loss of CAP water would impact the restrictions on ground water pumping mandated by the 1980 Arizona Groundwater Code. Gila River requested EPA conduct a voluntary Environmental Impact Study (EIS) for the BART rulemaking. The Fort McDowell Yavapai Nation raised concerns about the direct and indirect cost in creases if SCR were

determined BART for NGS. 121 The Pascua Yaqui Tribe submitted comments to EPA on December 14, 2009 raising concerns over the afford ability of CAP water and potential impacts on a future water rights settlement agreement. 122

After the close of the ANPRM comment pe riod, during the public comment period for the MATS rule, EPA received requests for consul tation from several tribes located in Arizona. 123

EPA continued consultation with tribes on BART for NGS, and, at the reque st of several tribes,

118 Letter dated March 1, 2010 from Ned Norris, Jr., Chairman, Tohono O’odham Nation, to Jared Blumenfeld, EPA;

Document number 0212 in the docket for the ANPRM: EPA-R09-OAR-2009-0598.

119 Letter dated March 1, 2010 from Robert Palmquist, Strickland & Strickland, General Counsel to the Ak-Chin Indian Community, to Jared Blumenfeld, EPA; Document number 0214 in the docket for the ANPRM: EPA-R09-OAR-2009-0598.

120 Letter dated February 23, 2010 from William Rhodes, Govern or, Gila River Indian Community, to Jared Blumenfeld, EPA; Document number 0210 in the docket for the ANPRM: EPA-R09-OAR-2009-0598.

121 Letter dated February 26, 2010 from Clinton Pattea, Presid ent, Fort McDowell Yavapai Na tion, to Jared Blumenfeld, EPA; in the docket for this proposed rulemaking.

122 Letter dated December 14, 2009, from Peter Yucupicio, Chairman, Pascua Yaqui Tribe, to Laura Yoshii, EPA; in the docket for this proposed rulemaking.

123 See letter dated May 20, 2011 from William Rhodes, Governor , Gila River Indian Community , to Lisa Jackson, EPA; letter dated July 14, 2011 from William Rhodes to Lisa Jacks on; letter dated June 21, 2011 from William Rhodes to Colleen McKaughan, EPA; undated letter from Ben Shelly, President, Navajo Nation, to Gina McCarthy, EPA; letter dated July 29, 2011 from Ben Shelly to Lisa Jackson, in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 59 of 129 included consultation discussions related to th e national rulemaking for the Mercury and Air Toxics Standard (MATS). EPA sent letters inviti ng all tribes in Arizona to consult with EPA on NGS in conjunction with the InterTriba l Council of Arizona on September 16, 2011. 124 Meeting

materials associated with consultation m eetings on September 16, 2011, February 8, 2012, and two meetings in August 2012, are available in the docket for this proposed rulemaking. 125 EPA received additional comment letters from the Yavapai-Apache Nation 126 and the Ak-Chin Indian Community. 127

D. EPA Conclusions regarding This Factor

i. Energy and Non-Air Quality Environmental Impacts

In its cost analysis for SCR, SRP include d the cost of auxiliary power for the SCR system; therefore EPA did not further consider en ergy efficiency losses as a result of SCR, as those effects were quantified in the cost analysis.

The cost analysis submitted by SRP for SCR at NGS assumes costs associated with the use of aqueous anhydrous ammonia, and several co mmenters raised concerns about the potential risks from the transportation and storage of th is chemical. In addition to concerns about anhydrous ammonia itself, because NGS is not located next to a major rail line, commenters also

raised concerns that ammonia deliveries would increase heavy-duty truck traffic to and from NGS. Although this factor deal s specifically with energy an d non-air quality environmental impacts, EPA determined that the potential ad verse health impacts of the transportation and storage of anhydrous ammonia at NGS warranted further review.

Commenters estimated that if SCR were requi red, two additional trucks daily would be required to transport the anhydrous ammonia fr om Flagstaff to NGS (approximately 135 miles each way). EC/R estimated emissions from the add itional truck trips (728 trucks per year each traveling 270 miles round trip). EC/R used conservative emission factors from the South Coast Air Quality Management District. 128 The modeled concentrations of criteria pollutants were compared against the National Ambient Air Quality Standard (NAAQS), and modeled concentrations of hazardous air pollutants were used to estimate cancer risks and a non-cancer hazard quotient for comparison against background. Of the criteria pollutants, emissions of NO

x were highest but totaled only 3.76 tons per ye ar, which was modeled to be well below the NAAQS and the Class I increments at the mo st impacted census block, located in Coconino County, Arizona, with a population of 109 individuals . The modeled impact of the sum of all hazardous air pollutants in the hi ghest impacted census block in Coconino County was estimated

to result in a cancer risk of 0.7 excess cance r cases over a lifetime exposure per one million people exposed (7 x 10 -7 risk), and a non-hazard quotient of 0.2, where a quotient of one or

124 Letters dated September 6, 2011 from Jared Blumenfeld, EPA, to Arizona tribal leaders, in the docket for this proposed rulemaking.

125 See document file sets titled “EPA Consultation with Tribes , 9-6-11”,“EPA Consultation with Tribes, 2-8-12”, and “EPA consultation with Tribes in August 2012” in the docket for this proposed rulemaking.

126 Letter dated September 21, 2011 from David Kwail, Chairman , Yavapai-Apache Nation, to Laura Yoshii, EPA; in the docket for this proposed rulemaking.

127 Letter dated October 14, 2011 from Louis Manuel, Jr., Chairman, Ak-Chin Indian Community to Janet McCabe, EPA; in the docket for this proposed rulemaking.

128 See report from EC/R Incorporated titled: “Ammonia Mobile Source Risk Estimates for Navajo Generating Station.pdf” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 60 of 129 below indicates exposure is not likely to result in adverse health effects. The background cancer risk for Coconino County is 15 excess cancer cases over a lifetime exposure per one million people exposed. For the other impacted census blocks, the modeled risks associated with

increased truck traffic were estim ated to be as low as 2 x 10 -10 and the hazard quotients are

estimated to be as low as 0.00007. Based on the info rmation that the increase in risks associated with transportation emissions in the most impacted census block are well below background,

EPA has determined that the increase in dail y tanker truck traffic to transport anhydrous

ammonia to and from NGS for SCR will not result in a significant health risk.

Based on estimates from SRP that installa tion of SNCR on Units 1 – 3 at NGS would require nearly 31,000 tons per year of urea, and as suming each truck can carry nearly 20 tons of urea, roughly 4 trucks per day might be require d to transport dry urea to NGS (1,580 truckloads per year) if SNCR was inst alled and operated at NGS. 129 Using a similar analysis as was conducted for SCR, emissions of NO

x were projected to be highest of the criteria pollutants, totaling over 8 tons per year, and was modele d to be well below the NAAQS and Class I increments at the most impacted census block. The modeled impacts of SNCR are expected to be greater than the modeled impacts of SCR because SNCR is requires twice th e daily truck trips as SCR. The modeled impact of the sum of all hazardous air pollutants in the highest impacted census block in Coconino County, with a population of 230 individuals, wa s estimated to result

in a cancer risk of 1 excess cancer cases over a lifetime exposure per one million people exposed (1 x 10 -6 risk), and a non-hazard quotient of 0.47, wh ere a quotient of one or below indicates exposure is not likely to result in adverse he alth effects. The background cancer risk for Coconino County is roughly 9 excess cancer cases over a lifetime exposure per one million people exposed (8.8 x 10 -6 risk). Based on the information that the increase in risks associated with transportation emissions in the most impacted census block are well below background, EPA has determined that the increase in daily tank er truck traffic to transport urea to and from

NGS for SNCR will not result in a significant health risk.

Commenters additionally cite d concerns about the tran sport and use of anhydrous ammonia, and in its comments on the ANPRM, SRP stated that it would be required to develop, implement, and maintain and Risk Management Plan (RMP) and Process Safety Management Plan for storage and transport of this chemical . The report from EC/R Incorporated included in the docket for this rulemaking includes a qualita tive assessment of risks from the transport and storage of anhydrous ammonia. As discussed in the report , ammonia is widely used in the United States for a variety of purposes, including in agricultural and industrial systems. Anhydrous ammonia is a health hazard if inhaled, and e ffects can range from lung irritation to severe respiratory injuries, with possible fatality at higher concentrations. Th ere are several federal regulations that require the repor ting of the use and release of hazardous materials. The programs administered by EPA include: Section 112(r) of th e Clean Air Act, the Emergency Planning and Community Right-to-Know Act (EPCRA), and the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA). The RMP cited by SRP is required under Section 112(r) of the CAA. The RMP requirements apply only to stationary sources, therefore the transportation of anhydrous ammonia does not fa ll under an RMP. The U.S. Department of Transportation (DOT) regulates the transporta tion of anhydrous ammonia under Federal Motor Carrier Safety Administration (FMCSA) re gulations. Using an FMCSA-supported risk assessment estimating an annual accident and in cident rate for hazar dous materials, EC/R

estimated that based on the estimated tanker truc k miles traveled, one accident or incident in

129 Ibid.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 61 of 129 approximately 30 years involving a laden tanker tr uck might be expected. According to figures from the FMCSA risk assessment, only 28% of su ch accidents would be expected to involve a spill. Given that the vast majority of the rout e from Flagstaff to NGS passes through a sparsely populated area, the likelihood of injury to the populace from an accident is small.

The EC/R report further notes that a national database operated by the National Toxic Substance Incidents Program of the U.S. Agency for Toxic Substances and Disease Registry reports that between 2005 – 2010, there were 45 incidents involving anhydrous ammonia, and that all incidents were associated with agricultura l use of the chemical, and that the vast majority

of those incidents were associat ed with loading operations or soil applications, rather than transport on highways or public areas. There were no incidents invol ving anhydrous ammonia use at a power plant or transportation to a power plant between 2005 and 2010. EPA further notes that SCR is a widely used control techno logy at coal and natural gas-fired power plants throughout the country and that SR P might confer with Tucson Electric Power (TEP), one of the co-owners of NGS, in developing an RMP for anhydrous ammonia. TEP has a title V operating permit for Springerville Generating Station in Arizona that describe s new anhydrous ammonia storage tanks, therefore TEP likely has already developed an RMP for anhydrous ammonia for the Springerville. 130

EPA agrees with CDPHE and NPS that NO

x reductions from NGS may have co-benefits for tropospheric ozone and nitr ogen deposition. We have de termined that a qualitative acknowledgement of the co-benefit for ozone and nitrogen depositi on is sufficient consideration for this factor. The BART gui delines generally focus on adve rse environmental impacts of control technologies, such as so lid or hazardous waste generati on or discharges of polluted water, however, the guidelines fu rther state that “any important relative environmental impacts (both positive and negative) of alternatives can be compared with each other”. 131 As the most stringent NO

x control option, SCR is expected to result in the highest leve l of co-benefit for reducing ozone and nitrogen deposition.

EPA did not receive comments that specifically raised concerns regarding the impact of SCR on fly ash salability at NGS. This issue, however, was raised in the context of EPA’s BART evaluation for FCPP. For our proposed BART rule making for FCPP, EPA contracted with EC/R to explore the impact of ammonia on the usab ility of fly ash. This report from EC/R was included as Appendix C 132 of the technical support documen t for our October 19, 2010 proposed BART determination for FCPP. Ammonia adsorption to fly ash is generally less desirable due to odor but does not impact the integr ity of the use of fly ash in concrete. However, EC/R noted

that other NO

x control technologies, including LNB, also have undesirable impacts on fly ash.

LNBs increase the amount of unburned carbon in the fly ash, also known as Loss of Ignition (LOI), which does affect the inte grity of the concrete. However, commercial-scale technologies exist to remove ammonia and LOI from fly ash. Therefore, EPA has determined that the impact of SCR on the fly ash at NGS is smaller than the impact of LNB on the fly ash, and in both cases, the impact can be mitigated.

ii. Economic Impacts of Compliance

130 See document titled “Springerville title V permit ADEQ” in the docket for this proposed rulemaking.

131 See 70 FR 39169 (July 6, 2005).

132 See document titled “TSD Appendix C: Impact of Ammonia in Fly Ash on its Beneficial Use”; Document number 0006, in the docket for the proposed rulemaking for Four Corners Power Plant: EPA-R09-OAR-2010-0683.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 62 of 129 The BART Guidelines state that under th e energy impacts analysis, the reviewing authority may consider “whether a given al ternative would result in significant economic disruption or unemployment.” 70 FR at 39169. Additiona lly, in selecting a “best” alternative, the BART Guidelines further state that “there may be unusual circumstances that justify taking into

consideration the conditions of the plant and the economic effect s of requiring th e use of a given control technology.” 70 FR at 39171. Although the econom ic effects are discussed in the context of selecting the “best” control technology rather than as a consideration under the energy impacts analysis, EPA is including a discussion of an af fordability analysis in the Energy and Non-air quality impacts of compliance factor, as it relates to potential economic disruption.

In addition to the ICF Report commissioned by the Hopi Tribe, EPA received studies from other groups as well. DOI, SRP, and th e Gila River Indian Community commissioned separate studies to examine the impacts of poten tial BART controls on electricity rates, CAP water rates, and the Gila River Indian Co mmunity. The NREL phase I study commissioned by DOI, as discussed previously, examined potential impacts of three main scenarios, (1) SCR installation at NGS for BART, (2 ) SCR installation for BART plus installation of baghouses in the event baghouses are needed at NGS to comply with other non-BART regulatory requirements, and (3) full closure of NGS, on se veral groups of stakehol ders, including owners of NGS and their retail customers, CAWCD and their water customers, and Tribes. The Harvey Economics reports commissioned by the Gila Ri ver Indian Community and SRP focused on CAP water rates and potential impacts to profit margins for agriculture on the Gila River Indian Community in particular, as well as other agricu ltural and non-agricultural impacts to tribes

located in Arizona and the Lower Colorado River Basin Development Fund. Finally, SRP commissioned a study by Arizona State University to examine the broader contributions of NGS and the Kayenta Mine to the economy of Arizona.

Throughout the following section, EPA descri bes results from these studies as a comparison with our analyses. Although EPA is including the ICF, NREL, Harvey Economics, and ASU studies in the docket for our propos ed rulemaking as additional and supplemental information submitted by interested stakeholders , EPA is not providing a critical review or assessment of the methodologies of those studies.

a. Projected Impacts on Electricity Generation Costs and Retail Rates

EPA contracted with EC/R Incorporated to explore the concerns raised by the Navajo Nation regarding the affordability of SCR. Sp ecifically, EPA requested EC/R to conduct an analysis to estimate the increase in cost to produ ce electricity if SCR were required for BART, to assess the factors that impact a de cision to shut down NGS, and to estimate potential increases to electricity and water rates under possible options for BART. EC/R c ontracted with Energy Strategies, LLC to conduct the analysis.

Energy Strategies, LLC (ES) created a model to estimate the cost of electricity generation

if new controls were installe d on all 3 units at NGS compared with the cost to purchase electricity on the wholesale market, to determin e whether it would be more economical for the

owners of NGS to install new controls and cont inue operation, or to close NGS and purchase power on the wholesale market as part of their contractual obli gations to retail electricity customers. The model and the final report from ES are available in the online docket for thisTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 63 of 129 proposal. 133 The model is a 25-year discounted cash flow model that estimates the net present value (NPV) cost of electricity. ES estimated the current Business As Usual (BAU) cost to produce electricity and modeled the cost to add SNCR or SCR to all 3 units. Because SRP

elected to install LNB/SOFA on each unit at NGS over 2009 – 2011, the BAU case includes the cost of those retrofits. The BAU, SCR, and SN CR cases also include an estimated increase of $15 million per year in the lease costs paid by the owners of NGS to the Navajo Nation. 134 ES forecasted the market price to purchase energy on the wholesale market using the Palo Verde price index, which is determined by the most costly source of electricity, in this case, natural gas. Additionally, ES estimated the non- discounted cost of electricity per MWh, which we report here in kWh for consistency with our ANPRM. The model uses EPA’s revisions to SRP’s capital cost and operating expense estimates for SCR (S ee Table 13, total capital cost = $496 million to install SCR on all 3 units). For SNCR, the model uses those reported by SRP. The model uses an amortization rate of 15%, which includes the interest rate and the tax rate on the debt and equity of the project. Thus, the m odel used for the affordability analysis differs from the EPA Control

Cost Manual in that the Cost Manual determines the am ortization rate on a pre-tax basis, using only the interest rate and amor tization period. The results of th e model are shown in Table 18.

LADWP is a publicly-owned u tility that currently owns 21.2% of NGS. As discussed previously, because of state law in California, LADWP will be prohibited from continuing to participate in NGS after 2019. At this time, the EPA understands that LADWP is seeking to sell its ownership share of NGS. Because assumptions re lated to capital recovery for investor-owned utilities (e.g., Arizona Public Service) differ from publicly-own ed utilities (e.g., Salt River Project), the total cost of controls will di ffer depending on whether LADWP’s share of NGS is purchased by an investor-owned utility or a publicly-owned utility. The affordability analysis included in the docket for this proposed rulemaki ng models both scenarios for future ownership

of LADWP’s share and s hows that the cost of new controls is higher if LA DWP’s share is purchased by an investor-owned utility because th e capital recovery calculation for these types of

entities includes a rate of return for investors that would not be included for publicly-owned utilities. Because LADWP is a publicly-owned uti lity, the results presented in Table 18 are based

on continuation of the status -quo (i.e., LADWP’s share of NGS is purchased by another publicly-owned utility). If the LADWP’s share of NGS is purchased by an investor-owned utility, the results of the affordability analysis sh ow different results, such that the 25-year NPV for the SCR case becomes more costly than the 25-year NPV case for the low market scenario.

Table 18: Summary of Cost after Installing SNCR and SCR versus Mark et Trends if Compliance with BART by 2018

SNCR SCR Market Low Market Mid Market High

Increase in 25- year Net Present

Value from BAU ($ millions) $255 $648 $673 $951 $1,040

133 See Energy Strategies report: “Affordability Analysis fo r NGS BART Options.pdf”, and three excel spreadsheets titled “Model – NGS BART Affordability Analysis 01 -16-13”, “M&I User Consolidated wate r cost impact analysis”, and “NIA – water use and supply projections”.

134 The owners of NGS and the Navajo Nation are currently in negotiation to renew the site lease for NGS. When the site

lease for Four Corners Power Plant was rene wed, the lease cost increased by roughly $7 million per year. Although it is not yet known how much the lease costs for NG S will increase, we expect they will incr ease, and conservatively modeled in the affordability analysis an increase that is roughly double the increase for Four Corners Power Plant. If actual lease costs increase by a smaller amount than $15 million per year, the difference between the SCR and low market cases would be larger than as shown in Table 18.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 64 of 129 The analysis shows the retrof it of all 3 units at NGS w ith SCR would result in an

incremental increase over the bus iness as usual (BAU) scenario of $648 million, which is lower

than the increase over BAU of the cost to purchase the equivalent amount of el ectricity on the wholesale market considering the low, mid, and high market trends ($673 – $1,040 million), 135
suggesting that on a 25-year Net Present Value basis, although SCR will increase the cost of electricity generation, it is not li kely to force NGS to shut down because the total cost to produce electricity at NGS, if retrofit with SCR on Un its 1 – 3, should not exceed the total cost to purchase electricity on the wholesale market.

EPA expects that increases in electricity gene ration costs will be passed onto the utility’s customers. Retail consumers of power pay more than just the generation costs of power (i.e.,

transmission and distribution cost s), however, for SRP customers, for example, the cost increase from installing SCR at NGS would flow into a broader rate impact calculation based on the entire portfolio of SRP genera tion assets and power purchase contracts, which include coal, natural gas, nuclear, and some renewable energy. Therefore, the electricity generation cost

increase for SRP from SCR installation of 0.46 cen ts per kWh at NGS (a 14% increase compared to BAU), which is only one of SRP’s sources of power, does not result in a commensurate 14%

increase in rates to its retail customers.

Because SRP owns the largest utility share of NGS, the affordability analysis includes

estimated effects of SCR insta llation at NGS on SRP rate payers using public information for

SRP. 136,137 As discussed in the report from Energy Stra tegies, the cost impact of SCR is highest the year installation is complete on all units and declines over time as the investment is depreciated to a point below the average. At the re tail level, ES believes that it is unlikely for a utility to seek cost recovery based on the aver age cost increase; rather , utilities would likely characterize the rate impact to its ratepayers by focusing on the highest cost year. ES estimates that the highest cost year to be 2018 – the year when EPA expects installation of new controls on

all three units would be completed under BART.

Table 19: Increase in Electric ity Generation Costs in 2018

NGS Owner Business As Usual (BAU)

Electricity

Generation Cost Electricity

Generation Cost

with SNCR Percent Increase Compared to

BAU for SNCR Electricity

Generation Cost

with SCR Percent Increase Compared to

BAU for SCR

Reclamation 3.27 cents/kWh 3.43 cents/kWh 5% 3.73 cents/kWh 14% Publicly-Owned Utilities (SRP,

LADWP) 3.49 cents/kWh 3.66 cents/kWh 5% 3.97 cents/kWh 14%

Investor-Owned Utilities (APS, TEP, NPC) 3.88 cents/kWh 4.06 cents/kWh 5% 4.61 cents/kWh 19%

Average Total Plant 3.56 cents/kWh 3.74 cents/kWh 5% 4.12 cents/kWh 16%

135 See Energy Strategies report titled “Affordability Analysis of BART Options for NGS.pdf” and spreadsheet titled “NGS Affordability Analysis Model.xlsx” in the docket for this proposed rulemaking.

136 See “Impact Analysis of Proposed EPA BART Determination on NGS.xls”, Rate Impact Estimates worksheet in docket for this proposal.

137 The largest share of NGS is owned by a non-utility, Bureau of Reclamation, for the benefit of the Central Arizona Project.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 65 of 129 ES used the 2009 FERC F1 filings that report the 2009 total retail sales (in kWh) and 2009 total retail revenues ($) to get an average retail rate ove r 2009. This methodology involves numerous conservative simplifying assumptions to estimate the affect of new controls on retail rates. Revenues, in nominal dollars, and sale s (in kWh) from 2009 were estimated for 2018 (the expected completion date for th e installation of new controls on all 3 units) by applying a 1.5% escalation factor each year from 2009 – 2017. This escalation factor is c onservative and within the range of historical increases. This calculation also assumes that 100% of the increase in cost from new controls is passed onto retail customer s, and does not include changes in ownership, or life-extending capital investment, or other environmental regulations.

The increase in generation costs resulting fr om new controls, using the 2018 increase in generation costs, is multiplied by the utility's sh are of NGS's electricity generation (in kWh) to

calculate SRP’s share of the increase in cost result ing from new controls. This cost is added to the 2009 retail revenues (escalat ed to 2018 by 1.5% annually) a nd then divided by estimated retail sales (kWh) based on 2009 sales (escalated to 2018 by 1.5% annually). This results in the estimated retail rate with installation and opera tion of SCR and SNCR. The increase in the retail rate is then estimated by subtracting the estima ted retail rate without new controls from the

estimated rate with new controls . Using this methodology, ES estimates that the incr ease in retail rates to SRP rate payers from the insta llation and operation of SCR will be $0.0006/kWh (0.06 cents per kilowatt-hour), a 0.65% increase in the average 2009 estimated retail rate. This is comparable to the retail rate increase proj ected by NREL for SRP customers of 0.5 – 0.6%. 138

The NREL report states that even with rate increases resulting from SCR, NGS would still be one of the lowest cost generators in the Desert Southwest. The NREL study and the ES study both suggest that installing SCR (or SNCR) at NGS would likely cost less than shutting down NGS and replacing it with powe r from elsewhere in the West.

b. Projected Impacts on Water Rates in Arizona

In addition to impacts on electricity customer s that purchase power from the owners of NGS, numerous parties submitted comments on th e ANPRM that raised concerns about the potential impact to water cu stomers of the Central Arizon a Water Conservation District (CAWCD). As part of our analysis, ES evaluated the potential increases in water costs to various CAP customers. EPA expects that costs associ ated with Reclamation’s share of capital improvements at NGS are passed onto CAP custom ers in the variable OM&R costs, i.e., “pumping energy rate”. Based on advisory rate s (generated in 2011), CAWCD estimates the pumping energy rate to be $58 per acre-foot ($58/AF) in 2016. In 2016, the fixed OM&R cost (delivery charge) is estimated to be $83 /AF, thus M unicipal and Industrial (M&I) CAP customers are estimated to pay at least $141 /AF for water ($58 + $83/AF), whereas non-Indian agricultural (NIA) us ers and Indian water users are estim ated to pay only $58/AF (the pumping energy rate). 139

Based on an analysis similar to the one used to estimate potential elect ricity rate increases to SRP customers, ES estimated that the increased electricity generation cost at NGS from the

138 See Table 1-12 on page 19 of the NREL report.

139 EPA understands that NIA users pay only the pumping cost of energy per in exchange for limited use of CAP water that will decline to zero over time. See Addendum to Energy Stra tegies report titled “Economic Analysis of CAP Water Rates”

and references therein in the dock et for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 66 of 129 installation of SCR on a ll three units may result in an pumping energy rate increase of $8.40/AF (in 2018, the highest impact year). Assuming that water rates in 2018 will not increase from 2016 advisory rates , an increase of $8.40/AF represents an estimated 6% increase in the CAP water rate paid by M&I users, and a 14.5% increase in the CAP water rate pa id by NIA and Indian water users, who only pay the pumping energy rate. The actual impact in terms of total water costs to individual CAP customers will depend on whether the customer uses exclusively CAP water, or if it uses CAP water in addition to wa ter from other sources, su ch as other sources of surface water, groundwater, or recl aimed water. Estimated impacts to various classes of water customers (NIA and M&I) are disc ussed in more detail below.

For comparison, in its report, NREL estimated a range of potential water cost increases

based on SCR cost estimates from National Park Service (“low SCR rate”) and from the S&L report for SRP (“high SCR rate”). We report the hi gh SCR rate cost increas es in Table 20 below. The increases in water costs calculated by NREL based on the high SCR cost estimates are slightly higher than EPA’s estimates. A separate analysis for the Gila River Indian Community by Harvey Economics (this analysis is discussed in more detail below) estimated pumping cost

increases that are lower than both NREL and EPA estimates.

Table 20: Estimated Pumping Cost Increase from SCR
NREL High EPA NREL Low Harvey
Pumping Cost Increase $8.58 / AF $8.40 / AF $7.10 / AF $6.60 / AF

% Increase in Water Rates

to M&I 7% 6% 6% Not calculated

% Increase in Water Rates for Tribes and Agriculture 16% 14% 13% 11%

Table 20 shows that our projec ted increase in pumping energy rates for CAP water is similar, but slightly lower than that projecte d by NREL for the high SCR rate. The increase in CAP water pumping costs projected by Harvey Ec onomics is considerably lower than the rate increases projected by EPA and NREL.

c. Sensitivity to Other Uncertainties

As the Navajo Nation, Hopi Tribe, and ot her commenters discussed in their comment letters on the ANPRM, other factor s would affect whether the pl ant owners choose to retire NGS, including lease negotiations, future regul ations targeting gr eenhouse gas emissions, mercury and HCl emissions (Mercury and Air Toxics Standards - MATS), and ash handling (coal combustion residues).

There is considerable uncertainty related to potential future gr eenhouse gas regulations and the effect on the remaining owners of NGS when LADWP divests its ownership interest in NGS possible as early as 2015. 140 ES describes three types of risk, (regulatory, economic, and market), that each owner must consider when de termining whether investment in SCR meets the needs of their stakeholders (rat e payers, regulators, owner boards, and shareholders). Because of

140 See, for example, article available at: http://www.power-eng.com/articles/2013/january/ladwp-may-sell-share-in-coalfired-power-plant-switch-another-to-natural-gas.htmlTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 67 of 129 the uncertainty associated with these upcoming regulations and the complexity in determining the appropriate level of risk for each owner, EP A has determined that our BART determination cannot give a significant amount of weight on conjectures regardi ng the future decisions of NGS owners. In the absence of compelling evidence of cl osure in the near future resulting from one or more regulatory factors, EPA is relying on the resu lts of our analysis that shows that based on the 25-year NPV, SCR or SNCR will not cause the co st of electricity generation to exceed the

wholesale market cost of electr icity. EPA understands and is sensit ive to the important role NGS plays in the economies of the Navajo Nation and Hopi Tribe. As long as NGS continues to burn coal from the Kayenta Mine to produce electric ity, royalties, taxes, lease payments, and other

sources of revenue associated with NGS should c ontinue for the Navajo Nation and Hopi Tribe. Because our analysis suggests that SCR or SNCR should not force electricity production costs to be uneconomical compared to market costs of power, EPA does not expect adverse impacts to the Navajo Nation and Hopi Tribe from a ny of the BART options (SCR, SNCR, and LNB/SOFA) under consideration.

EPA finalized the MATS rule in December 2011, setting emission limits for mercury and filterable PM, among other pollutants. The final rule was published in the Federal Register on February 16, 2012 (77 FR 9304) and is effectiv e on April 16, 2012. Units 1 – 3 at NGS generally already meet the filterable PM limit of 0.03 lb/MMBtu. The merc ury limit set in the final HAPS

rule for coal-fired units not bur ning low-rank virgin coal is 1.2 pounds per trillion Btu (lb/TBtu).

EPA estimated baseline HAP emissions for NGS to be roughly 1.25 lb/TBtu. 141 SRP indicated to EPA that it has tested the use of calcium bromide in combination with the existing wet scrubbers for mercury control to determin e if NGS, and other similar units owned by SRP, could comply with the mercury standard without the installa tion of new baghouses. SRP has stated that it is “cautiously optimistic” that baghouses will not be needed at NGS because the reaction between mercury and calcium bromide and their subse quent capture in the wet scrubber should be sufficient to meet the mercury limit in MATS. SR P has indicated that they have observed some re-emission of mercury following ca pture by the wet scrubber, but that they are working through this issue and plan to coordinate with EPA, as a ppropriate, to implement tec hniques that will lead to permanent capture of mercury by the wet scru bber. The compliance date for MATS is April 16, 2015, but EPA is encouraging state and local perm itting authorities to make widely available, at their discretion, an additional year for compliance (i.e., compliance by April 16, 2016). For completeness, EPA included baghouse costs in our affordability analysis, and determined that, on a 25-year Net Present Value basis, the electri city generation costs after installing SCR and baghouses on all three units at NGS may ex ceed the wholesale market cost of power. 142
However, based on the information provided by SRP on calcium bromide injection, EPA is preliminarily concluding that the comparison of electricity generation costs for SCR against

market costs should not include the cost of ba ghouses, whether for MATS compliance, or for a future PSD permit (as discussed in Section 3.0 Costs of Compliance).

EPA notes that many of the uncertainties (see Table 21) facing NGS that will impact the decision between investing in new air pollution controls and closure, including, on-going lease and right-of-way negotiations with the Navajo Nation and the renewa l of the coal contract with

141 See spreadsheet titled “mats_final_current_baseline_hap_invent ory.xlsx” from the final MATS rulemaking, also included in the docket for this proposed rule.

142 See report from Energy Strategies titled “Economic Analysis of Proposed EPA BART Determination” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 68 of 129 Peabody Energy, are unrelated to EPA and are within the control of many of the stakeholders

that stand to benefit most from continued operation of NGS.

Table 21: Lease, Permit and Contract Rene wals Required for NGS or Kayenta Mine
Description Renewal Year or Comments

Water Service Contract 2014

Coal Supply Contract between Peabody and NGS Currently under renegotiation

Peabody Lease Renewal with Nava jo Nation and Hopi Tribe 2017

NGS Project Lease Renewal with Navajo Nation (Federal Rights of Way) 2019

Water Intake/Water Line Renewa l (Federal Rights of Way) 2019

Railroad and Transmission Line Renewa ls (Federal Rights of Way) 2021

Southern Transmission Line Easement (Federal Rights of Way) 2022

Mining Permit 2024/25

Mining Plan Approval 2024/25

Permit for small parcel for water intake from Lake Powell 2032

Energy Strategies explored the sensitivity of the affordability analysis to future changes in wholesale market prices, lease costs, and coal prices. As discussed in more detail in the report included in the docket for this proposed rule making, the comparison between 25-year NPV for electricity generation under the BAU, SNCR, an d SCR installation cases are compared against purchasing an equivalent amount of electricity on the wholesale market. Thus, the 25-year NPV market prices are sensitive to the market price forecast. In turn, the market price forecast is sensitive to the price of natural gas. The affo rdability modeling results (as shown in Table 18 and Table 19) are based on a market price forecast th at uses the average natural gas price over 2012 (as of November 27, 2012). As discussed in more detail in the Energy Stra tegies report, a 10% reduction in natural gas price is expected to ma ke the 25-year NPV for SC R more expensive than the low market case, and a 20% increase in the ma rket price would result in the 25-year NPV for the low market case that is 13% higher than the 25-year NPV for the low market case. These results indicate that the affordability analysis is highly influenced by changes in the market prices forecast.

The affordability analysis was conducted with the understanding that the owners of NGS and the Navajo Nation were undergoing negotiations to renew the site lease for NGS. As noted in the Energy Strategies report, renewal of the lease for the F our Corners Power Plant, also on the Navajo Nation, resulted in an increase of roughly $7 million per year. Energy Strategies elected to conservatively assume that the le ase costs for NGS will in crease by $15 million per year in 2020 (the year following lease expira tion in 2019), affecting the BAU, SNCR, and SCR cases (as shown in Table 18 and Table 19). The sensit ivity analysis showed that if site lease costs increased by only $5 million, the 25-year NPV fo r BAU and SCR cases both decrease slightly, 143

Finally, the Energy Strategies report also examin ed sensitivity of the affordability results to the cost of coal (fuel costs). Changes in th e cost of fuel are exp ected to affect operating expenses for the BAU and control technology cas es (i.e., SNCR and SCR). The results suggest

that a 20% reduction in the fuel costs would ma ke SCR much less costly than the low market

143 For comparison, when the lease for th e Four Corners Power Plant was renewed by the Navajo Nation in 2011, lease payments increased by $7 million per year.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 69 of 129 case. A 20% increase in fuel costs would cause the 25-year NPV for the low market case to be lower than the 25-year NPV for SCR installation.

The ICF Report commissioned by the Hopi Tribe in 2010 used ICF’s IPM model to

examine whether a combination of several stringent environm ental requirements would make continued operation of NGS uneconomical. Simila r to EPA’s analysis comparing the cost of electricity generation against the cost to pur chase an equivalent amount of power on the wholesale market, the ICF study examined cost s associated with potential environmental regulations against the price of natural gas, however, the ICF study assumed stringent requirements to control mercury under MATS and incorporated assumptions for a cap and trade program for CO 2 . As there are no plans in place to deve lop a national, market-based program to reduce greenhouse gas emissions, it would be too speculative to add a price for CO 2 allowances into this analysis. Additionally, as stated previously, SRP, the ope rator and co-owner of NGS, is “cautiously optimistic” that baghouses will not be needed at NGS to comply with MATS, therefore, EPA only evaluated baghouses as a sensitivity analysis for our study. The ICF study assumed capital cost of SCR to be $663 million a nd baghouses and an activated carbon injection system to comply with MATS to be $450 million. The study further assumed stringent requirements for a CO 2 trading program with a CO 2 allowance price of $102 per ton. Based on these assumptions, the ICF study suggested that if average natural gas prices over the remaining life of NGS were at or below $5.60 per MMBtu, continued operation of NGS would not be economical. The results from the ICF study cannot di rectly be compared ag ainst the results of EPA’s analysis, however, both studies do suggest that natural gas pric es are an important variable, and that SCR in combination with additional capital investments may affect the economics of continued operation comp ared to the wholesale market.

d. Potential Impacts to Tribes Located in Arizona

As discussed previously, CAWCD operates, ma intains, and is responsible for repayment

to the Federal Government for the Central Arizona Project (CAP). Reclamation’s 24.3% ownership share (approximately 4.3 Terawatt-hours, 144 or TWh) in power produced by NGS is used by CAP to pump surface water from the Colorado River to municipal, industrial, agricultural, and tribal water users in Arizona. CAP uses about 2.8 TWh of NGS power (92% of CAP’s power needs) per year. Excess power owne d by Reclamation that is not used by CAP (about 1.5 TWh) is sold and profits are depos ited into the Lower Colorado River Basin Development Fund (Development Fund). This fund was originally authorized under the Colorado River Basin Act of 1968 for the purpose of repaying the federal government for the cost to build CAP, and subsequent settlement acts with several tribes located in Arizona authorized use of the fund to pay the delivery portion of the cost of CAP water (fixed OM&R costs) for certain Indian Tribes, and to pay the costs to construct the delivery systems to bring

CAP water to certain Indian Tribes. Reclam ation, CAWCD, and several Tribes submitted detailed comments on the ANPR to EPA outlining the potential effects that requiring SCR as BART for NGS might have on the cost water and Indian water settlement agreements. EPA’s understanding of the relationship between NGS, R eclamation, NGS, CAP, and tribes is shown in Figure 2.

144 1 Terawatt = 10 12 Watts, or 10 6 Megawatts.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 70 of 129 Figure 2: EPA’s Understanding of the Relationshi p Between Reclamation, NGS, CAP, and Tribes

Tribal Water Customers

As Tribes use more of their CAP allocations,

NIA water use will

decrease and eventually go to zero CAWCD Annual Repayment Obligation: ~$55 million per year Additional Revenues credited to CAWCD’s annual repayment obligation: Hoover Dam and Parker Davis Surcharge ($4.25 million per year); NGS O&M revenues, sale of SO 2 credits, CAP Land ($2 million per year)

Arizona Water Settlement Act (2004)

$55 million per year (1 st cascade) Any $ in Excess of ~$55

million ( 2 nd cascade )

Tribes in Arizona with CAP Water Allocations or Using CAP Water

Tribe Allocation Gila River 311,800 AF/y Ak-Chin 85,000 Tohono O’odham 74,000 San Carlos Apache 60,665 White Mountain Apache 23,782 Fort McDowell 18,233 Salt River Pima-Maricopa 13,300 Navajo Nation 6,411 Yavapai-Apache Nation 1,200 Hopi Tribe 1,000 Pascua Yaqui 500 Yavapai-Apache Nation 500 Tonto Apache Nation 128 Bureau of Reclamation

24.3 % Ownership Share

(~ 547 MW) in Navajo

Generating Station Central Arizona Project (CAP) to use Arizona’s 2.8 million AF entitlement of the Colorado River. CAP is operated by the Central Arizona Water Conservation District (CAWCD). Colorado River Basin Project Act (1968) authorized:

~ 2.8 million MWh

per year, sold at production cost, to

pump water

Surplus NGS Power Sales (1.6 million MWh). As of Oct 2011, SRP buys select on-peak power for $25 million + production costs in 20 year contract.

WAPA markets the remaining power. Total gets credited to CAWCD’s annual repayment obligation. Municipal and Industrial (M&I)

Water Customers

Non-Indian Agricultural Customers (NIA)

First Cascade

1. Fixed OM&R costs for Tribal Water

Deliveries

2. Gila River OM&R Trust Fund (Aggregate $53 million)

3. GRIC San Carlos Irrigation Project Rehabilitation ($147 million)

4. New Mexico Unit ($66 million total)

5. Distribution Systems (GRIC, San Carlos Apache, Tohono O’odham, Yavapai Apache, Pasqua Yaqui, Tonto Apache)

6. Future Indian Water Settlement Subaccount ($250 million total)

Lower Colorado River Basin Deve lopment Fund (Dev elopment Fund)

Second Cascade

1. Fixed OM&R costs for Tribal

Water deliveries

2. Final Year’s Payment on CAP Repayment Obligation

3. Payment to US Treasury to

reimburse Fixed OM&R Costs for

Tribal Water deliveries and Indian Water Rights settlement costs

4. Payment to US Treasury toreimburse 9(d) debt made nonreimburseable under AWSA Apache)

5. US Treasury General FundTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 71 of 129 Prior to October 1, 2011, excess Reclamati on power not used by CAP (about 1.5 TWh) was sold to SRP under a series of long-term contracts known collectivel y as the Four-Party Agreements. Under these contracts, in exchange for the use of the excess power, SRP deposited $21.75 million into the Development Fund each y ear. This amount was credited towards CAWCD’s annual repayment obligation to the federal government, set by an amortization schedule, of approximately $55 million per year , ending in 2044, with two additional lower payments in 2045 and 2046. Additional miscellaneous revenues to the Development Fund, for example from electricity surcharges from the Hoover Dam and Parker-Davis Dam, are also credited to CAWCD’s annual repayment obligati on. In other words, CAWCD is obligated to ensure that approximately $55 million annually is deposited into the Development Fund, however, numerous additional revenue sources ar e allowed to be credited against CAWCD’s payment obligation, so that actual CAWCD annu al payments would typically not exceed $33 million. This relationship was described in the NREL report as in a 2009 letter from CAWCD to

EPA. 145

In its 2009 letter, CAWCD describes how incr easing electricity produ ction costs if SCR were required would reduce annual revenues to the Development Fund from surplus NGS power sales. However, because surplus power sale re venues are credited against CAWCD’s repayment obligation, if those revenues decline, CAWCD must make up the difference in its annual payments to the Development Fund. Therefore, until the end of its repayment obligation (2044 – 2046), CAWCD will continue to ensure that approximately $55 million per year will be deposited into the Development Fund. CAWC D’s annual repayment obligation to the Development Fund is used to pay various prio ritized costs, including fixed OM&R costs for CAP Indian Deliveries, tribal irrigation proj ects, and tribal wate r distribution systems. 146 These priorities are known as the “fir st cascade” of priorities. EPA understands that given CAWCD’s obligation to ensure annual payments into the Development Fund of approximately $55 million, from the tribal perspective, these “first cascad e” of priorities for tribal water uses are not in jeopardy if electricity production costs rise at NGS. CAWCD, howev er, has stated that in order to make up for lower credited revenues from surplus NGS power sales, CAWCD may need to increase water service charges and/or ad valorem taxes. 147 CAWCD further states that SCR would impact potential revenues in excess of CAWCD’s annual repayment obligation, which are designated to apply to a “second cascade” of prio rities, which also includes fixed OM&R costs for CAP Indian Deliveries. EPA notes that pa yments of fixed OM&R costs for CAP Indian Deliveries are the first priority use u nder both the first and second cascades.

During a conference call between Recl amation and EPA on February 13, 2012, Reclamation explained that in the event that excess power sales generate revenues in excess of CAWCD’s annual repayment obligation, paying for fixed OM&R costs out of the second

cascade is a benefit to tribes because it offsets that amount that would have been paid under the first cascade, allowing lower prio rity tribal projects under the first cascade to receive those

145 Letter from David Modeer, CAP to Colle en McKaughan, EPA, re: “Assessment of Anticipated Visibility Improvements at Surrounding Class I Areas and Cost Effectiveness of Best Av ailable Retrofit Technology for Four Corners Power Plant and Navajo Generating Station: Advanced Notice of Proposed Rulemaking, Docket No. EPA-R09-0AR-2009-0598 - Your Letter of November 25, 2009”. December 18, 2009.

146 See presentation developed by Reclamation titled “Development Fund Power Point to EPA (2).pptx”, and “BOR Answers to EPA Questions (2).pdf” in the docket for this proposed rulemaking.

147 CAWCD has authority to levy ad valorem taxes of up to 10 cents per $100 assessed valuation of property within the District’s service area to fund administrative costs and repayment of CAP construction costs. The current ad valorem tax is set at 6 cents per $100 assessed valuation.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 72 of 129 available funds. However, the NREL report states that even if SCR were not required at NGS, the second cascade of priorities will only re ceive revenues when market power prices are substantially higher than current market prices. 148 Thus, EPA understands that the potential to generate revenues in excess of the CAWCD’s repayment obligation from surplus NGS power sales are more heavily influenced by market power prices (which are im pacted by the price of natural gas) than by additional electricity production costs associated with SCR.

CAWCD’s letter to EPA was written in 2009, prio r to the expiration of the Four-Party Agreement on September 30, 2011. Thus, EPA understa nds that CAWCD’s di scussion related to NGS surplus power sale revenues it expected in 2012 and beyond is no longer applicable. 149
Under the post-Four Party Agreement arrangement , SRP has signed a contract to receive 220,000 MWh for an annual payment of $25 million in addition to paying for the production costs of that power. The remaining surplus power will be marketed by the Western Area Power

Administration on behalf of Reclamation. The to tal revenues from surplus NGS power sales will still be credited against CAWCD’s annual repa yment obligation; howev er, these revenues are expected to be highly variable and largely dependent on the market price for power at the time of sale and NGS power production costs. 150 Therefore, under the post -October 1, 2011 agreements,
EPA understands that $25 milli on (from SRP for 220,000 MWh) is guaranteed to be credited against CAWCD’s annual repayment obligation of $55 million, and miscellaneous sources of

revenues continue to exist that will also be credited against CAWCD’s repayment obligation. Additional revenues from the remaining surplu s NGS power sales will also be credited to CAWCD, but if remaining surplus power is sold at a loss, CAWCD must cover the loss through its obligation to ensure that $55 million per year is deposited into the Development Fund. Thus, EPA understands that from the perspective of the tr ibal CAP water users, th e change in structure, since October 1, 2011, of how excess NGS power is sold, does not directly affect Tribes; however, it does affect the level of risk borne by CAWCD in te rms of how much CAWCD must pay to ensure $55 million goes to the Development Fund.

After CAWCD’s annual repayment obligation ends (in 2044 or 2046, per its amortization schedule), the guaranteed revenue of $55 million pe r year to the Development Fund ends. It is

not clear to EPA how the current revenue stream s might change if NGS continues to operate beyond 2044. If NGS closes after CAWCD’s repaymen t obligation ends (at its projected “end of useful life”) or if R eclamation’s share of NGS power is no longer available to CAWCD after 2044, CAWCD must find a new source of power (tha t will likely be more expensive if it must purchase at market rate), and substantial revenues to the Development Fund will no longer exist. Even in the absence of new control requirement s at NGS, tribes that depend on the Development Fund to subsidize the cost of water, as well as ot her users of CAP water, will be impacted at the end of NGS’s useful life, unless Reclamation or Congress creates or a pproves other sources of revenue for the Development Fund.

EPA understands that at least sixteen tribes in Arizona: (1) have water settlement agreements that allocate CAP water to the tribes in exchange for releas ing rights and claims to other surface and groundwater re sources in Arizona; (2) are in the process of negotiating CAP water settlement agreements; or (3) use CAP water through a contract (see Table 22). EPA

148 See page 58 of the NREL report.

149 See footnote 12 of the Decem ber 18, 2009 letter to EPA detailing its expecta tion that after 2012 wh en a bond indenture expires, it expects NGS surplus power sales to generate $5 0 million or more towards its $55 million annual repayment obligation.

150 See page 55 of NREL study.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 73 of 129 understands that these tribes generally each ha ve different CAP allocations and unique water settlement agreements; therefore, potential impact s may be different for each tribe and should be considered individually. In a letter from CAP to DOI and EPA, 151 in addition to the tribes listed in Table 22 below, CAP states th at several other tribes have re ached only partial settlement of water claims, or still have outsta nding or unresolved claims that may seek to rely on CAP water. CAP lists the San Carlos Apache Tribe a nd the Tohono O’odham Nation as having partial settlements, and lists the following tribes as also having unresolved water claims: Havasupai Tribe, Hualapai Tribe, Kaibab Band of Paiute In dians, Pascua Yaqui Tribe, San Juan Southern Paiute, Tonto Apache, Yavapai-Apache Nation (s ee Table 22). Various comment letters and the NREL report discuss CAP water rate s in terms of “fixed” and “var iable” OM&R costs. As stated previously, the fixed OM&R costs refer to costs associated with water distribution and delivery costs, which are typically only paid directly by municipal and industria l (M&I) users of CAP water. The variable OM&R costs refer to the cost of energy used to pump CAP water, which are typically paid by M&I users, as well as tribes and agricultural water users.

151 Letter from David V. Modeer, CAP, to David J. Hayes, DOI and Jared Blumenfeld, EPA, re: Comments on the National Renewable Energy Laboratory (NREL) Report, Navajo Generating Station and Air Visibility Regulations: Alternatives and Impacts (the “Report”), February 23, 2011 (EPA believes the letter is incorrectly dated as February 23, 2011 – EPA received the letter in 2012, furthermore the NREL report was not released until 2012).Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 74 of 129 Table 22: Summary of Tribes with CAP Allocations or Using CAP Water

Tribe Authority CAP Allocation Notes

Gila River Indian Community Arizona Water Settlement Agreement (AWSA) (2004) 311,800 AF/year 152 Development Fund pays fixed OM&R water costs. Have access to trust fund to pay variable water costs. Leasing or exchanging over 80,000 AF of

CAP water for off-reservation use 153

Ak-Chin Indian Community Ak-Chin Indian Community Water Rights Settlement Act (1984) Up to 85,000 AF/year 154 EPA believes that water infrastructure is fully

established 155

Tohono O’odham Nation AWSA (2004); Southern Arizona Water Rights Settlement Agreement (SAWRSA) (1982); 12/11/80 agreement 66,000 AF/year 156
+ 8,000 AF/year for

Sif Oidak District Development Fund pays fixed OM&R costs. Cooperative Fund pays pumping costs of water and is managed by Office of the Special Trustee.

San Carlos Apache Tribe San Carlos Apache Tribe Water Rights Settlement Act (1992) 45,556 – 60,665 AF/year 157 $41.4 million trust fund (see 25 CFR Part 183 or 66 FR 21086, April 27, 2001).
White Mountain Apache

Indian Tribe January 2009 agreement effective

December 2010 23,782 AF/year Entire allocation ha s been leased under terms of

December 2010 settlement. 158

Fort McDowell Yavapai

Nation Fort McDowell Indian Community Water Rights (1990) 18,233 AF/year 159 Leasing 4,300 AF to Phoenix and currently entering into leases for all but 250 AF
Salt River Pima-Maricopa Indian Community Salt River Pima Maricopa Indian Community Water Rights Settlement Act (1988) 13,300 AF/year Full allocation leas ed to Phoenix-area cities 160 , $47 million Economic development trust fund.

Navajo Nation No agreement yet, but allocation defined in AWSA (2004) 6,411 AF/year In 2012 Senator Kyl proposed settlement legislation, contingent on various NGS lease and coal approvals (S.2109). This legislation has not

been enacted.
Yavapai-Apache Nation (Camp Verde) Contract with DOI, no final water settlement agreement yet. 1,200 AF/year Contract dated December 11, 1980. Presently Nation is developing infrastructure to deliver CAP

water. Hopi Tribe No agreement yet 1,000 AF/year Allocation of CAP water defined in Section 206 of the 2012 legislation proposed by Senator Kyl (S.2109). This legislation has not been enacted.
Pascua Yaqui Tribe No agreement yet 500 AF/year 161 Water rights currently in adjudication
Yavapai-Prescott Tribe The Yavapai-Prescott Indian Tribe Water Rights Settlement Act of 1994 500 AF/year NREL study says this water is now “assigned to City of Scottsdale”
Tonto Apache Tribe No agreement yet 162 128 AF/year Currently not using CAP allocation
Havasupai Tribe of the Havasupai Reservation No agreement yet Unknown Cited by CAWCD as having unresolved water

claim
Hualapai Indian Tribe of the Hualapai Reservation No agreement yet Unknown Cited by CAWCD as having unresolved water

claim

Kaibab Band of Paiute

Indians of the Kaibab

Reservation No agreement yet Unknown Cited by CAWCD as having unresolved water

claim

152 Letter from William R. Rhodes, Gila River Indian Commun ity to Jared Blumenfeld, EPA, re: Gila River Indian Community’s Comments on ANPR. February 23, 2010.

153 Page 103 of NREL report and references therein.

154 Letter from Robert F. Palmquist, Strickland & Strickland, P.C. to Jared Blumenfeld, EPA, re: Comments by Ak-Chin Indian Community on ANPR. March 1, 2010.

155 From February 13, 2012 conference call between Reclamation and EPA.

156 Letter from Dr. Ned Norris, Jr., Tohono O’odham Nation to Jared Blumenfeld, EPA, re: Tohono O’odham Comments on ANPR. March 1, 2010.

157 Page 103 of NREL report and references therein.

158 Ibid.

159 Page 102 of NREL report and references therein.

160 Page 103 of NREL report and references therein.

161 Letter from Peter Yucupicio, Pascua Ya qui Tribe to Laura Yoshii, EPA, re: Pa scua Yaqui Tribe’s Comments to ANPR. December 14, 2009.

162 Page 104 of NREL report.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 75 of 129 Following the ANPR in 2009, EPA has engage d in discussions, meetings, and

consultations with several tribes in Arizona re garding NGS and water. These discussions with tribes and the additional information submitted by the tribes to EPA have been very helpful in understanding this complex issue. 163 The NREL report also provides additional information on tribal water settlement agreements.

The Gila River Indian Community (Gila Ri ver) contracted with Harvey Economics (Harvey) to identify and estimat e potential impacts to Gila River of a range of possible retrofit

scenarios at NGS. 164 Based on its analyses, Harvey estimat ed the highest impact of SCR on CAP

water costs would occur in 2020 and would increa se costs by 10.5% from the baseline scenario (pre-LNB/SOFA), a cost increase of $6.60/AF. Harvey estimated the cost increase from SCR plus baghouses ($12.85/AF increase, or 20.4%) to be nearly double the impact of SCR alone, and

estimated the water cost increase if NGS closed to be over 55% compared to baseline. In its letter to Gila River, Harvey describe s and quantifies Gila River’s various sources of water and its expectations for water delivery volumes in the futu re, areas of land devoted to agriculture and the estimated operating margins associated with agriculture over time, personal income and employment losses, and potential impacts to Gila River from re duced revenue from surplus NGS power sales.

In its report, Harvey provides information on five sources of water for the Gila River Indian Community: CAP, SRP, groundwater, reclai med water, and the Gila River. In 2011, the Gila River Indian Community us ed over 37,000 AF of CA P water, representing 17% of its total water resources in 2011. Over time, Gila River projec ts that it will increase its use of CAP water to 140,000 AF (around 2040), as well as its use of groundwater and re claimed water, such that CAP water will represent 31% of its total water res ources. The ability of Gila River to expand its

use of CAP water relies on disbursements from the Development Fund under the first cascade of priorities for Indian water infrastructure. Harvey reports that this increased use of water is projected to support growing water needs for cultiva tion of agricultural crops, in particular cotton and alfalfa (59% of total water requirements in 2050), and to a lesser extent, small grains, vegetables, and melons (15%). The remaining 26% of total water requirements was estimated to be lost during delivery and irrigation. Harvey further explains that CAP energy charges have increased an average of 4.73% pe r year over the past 15 years, which exceeds the anticipated growth rate of 3.7% for all costs used in an analysis of the Arizona Water Settlements Act (AWSA) of 2004. Thus, in the ab sence of any new controls at NGS, pumping rates for water paid by Tribes are still expected to increase annually. Harvey estimated that Gila River’s agricultural operating margins woul d decrease by 10% if LNB/SO FA and SCR were required at NGS, nearly 17% if LNB/SOFA, SCR, and baghous es were required and nearly 200% if NGS closed. Harvey further estimated revenue losse s to the Development Fund (which would only occur during periods of high market prices that result in excess power sale revenues exceeding CAWCD’s annual repayment obliga tion) and projected that exce ss power sales revenues would not exceed the annual repayment obligation unt il 2020, and would be over $5.6 million per year if SCR were required. Although Gila River is no t the only Tribe affected by this projected revenue loss, Harvey estimates that Gila River would be more impacted than any other Tribe because it has the largest CAP water allocation. Ov erall, Harvey estimated potential cumulative direct and indirect monetary losses to the Gila River Indian Community of $758 million through

163 See Timeline of all Tribal Consultation on NGS in the docket for this proposed rulemaking.

164 Letters from Edward F. Harvey, Harvey Economics, to Li nus Everling, Gila River Indian Community Law Office, re: Proposed EPA BART Changes at NGS. November 16, 2011 and updated on March 15, 2012.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 76 of 129 2044 under the LNB/SOFA plus SCR scenario. 165 EPA is not providing a critical review of the methods, assumptions, or results from the Harvey Economics study.

The Ak-Chin Indian Community (Ak-Chin) ha s the second largest CAP water allocation of 85,000 AF per year. EPA understands that Ak-C hin’s water settlement does not rely on the Development Fund and that its settlement is fully implemented. 166 EPA interprets full implementation to mean that the necessary infrastructure to allow Ak-Chin to use its full CAP entitlement has already been constructed.

In a comment letter to EPA, Dr. Ned No rris, Chairman of the Tohono O’odham Nation (Tohono O’odham), describes his concerns related to the potential impacts of new controls at

NGS. 167 Under water settlement agreements in 1982 and 2004, the Tohono O’odham have a CAP water entitlement of 66,000 AF pe r year, with an additional 8,000 AF per year allocation solely for irrigation to the Sif Oidak Di strict. Chairman Norris explains that water delivery costs (fixed OM&R) are paid for the Nation by the Development Fund, and pumping costs of water (variable OM&R) are paid by a separate fund estab lished by the 1982 and 2004 water settlement agreements called the Cooperative Fund. The C ooperative Fund is only available to the Tohono O’odham and only interest accrued in the Coopera tive Fund can be used. The NREL report states that the Cooperative Fund can also be used as back-up funding for fixed OM&R costs. This fund is managed by the Office of the Special Trustee w ithin the Department of the Interior. If funds are no longer available in the Development Fund fo r fixed OM&R costs, and if interest accrued in the Cooperative Fund is not sufficient to fi nance costs of both va riable and fixed OM&R costs, the Tohono O’odham Nation is responsible for the remainder of CAP water charges. This is consistent with a statement in the NREL report that describes the settlement agreements to clarify that if the Developm ent and Cooperative Funds are no longer available, the Tohono O’odham are responsible for paying all CAP water charges to fulfill the settlement allocations. 168
Additionally, the NREL report states that the Tohono O’odham have not been able to access its CAP allocation because no delivery or distributi on systems have been constructed, however, the

comment letter from the Tohono O’odham to EPA doe s not indicate that it is not receiving its CAP water allocation, nor does it discuss relian ce on the Development Fund for the creation of its water infrastructure systems.

The San Carlos Apache Tribe (San Carlos Apache) did not submit comments to EPA on our ANPR, but representatives of the San Carlos Apache did attend a consultation meeting

related to NGS between tribes in Arizona and EPA in Phoenix, on September 16, 2011. EPA has not received information directly from the San Carlos Apache but understa nds that water rights

and claims were settled in 1992 in the San Carl os Apache Tribe Water Rights Settlement Act,

and the settlement act established two funds for the benefit of the San Carlos Apache: the San Carlos Apache Tribe Development Trust Fund, and the San Carlos Apache Tribe Lease Fund, administered by the Bureau of Indian Affairs. 169 Principal and income from the Trust Fund can be used in several ways, including to put CAP wate r to beneficial use or to defray costs to the

165 See table on page 27 of the March 15, 2012 Updated Harvey Economics Letter to Gila River Indian Community on NGS Impacts, in the docket for this proposed rulemaking.

166 Letter from Louis J., Manuel, Jr. Ak-Chin Indian Commun ity, to Janet McCabe, EPA, re: Navajo Generating Station Proposed Air Quality Regulations and the Federal Trust Responsibility. October 14, 2011.

167 Letter from Dr. Ned Norris, Jr., Tohono O’odham Nation to Jared Blumenfeld, EPA, re: Tohono O’odham Comments on ANPR. March 1, 2010.

168 Page 104 of the NREL repo rt and references therein.

169 See 66 FR 21086, April 27, 2001.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 77 of 129 tribe of CAP OM&R costs. Defined uses for the Lease Fund are unrelated to CAP water. Additionally, based on information on the Sa n Carlos Apache in the NREL report, EPA

understands that the CAP alloca tion to the San Carlos Apache is variable, ranging from 45,565 AF to 60,665 AF per year, and that some of th e tribe’s allocation comes from the unused portion of the Ak-Chin allocation. The NREL report furt her states that the San Carlos Apache are working with Reclamation on a water delivery sy stem, that the Arizona Water Settlement Act (AWSA) provides funding to build a water system sufficient to delivery 12,700 AF per year of CAP water to the San Carlos Apache Tribe, and that currently, the San Carlos Apache lease a total of 26,500 AF per year of water to non-tribal users (the City of Scottsdale and to the Phelps Dodge Morenci Mine). EPA does not have additiona l information on the status of the San Carlos Apache Trust Fund, and whether the water de livery system the San Carlos Apache and Reclamation are currently working on is f unded through the Lower Colorado River Basin Development Fund or through the San Carlos Ap ache Tribe Development Trust Fund. Because the San Carlos Apache have two separate funds es tablished under a separate settlement act from the Lower Colorado River Basin Development F und, EPA believes the San Carlos Apache Tribe would not be adversely affected by a requirement from EPA to require additional air pollution

controls at NGS. Because EPA has not received information directly from the San Carlos Apache, and it is unclear the degree to which the San Carlos Apache can rely on the Lower Colorado River Basin Development Fund, EPA requests comment from the San Carlos Apache on potential effects of our pr oposed BART determination for NGS on its water settlement

agreement.

The White Mountain Apache Indian Tribe (White Mountain Apache) did not submit

comments to EPA on our ANPRM and did not a ttend consultation meeti ngs between EPA and

tribes located in Arizona in 2011 and 2012. From the NREL report, EPA understands that the White Mountain Apache achieved a water settlement agreement in January 2009 (effective in December 2010), that allocated the tribe 23,782 AF pe r year of CAP water, and that the entire

allocation has been leased under the terms of the settlement. 170 If the White Mountain Apache were to use its CAP water allocation, NREL states that fixed OM&R water costs would be paid by the Development Fund, as long as funds are av ailable. Because the tribe’s full CAP water allocation is leased, EPA believes the White Mountain Apache would not be significantly affected by increased energy generation costs at NGS as a result of BART controls. Because EPA has not received information directly from the White Mountain Apache, and the duration of its lease of CAP water is unclear, EPA reque sts comment from the White Mountain Apache on potential effects of our proposed BART dete rmination for NGS on its water settlement

agreement.

In a comment letter to EPA from Dr. Clinton M. Pattea, President of the Fort McDowell Yavapai Nation (Fort McDowell), Dr. Pattea described concerns related to CAP water cost increases, and also questioned whether cont rol requirements on NGS would affect Fort McDowell’s electric power allocation from seve ral Federal hydroelectri c generation facilities marketed by the Western Area Power Administration (WAPA). Dr. Pattea states that in order to utilize its electric power allocation, Fort Mc Dowell selected SRP to accept Fort McDowell’s power allocation and pass through the benefit of the power. EPA believes that a BART rulemaking on NGS would not affect agreements between Fort McDowell, SRP, or WAPA related to electric power allocations from Fede ral hydroelectric faciliti es. EPA understands that

water claims for Fort McDowell were settled in 1990 (Fort McDowell Indian Community Water

170 See page 104 of the NREL report.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 78 of 129 Rights), and the NREL report states that Fort McDowell has a CAP water allocation of 18,233 AF per year, and is currently leasing 4,300 AF to the City of Phoenix. The NREL report also

states that the tribe is currentl y entering into annual leases for all but 250 AF of the balance. If Fort McDowell needs to develop infrastructure to utilize the remaining 250 AF of CAP water, EPA believes that Fort McDowell may be affect ed by a requirement to install additional air pollution controls at NGS. Because Fort McDo well’s future intentions for its CAP water allocation are unclear, EPA requests comment from Fort McDowell on potential effects of our proposed BART determination for NGS on its water settlement agreement.

The Salt River-Pima Maricopa Indian Commun ity (Salt River-Pima Maricopa) did not submit comments to EPA on NGS (but did su bmit comments on Four Corners Power Plant related to potential effects of post-combustion controls on fly ash), and did not attend consultation meetings on NGS in 2011 or 2012. EPA understands that the Salt River-Pima Maricopa have a water rights settlement fo r 13,300 AF per year of CAP water, with a $47 million economic development trust fund. The NREL re port states that the total Salt River-Pima Maricopa settlement includes water from differ ent sources, totaling 122,400 AF per year, and that its full CAP allocation of 13,300 AF per year is leased to Phoenix-area cities. Thus, assuming the Salt River-Pima Maricopa CAP wa ter allocation is le ased under long-term contracts, EPA believes the Salt River-Pima Maricopa Indian Community will not be significantly affected by a requirement to inst all additional air polluti on controls at NGS. Because Salt River-Pima Maricopa’s future inte ntions for its CAP water allocation are unclear, EPA requests comment from Salt River-Pima Mari copa on potential effects of our proposed BART determination for NGS on its water settlement agreement.

The Navajo Nation does not have a final water settlement agreement yet, but the Arizona

Water Settlement Act of 2004 defines a CAP allo cation of 6,411 AF per year to the Navajo Nation with a requirement that the settlement mu st be approved by Congress before December 31, 2030. On February 14, 2012, Senator Jon Kyl of Arizona introduced Senate Bill S.2109: “Navajo-Hopi Little Colorado River Water Rights Settlement Act of 2012”. 171 This bill also

defined an allocation of CAP wa ter to the Hopi Tribe of 1,000 AF per year. This bill was not

enacted and was referred back to Committee. 172 It is unclear at this time when a final water settlement agreement for the Navajo Nation and Hopi Tribe will be impl emented, what the terms of that settlement may be, and the degree of reliance of the settlement on CAP or the Development Fund.

The Yavapai-Apache Nation (Yavapai-Apache) submitted comments to EPA and

attended a consultation meeti ng with EPA on NGS in 2011. The Yavapai-Apache currently have a contract with DOI from December 11, 1980 fo r the delivery of 1,200 AF of CAP water and currently, the Yavapai-Apache are developing the infrastructure necessary to deliver the CAP

contract water to its Reservation lands. If the Yavapai-Apache currently lack infrastructure to receive CAP water, the existing fa te of the tribe’s 1,200 AF of CAP contract water is not clear. The Yavapai-Apache have expressed concern that installation of new air pollution controls at NGS will affect their ability to achieve a final water settlement agreement, as well as the ability of the Development Fund to pay fixed OM&R charges for the tribe and support its water infrastructure development.

171 See Navajo-Hopi Little Colorado River Water Rights Settlement Act of 2012, S.2109, 112 th Congress, 2D Session, February 14, 2012. Information also available at http://www.govtrack.us/c ongress/bills/112/s2109.

172 http://www.govtrack.us/congress/bills/112/s2109Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 79 of 129 The Pascua Yaqui Tribe (Pascua Yaqui) s ubmitted comments to EPA expressing concern that requiring additional air polluti on controls at NGS w ould affect the tribe’s ability to use CAP water and its ability to achieve a final water ri ghts settlement in the future. The Pascua Yaqui currently lease 500 AF of CAP water per year, unde r a contract with the Department of Interior dated December 11, 1980. The NREL report states that the Pascua Yaqui take delivery of the full amount of contract water via an exchange with the City of Tucson. A lthough it is not clearly stated in the NREL report, or in the Pascua Ya qui letter to EPA, it appears the fixed OM&R water costs are also paid from the Developmen t Fund for the Pascua Yaqui, therefore, it also appears that the tribe is responsible for variab le OM&R water costs, as well as a fee of $15.17 per AF to the City of Tucson for storing the tribe’s water. 173 The NREL report further states that the Pascua Yaqui are currently claiming a water right of 3,520 AF per year and the claim is the subject of current adjudication.

The Yavapai-Prescott Indian Tribe (Yavapai-P rescott) has a water settlement agreement (Yavapai-Prescott Indian Tribe Water Rights Se ttlement Act of 1994) that allocates 500 AF per year of CAP water to the Yavapai-Prescott. Th e NREL report states that the Yavapai-Prescott has “assigned this water to the City of Scottsdale”. 174 It is unclear to EPA if this “assignment” of water represents a permanent lease of the wate r, and whether the Yavapai-Prescott plan to develop water infrastructure to use its CAP wate r allocation in the future. The Yavapai-Prescott

did not submit comments to EPA on the ANPRM and did not attend consultation meetings on

NGS held with tribes in Arizona in 2011 or 2012. Assuming that the Yavapai-Prescott CAP

water allocation is leased under l ong-term contracts or if the Yava pai-Prescott does not plan to use its CAP water allocation, EPA believes the Yavapai-Prescott Indian Tribe will not be significantly affected by a requirement to insta ll additional air pollution controls at NGS.

The Tonto Apache Tribe (Tonto Apache) have not submitted comments to EPA on the ANPRM and did not attend consultation meetings on NGS held with tribes in Arizona in 2011 or

2012. EPA understands from the NR EL report that the Tonto Apach e have an allocation and a CAP water contract for 128 AF per year, but have not reached a water rights settlement agreement. The NREL report further states that the Tonto Apache are not using their CAP water allocation, have no existing authority to lease or ex change the water, and lack the infrastructure

to receive its CAP allocation. Becau se the water infrastructure is not yet in place, if the Tonto Apache rely on the Development Fund for infras tructure construction, EPA believes that the Tonto Apache could be adversely affected by a requirement to install additional air pollution

controls at NGS. Because EPA has not received information directly from the Tonto Apache, EPA requests comment from the Tonto-Apache on potential effects of our proposed BART determination for NGS on its water settlement agreement.

The Havasupai Tribe of the Havasupai Reserv ation (Havasupai), the Hualapai Indian Tribe of the Hualapai Reservati on (Hualapai), and Kaibab Band of Paiute Indians of the Kaibab Reservation (Kaibab Band) did not submit commen ts to EPA on the ANPRM or participate in

consultation between EPA and tribes located in Arizona in 2011 and 2012. The letter from the

CAWCD to DOI and EPA cited these three tribes as having unresolved wa ter rights claims. The NREL report does not discuss these three tribes, and EPA does not have additional information. Assuming all unresolved water claims use CAP water and the Development Fund for fulfilling

173 See page 103 of NREL report and references therein.

174 See page 104 of NREL report.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 80 of 129 settlement agreements (although it is not clear to EPA that the CAP/Development Fund must always be used as a model), then the Havasupa i, Hualapai, and Kaibab Band could be adversely affected by a requirement to install additiona l air pollution controls at NGS, however, EPA requests comments from these trib es regarding specific concerns they may have and potential

effects on their tribes of our proposed BART determination for NGS.

The Colorado River Indian Tribes, which in cludes four distinct tribes: the Mojave, Chemehuevi, Navajo, and Hopi, did not submit comments to EPA on the ANPRM, but did attend the consultation meetings between EPA and tr ibes located in Arizona in 2011 and 2012. The NREL report and the letter from CAWCD to DOI and EPA did not discuss the Colorado River Indian Tribes or identify them as having an out standing or unresolved water claim. EPA is not aware of how the Colorado River Indian Tribes (a side from the Navajo and Hopi portions of the Tribes) they may be affected by our BART determination for NGS. EPA requests comments from the Colorado River Indian Tribes regarding specific concerns they may have and potential

effects on their tribes of our proposed BART determination for NGS.

In the preceding paragraphs, EPA discussed potential impacts to sixteen tribes in Arizona. Of these tribes, EPA understands that nine tribes: Gila River, Ak-Chin, Tohono O’odham, San Carlos Apache, White Mountain Apache, Fort McDowell, Salt River PimaMaricopa, Navajo Nation, and the Yavapai-Presco tt, have allocations to CAP water that have been finalized in settlement agreements. Of these nine tribes, four tribes several currently lease

all or most of their CAP water allocations: Wh ite Mountain Apache, Fort McDowell, Salt RiverPima Maricopa, and Yavapai-Prescott. Eight tribes appear to be in the process of developing water settlement agreements: Hopi Tribe (and Navajo Nation, as required under the terms of their CAP allocation in the 2004 AWSA), Pascua Yaqui Tribe, Tonto Apache Tribe, and the Havasupai, Hualapai, and the Kaibab Band of Paiute Indians. EPA requests comments or supplemental information from these sixteen tribes , as well as other tribes located in Arizona where specific information was not available: the Colorado River Indian Tribes, the San Juan Southern Paiute Tribe of Arizona, Cocopah I ndian Tribe, Quechan Indian Tribe, and the

Chemehuevi Indian Tribe of the Chemehuevi Reservation.

d. Potential Impacts to Non-Indian Agriculture Users

Agricultural water users in Arizona, referenced by CAWCD as the Non-Indian Agriculture (NIA) users, pay onl y for the energy pumping costs of CAP water (variable OM&R). In its letter to DOI and EPA, CAWCD states that a critical component of the Arizona Water Settlement Act of 2004 was the relinquishment of CAP’s NIA users of long-term entitlements to CAP water, allowing the DOI to settle water cl aims and reserve water for future settlement agreements. CAWCD states that “in return, the NIA users expected to receive a quantity- and time-limited pool of CAP water at a price they could afford”. 175

According to CAWCD in its February 2012 letter, NIA users take delivery of approximately 400,000 AF per year of CAP water, while tribal agricultural users take delivery of about 140,000 AF per year of CAP water and ar e increasing their use. The sum of all known

tribal CAP allocations and cont racts (as listed in Table 22) to tals nearly 600,000 AF per year,

175 See February 23, 2012 from CAP to DOI and EPA regarding CAP’s comments on the NREL report, page 11, in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 81 of 129 however, as discussed above, many tribes with CA P water allocations cannot or do not use their full allocations and many tribes lease their alloca tions, in full or in part, to Arizona cities. EPA

understands NIA users of CAP wa ter are concerned about potentia l impacts of increasing costs

of CAP water. 176 Over the short term, EPA also unders tands that irresp ective of a BART determination on NGS, variable OM&R water rates for CAP water have generally increased annually and are projected to cont inue to increase into the future . It is unclear to EPA how long NIA users expect to continue using CAP water, and whether th e existing NIA users intend and are allowed to return to groundwat er when the transition from NI A use of CAP water to Indian agriculture use of CAP water o ccurs, or if CAWCD and the farm ers expect NIA users to cease operations when CAP water is no longer available for NIA use.

e. Potential Impacts to Muni cipal and Industrial Users

The addendum to the report by Energy Strategies discusses potential impacts to the major municipal users of CAP water. 177 The addendum identifies the cities of Tucson, Phoenix, Scottsdale, and Mesa to have the largest muni cipal allocations of CA P water, and together represent roughly 60% of the CAP M&I water user allocati ons. As discussed above, the

installation of SCR on all units at NGS is expected to increase water rates to M&I users by 6%. However, the impact to an individual M&I user’s total water cost will depend on the amount of CAP water a given entity uses a nd the percentage the CAP water re presents of the entity’s total portfolio. The city of Tucson relies entirely on CAP for its water s upply, therefore Tucson will experience the full 6% increase in its total wate r costs. In contrast, the cities of Phoenix, Scottsdale, and Mesa have several sources of water, and rely on CAP for 45 – 70% of their individual water supplies. Thus, the 6% increase in water rates will be somewhat mitigated and

increases in total water costs to those citi es are expected to range from 4 – 5%.

f. Broader Economic Impacts to Arizona

In addition to the NREL and Harvey Economics studies discussed above, SRP commissioned a study by the Seidman Research In stitute at Arizona Stat e University (Navajo Generating Station and Kayenta Mi ne: an Economic Impact Study). 178 This study is included in the docket for this proposed rulemaking, and EPA is including a summary of the main conclusions from the study, but we are not pr oviding a critical review of this study’s methodologies or conclusions.

The study was a macroeconomic assessment of the impact NGS and the Kayenta Mine have on the Arizona economy, examining the c ontributions of the power plant and mine to values such as employment, income, and tax reve nue. It also provides an assessment of these impacts at the county specific level. The study di ffers from those previously discussed in that it

concentrates on the overall value of NGS and the Kayenta Mine to the Arizona economy and did not attempt to measure changes in power and wa ter rates resulting from new capital investment at the power station. Accordingly, it did not co nduct different scenarios reflecting various BART related capital expe nditures, but instead, took cu rrent prevailing data a nd provided estimations of

176 See letter from August 10, 2010 letter from Tempe Farming Co. to EPA, in the docket for this proposed rulemaking.

177 See Addendum to Energy Strategies report on Economic Impacts to CAP Water users in the docket for this proposed rulemaking.

178 See document titled: “2012_0202 Final ASU Report.pdf” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 82 of 129 future job, income and taxes that would be at tributable to the plan t and mine’s continued operation.

The model estimated that over 2011 – 2044, approximately 113,000 full-time job years (one person working one full year) were attributable to the plant and mine’s operation. Of this number, nearly 33,000 were directly related to the two facilities. A dditionally, Gross State Product was estimated to increase by roughly $20.5 billion and Real Personal Disposal Income by over $11 billion during the time frame. The report’s conclusions sugg est that, over the time frame noted, the operation of the plant and mine re sult in a significant macroeconomic benefit to

the state.

iii. EPA’s Proposed Determination for Factor 2: Energy, Non-Air Quality, and Economic Impacts of Compliance Factor

EPA understands that the timing of regulatory compliance is an important consideration given that the current term of NGS’s lease with the Navajo Nation expires in 2019. Based on public statements made by stakeholders, and as indicated in the NREL report, the owners of NGS intend to pursue a renewed lease that extend s to 2044. However, until a renewed lease that supports continued long-term operation of NGS is negotiated and approve d, significant capital

investment needed to modernize NGS with new air pollution controls is viewed as a risky business decision without sufficient certainty that the costs can be rec overed over 20 years.

Based on our economic analyses, the cost to produce power at NGS with SCR installed on all units should be below the market prices of wholesale power, and incr eased electricity rates

to customers of the electric ut ilities that own NGS should be re latively low. EPA understands that a potential increase in water rates to tribes is a critical issue for them. We note that, as described in the following secti on, past pollution control investments at this facility have made use of alternative financing me thods that limited impacts on CAP water rates. Furthermore, the NREL report indicated that mechanisms may exist to help avoid or mitigate the estimated level of impact. EPA, in conjunction with DOI and DO E, have committed to work together on several short- and long-term goals, incl uding innovative clean energy op tions for electricity generation and seeking funding to cover expenses for the federal portion of po llution control at NGS. However, it is not clear at this time whether or what type of mechanisms might be available to lessen increased costs. Therefore, as explained further below, EPA believes that the potential economic impacts discussed in th is section argue for thoughtful c onsideration of how flexibility in the compliance timeframe can be provided cons istent with the air quality goals of the Clean

Air Act.



### 5. Factor 3: Any Existing Polluti on Control Technology at the Source

A. NGS Approach to This Factor

The existing air pollution c ontrol equipment, listed in orde r of flow through the physical flue gas configuration, as reporte d in its Part 71 Operating Permit from July 3, 2008, is shown in Table 23. Prior to 2009, to control NO

x emissions, NGS used close-coupled over fire air (CCOFA). NGS currently uses hot-s ide electrostatic precipitators (hot-side ESPs) to control PM.

To reduce emissions of SO 2 , SRP installed wet limestone flue gas desulfurization units (FGDs)Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 83 of 129 over 1997 – 1999 on each unit, as required under a vi sibility FIP issued by EPA on October 3, 1991 (56 FR 50172), codified at 40 CFR 49.5513 to re medy visibility impairment at the Grand Canyon National Park that was reasonably attr ibutable to NGS. The 1991 FIP set an emission

limit for SO 2 of 0.10 lb/MMBtu on a plant-wide rolli ng annual average basis. On March 5, 2010 (75 FR 10174), EPA issued a gap-filling FIP for NGS to federalize emission limits for PM of 0.06 lb/MMBtu on a plant-wide 3-hour average ba sis, opacity limit of 20%, and a short-term 3- hour average SO 2 limit of 1 lb/MMBtu. From the SO 2 emission limit in the final 2010 FIP, actual

SO 2 emissions from NGS will remain 90% lower on an annual basis than they were before the scrubbers were installed to comp ly with the 1991 visibility FIP.

Table 23: Flue Gas Flow Sequence and Air Pollution C ontrol Equipment 179 at NGS as reported in its July 3, 2008 Part 71 Operating Permit

Unit 1 Unit 2 Unit 3 Boiler – Close Coupled Overfire Air (CCOFA) (NO

x ) Boiler – CCOFA (NO

x ) Boiler – CCOFA (NO

x )

Economizer Economizer Economizer Dry Hot-Side Electrostatic Precipitator (PM) Dry Hot-Side Electrostatic Precipitator (PM) Dry Hot-Side Electrostatic Precipitator (PM)

Air Preheater Air Preheater Air Preheater

Limestone Flue Gas Desulfurization (SO 2 ) Limestone Flue Gas Desulfurization (SO 2 ) Limestone Flue Gas Desulfurization (SO 2 )

Stack Stack Stack

B. Discussion of this Factor in the ANPRM

In our August 28, 2009 ANPRM, EPA reported in Table 38 that existing controls for PM

and SO 2 at NGS consisted of hot-side ESPs and wet FGDs. Additionally, although the controls

did not exist at the time of publication, we reported that NGS uses LNB/SOFA as NO

x controls and noted that on November 20, 2008, EPA Region IX issued a PSD permit authorizing NGS to

install LNB/SOFA on Units 1 – 3 over 2009 – 2011. This modificat ion is discussed further in

Section 5.D. below.

C. Affected State, Tribe, and FLM Consultation

We did not receive comments on the existing air pollution controls for NO

x at NGS from affected states, Tribes, or FLMs.

D. EPA Conclusions regarding This Factor

In its comment letter (see p. 25) on the ANP RM, SRP stated that “[t]he ANPR makes no mention of the fact that SRP recently obtained authorization from EPA to voluntarily install

LNB/SOFA on each of the units at NGS betw een 2009 and 2011”. EPA notes that the ANPRM does report that EPA Region IX issued a PSD pe rmit authorizing NGS to modify Units 1 – 3

179 Air Pollution Control Equipment listed in regular text and the pollutant controlled is listed in parentheses.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 84 of 129 with LNB/SOFA over 2009 – 2011 (see footnote 29 in the ANPRM). EPA further notes that although the ANPRM was published in the Federa l Register in August 2009, before SRP began its retrofit of any of the Units at NGS with the LNB/SOFA, in the ANPRM, EPA listed

LNB/SOFA as the NO

x control method used at NGS (See Table 38 – Existing Air Pollution Controls at NGS in the ANPRM).

When SRP and AECOM submitted its BART an alysis to EPA in 2008 (dated November 2007), NO

x controls on each unit consisted of close-coupled over fire air (CCOFA) 180 . In April 2009, SRP submitted a Prevention of Significant Dete rioration (PSD) permit application to EPA Region IX to voluntarily install and operate advanced combustion controls (LNB/SOFA) on Units 1 – 3. This modification triggered PSD revi ew for significant increases in emissions of carbon monoxide (CO). Because SRP submitted its permit application for the LNB/SOFA modification after EPA had begun its BART anal ysis for NGS, in the Ambient Air Quality Impact Report (AAQIR) 181 for our proposed PSD permit (AZ 08-01), we stated that:

The early installation of the LNB/SOFA systems will not affect the baselines for cost or visibility improvements in the BART determination, and therefore will not

influence EPA’s determination of the proper NOx reductions required to be

achieved from BART.

Additionally, in an agreement 182 regarding the EPA proposed permit AZ 08-01signed November 19, 2008 by Bill Heddon, Executive Director of Grand Canyon Trust (GCT) and Richard Hayslip, Associate General Manager of SRP, GCT agreed to withdraw its November 14, 2008

comment letter to EPA with the SRP understanding that:

Grand Canyon Trust stands by its suppor t for the installation of low-NO

x burners and separated overfire air at the Navajo Generating Station as long as their installation and operation will not prejudice in any way the implementation of

more effective NO

x and particulate matter controls (including SCR or SNCR, and baghouse technology) to more fully addre ss Navajo’s visibility impacts under the reasonable attribution and regional haze programs.

SRP installed LNB/SOFA combustion controls on Unit 3 in 2009, on Unit 2 in 2010 and Unit 3 in 2011. Therefore, all three units currently operate with modern advanced combustion controls and are required to meet the NO

x limit set in the final PSD permit issued by EPA on November 20, 2008 of 0.24 lb/MMBtu on a 30-day rolling average. 183

In issuing the 2008 PSD permit to authorize the LNB/SOFA modi fications to achieve early NO

x early NO

x reductions in advance of our proposed BART determination, EPA, GCT, and SRP agreed that agreed that the installation of advanced com bustion controls would not prejudice our BART determination for NGS. Therefore, the cost effectiven ess of SCR in Section 3 was compared against the against the baseline emission rate from 2001 – 20 03, prior to the installa tion of the LNB/SOFA.

180 See Part 71 Operating Permit (Permit # NN-ROP-05-06) issued by the Navajo Nation Environmental Protection Agency, dated July 3, 2008, in the docket for this proposed rulemaking.

181 See EPA’s Ambient Air Quality Impact Report, dated October 2008, for the proposed PSD permit for NGS, in the docket for this proposed rulemaking.

182 See Agreement between Grand Canyon Trust and Salt River Project on NGS dated November 19, 2008, in the docket for this proposed rulemaking.

183 See final PSD permit issued by EPA Region IX dated November 20, 2008.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 85 of 129 However, because EPA’s proposed BART determinat ion is being put forth for public comment in 2013, in 2013, after the insta llation of advanced combustion controls ha s been completed on all units, EPA is EPA is also providing cost effectiv eness values using LNB/SOFA as a baseline (essentially equivalent to equivalent to incremental cost of SCR compared to LNB/SOFA) discussed in the incremental cost

cost effectiveness estimates in Section 3 of this TSD. 184 The economic analysis, discussed in Section 4 Section 4 above, considers the installation of advan ced combustion controls as expenditures that have have already occurred, therefore, additional calculations for the econom ic analysis using LNB/SOFA as

LNB/SOFA as baseline are not needed. The aver age cost effectiveness of SCR or SNCR using emissions resulting from installation of LNB/SOFA as a baseline are the same as the incremental cost

cost effectiveness values for SCR+LNB/SOFA (compared to LNB/SOFA) and SNCR+LNB/SOFA SNCR+LNB/SOFA (compared to LNB/SOFA) reported in

184 See spreadsheet titled “NGS emissions and incremental co sts.xlsx” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 86 of 129 Table 15.

EPA is proposing to determine that considera tion of the existing controls at the NGS does not warrant eliminating SCR as the t op technically-feasible , cost-effective NO

x emission control technology in our BART analysis. Additionally, as stated in Section 3 of this TSD, the cost effectiveness of SCR using LNB/SOFA as a baseline for existing NO

x controls (i.e., incremental cost effectiveness of SCR compared to LNB/ SOFA) is still reasonabl e and does not warrant elimination of SCR from our BART analysis.



### 6. Factor 4: Remaining Us eful Life of the Source

A. NGS Approach to This Factor

In its analysis, AECOM stated that it used an amortization of 20 y ears to represent the remaining useful life of NGS.

B. Discussion of Factor in ANPRM

In the ANPRM, we stated that the remaining us eful life is often expr essed in terms of the amortization period used to annualize the cost of controls. SRP used an amortization period of 20 years, which is consistent with the EPA Control Cost Manual . We requested comment on the use of 20 years to represent th e remaining useful life of NGS.

C. Affected State, Tribe, and FLM Consultation

The Navajo Nation recommended th at we adopt a phased approach to BART, in part to provide a reasonable timeframe in which to resolv e the outstanding lease and right-of-way issues that affect the productive life of NGS. EP A understands these issues involve upcoming negotiations between SRP and Navajo Nation on re newals of SRP’s coal, land, and right-of-way leases and agreements.

D. EPA Conclusions regarding This Factor

EPA is proposing to determine that the appr opriate remaining useful life for NGS, as used as an amortization period fo r the cost of controls, should be 20 years. The outcome of the lease and right-of-way negotiations could conceivably impact NGS’s ability to operate into the future; however, without an enfor ceable obligation to s hut down, EPA has determined it is most appropriate to rely on a 20 year useful life as the default for amortization purposes. EPA also

understands from recent discussions on the land l ease renewal for NGS that the owners may be negotiating for the renewal lease period to end in 2044 (over 30 years from 2013). Therefore, a 30 year amortization period may also be appropriate , and potentially more re alistic, to apply to the cost analysis for NGS. A longer amortizatio n period would reduce the annualized cost of capital improvements and reduce the cost effectiven ess (in $/ton) of controls. Because the use of a shorter amortization period is more conservative (increases th e $/ton cost effectiveness of controls), EPA’s calculations of cost effectivenes s in our analysis rely on a 20 year amortization period. However, EPA recognizes that if the capi tal costs of controls can be amortized over a longer period, the $/ton cost eff ectiveness of controls would decr ease (i.e., controls would cost less on a per-ton-of -NO

x -removed basis).Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 87 of 129 

### 7. Factor 5: Degree of Improvement in Visibility which May Reasonably be Anticipated to Result from the Use of Such Technology

A. BART Guidelines and Modeling Protocols

The final factor to consider for BART is th e degree of visibility improvement that may be reasonably anticipated to result from the BART control options. CAA §1 69A(g)(2). The BART Guidelines recommend use of the CALPUFF air qua lity dispersion model to estimate the visibility improvements at each Class I area, typically within a 300 km (186 mile) radius of the source, of alternative control technologies, and to compare these to each other and to the impact of the baseline, or current, source configuration. AECOM conducted the modeling for NGS and included eleven Class I Areas in their modeling analysis . These are listed in andTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 88 of 129 Table 25 and shown in Figure 3. The measured visibili ty impairment (in deciviews) at each Class I area is presented in Table 24 as a range of the 10 th and 90 th percentiles, averaged for 2006 through 2008.

Table 24: Measured Visibility Impairment at Class I areas (2006 – 2008 average), from IMPROVE monitoring network 185

Class I Area IMPROVE

monitor Average 20% Best Days Deciview Impairment Average 20% Worst Days Deciview Impairment

Arches NP CANY1 2.8 11.0 Bryce Canyon NP BRCA1 2.1 11.5 Canyonlands NP CANY1 2.8 11.0 Capitol Reef NP CAPI1 2.8 11.5 Grand Canyon NP GRCA2 2.2 11.1

Mazatzal WA IKBA1 5.3 13.5

Mesa Verde NP MEVE1 3.2 10.9

Petrified Forest NP PEFO1 4.8 12.3

Pine Mountain WA IKBA1 5.3 13.5 Sycamore Canyon WA SYCA1 5.2 14.9 Zion NP ZION1 (N.A. for Zion; see Bryce) (N.A. for Zion; see Bryce)

185 Regional Haze Rule Summary data, Revised (New) IMPROVE Algorithm, Means for Best, Middle, and Worst 20% Visibility Days, http://vista.cira.colostate.edu/improve/Data/IMPROVE/summary_data.htm . For calculated visibility impairment using the old IMPROVE equation, see “measured_vis_table_old_IMPROVE.doc”; and data/calculations in “group_means_NE_11_09_NGS_2006-2008.xls” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 89 of 129 Figure 3: Map of Class I Areas 300 km from NGSTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 90 of 129 Table 25: Class I Areas in CALPUFF Modeling for NGS

Class I Area Abbreviation State Agency IMPROVE

monitor 186 Distance to NGS (km) 187

Arches NP arch UT NPS CANY1 245 Bryce Canyon NP brca UT NPS BRCA1 96 Canyonlands NP cany UT NPS CANY1 173 Capitol Reef NP care UT NPS CAPI1 90 Grand Canyon NP grca AZ NPS GRCA2 29

Mazatzal WA maza AZ USFS IKBA1 279

Mesa Verde NP meve CO NPS MEVE1 253 Petrified Forest NP pefo AZ NPS PEFO1 235 Pine Mountain WA pimo AZ USFS IKBA1 287 Sycamore Canyon WA syca AZ USFS SYCA1 204

Zion NP zion UT NPS ZION1 134

Under the BART guidelines, the measure of the visibility improvement to be used in comparisons between various control scenarios is the 98 th percentile of imp acts is expressed as 24-hour averages of delta deciviews relative to natural background, as estimated using the CALPUFF air quality modeling system. The mean ing of this is described next, followed by specific details of the app lication of CALPUFF to the NGS BART determination.

Under the RHR, visibility is measured in d eciviews. Visibility is traditionally described in terms of visual range in k ilometers or miles. However, th e visual range scale does not correspond to how people perceive visibility: a given increase in visual range is perceived differently depending on how good the original visibili ty was (that is, it is not on a linear scale). The deciview scale is designed to address this problem. It is linear with respect to perceived visual changes over its entire range , analogous to the decibel scale for sound: a given change in deciviews will be perceived as the same amount of visibility change, whatever the original visibility was. The defining equation is: deciviews = 10*ln(b ext / 10), where ln is the natural logarithm, and the extinction coefficient, b ext , is the fraction of light scattered out of a viewing path. Extinction increases w ith the amount of pollution (b ext is in units of 1/Mm, “inverse megameters”). Lower deciview values represent be tter visibility, more pris tine atmospheres, and greater visual range, wh ile increasing deciview values repr esent increasingly poor visibility. An increase of 1 deciview corresponds to about a 10% increase in extinction. 188 An eligible BART source with a predicted impact of 0.5 dv or more of impairment in a Class I area “contributes” to visibility impairment and is subject to BART. 70 FR 39104, 39121 (July 6, 2005).

Under the BART guidelines, deciviews ar e estimated using the CALPUFF air quality model. CALPUFF predicts 24-hou r average pollutant concentra tions based on source emissions and how they disperse in the atmosphere. The CALPUFF model includes s ource emissions of the following visibility-imp airing pollutants: SO 2 , SO 4 , NO

x , secondary organic aerosol (SOA), fine particulate matter (PMF), coarse particulat e matter (PMC), and elemental carbon (EC). CALPUFF incorporates a semi-empirical chemi cal module that simulates the conversion of SO 2 to particulate sulfate and NO

x to particulate nitrate, at a rate dependent on meteorological

186 For a Class I area without an IMPROVE mon itor of its own, the nearest monitor in another area is used; “IKBA” is Ike’s Backbone IMPROVE site, located in the northern Mazatzal Wilderness.

187 Distance is calculated between Unit 1 of NGS and th e nearest model receptor location in the Class I area.

188 Deciviews are related to the more traditional visual range according to dv = 10*ln(391 / visual range (km))Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 91 of 129 conditions and background ozone concentrati on. The CALPOST post-pro cessor (part of the CALPUFF modeling system) converts th ese concentrations to extincti on, and then to deciviews.

CALPOST’s conversion of the CALP UFF concentrations to extinction, b ext , is done by applying the IMPROVE 189 equation . The IMPROVE equation has an old and a revised version, implemented in CALPOST as “Method 6” and “Method 8 (mode 5)”, respectively.

The old IMPROVE or Method 6 equation is:

b ext = 3 * f(RH) * [ sulfate ] + 3 * f(RH) * [ nitrate ] + 4 * [ organic mass ] + 10 * [ elemental carbon ] + 1 * [ fine soil ] + 0.6 * [ coarse mass ]

+ 10

Each term in the equation is the extinction due to a pa rticular measured component; bracketed quantities are concentrations as pr edicted by CALPUFF (or as measured at an IMPROVE monitor). The 10 is for Rayleigh scatteri ng, which is due to the interaction of light with molecules of air itself with no pollutant s, and the old IMPROVE equation assumes this

value to be the same for all locations. The re vised (new) IMPROVE equation allows for sitespecific values for Rayleigh s cattering, typically ranging from 9 – 11. For the revised (new) IMPROVE equation, EPA assumed this value to be 10. The f(RH) is a water growth factor for sulfate and nitrate; its value depends on relative humidity (RH) , ranging from 1 at low humidity to 18 at 98% humidity.

The revised (new) IMPROVE or Method 8 equation is:

b ext = 2.2 * f S (RH) * [ small sulfate ] + 4.8 * f L (RH) * [ large sulfate ]

+ 2.4 * f S (RH) * [ small nitrate ] + 5.1 * f L (RH) * [ large nitrate ] + 2.8 * [ small organic mass ] + 6.1 * [ large organic mass ] + 10 * [ elemental carbon ] + 1 * [ fine soil ]

+ 1.7 * f SS (RH) * [ sea salt ] + 0.6 * [ coarse mass ] + Rayleigh scatteri ng (site-specific) + 0.33 * [NO 2 (ppb)]

Sulfate is assumed to be all “large sulfate” if total sulfate is over 20 μ g/m 3 , otherwise its fraction of the total is assumed to increase uniformly between 0 and 1 when the total is in the range between 0 and 20, i.e., large sulfate = (total sulfate/20)*total. A similar definition applies for nitrate and for organic mass. The f S , f L , f SS are water growth factors for small (“S”) and large (“L”) fractions of sulfate and nitrate, and fo r sea salt (“SS”). Their values depend on relative humidity, ranging from 1 at low humidity to over 5 at 95% humidity. The additional refinements

189 Interagency Monitoring of Protected Visual Environments (IMPROVE) is a network of monitors in various Class I Areas, established to assess visibility impairment and its causes . The IMPROVE equation is used to converted monitored concentrations into extinction, a measure of visi bility. See: http://vista.cira.colostate.edu/improve/Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 92 of 129 for size fractions and site-specific measurements in the revised IMPROVE equation results in less bias in matching visibility measuremen ts under high and low visibility conditions. 190

Finally, CALPOST takes the extinction from the IMPROVE equation and converts it to the delta deciviews ( Δ dv) to represent the impact on visibility in decivi ews of the source being evaluated. It is the change, or “delta”, between deciviews with and without the source. Under the BART guidelines, delta deciviews is the differe nce between deciviews including the impact of the source and natural background, and decivi ews of the natural background alone. Each modeled day and location in the Class I area will have an associated delta deciview. For each day, the model finds the maximum visibility impact of all locations (rece ptors) in the Class I area. From among these daily values, the BA RT Guidelines recommend use of the 98th percentile, roughly equivalent to the 8 th highest day, for comparing th e base case and the effects

of various controls. The 98th percentile is recommended rather than the maximum value to avoid undue influence from unusual meteorological conditions (BART Guidelines, 70 FR at 39121). For this proposal, EPA generally relied on the 98th percentile of all three years’ data taken together, but results for the average of the th ree individual years’ 98th percentiles are also provided in spreadsheet tables in the docket. 191

The natural background used in computing delta deciviews may reflec t either the annual average, or the best 20 percent of days; these may be referred to as “a” and “b”. A facility’s impact will stand out more under better visibili ty conditions (“b”). Thus, modeled facility impacts and control benefits appear smaller when “a” is used than when “b” is used. EPA

Guidance allows for the use of either “a” or “b.” 192 For visibility method 6, annual average background concentrations to be used for all Cl ass I areas in the West are available in EPA guidance. 193 Best 20% concentrations are not prov ided, but can be estimated by scaling the annual concentrations by the ratio of best 20% and annual averag e extinction, which are provided in the EPA guidance document. 194 For visibility method 8, both annual average and

best 20% for individual Class I areas are available in th e “FLAG 2010” guidance document from the Federal Land Managers. 195

Considering visibility method and natural background together, one may use Method 6 or Method 8, and background “a” or “b”, for a total of four combinations: 6a, 6b, 8a, and 8b. All of these were modeled by EPA, and results for all ar e provided in spreadsheet tables in the docket for this proposal. However, EPA primarily reli ed on method “8b”, that is, the revised IMPROVE equation, and impacts relative to the best 20 percent of natural background days. This is most consistent with our current understanding of how best to assess source specif ic visibility impacts,

190 Pitchford, Marc, 2006, “New IMPROVE algorithm for estimating light extinction approved for use”, The IMPROVE

Newsletter , Volume 14, Number 4, Air Resource Specialists, Inc.; web page: http://vista.cira.colostate.edu/im prove/Publications/news_letters.htm

direct link: http://vista.cira.colostate.edu/improve/Pub lications/NewsLetters/IMPNews4thQtr2005.pdf

191 See NGS RH FIP TSD_vis_Tables in the docket for this proposed rulemaking.

192 “Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations”, memorandum from Joseph W. Paisie, EPA OAQPS, July 19, 2006, p.2

193 Table 2-1 of Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule , U.S. Environmental Protection Agency, EPA-454/B-03-005, September 2003, on we b page http://www.epa.gov/ttn/oarpg/t1pgm.html, with direct

link http://www.epa.gov/ttn/oarpg/t1/memoranda/rh_envcurhr_gd.pdf ;

194 This scaling for best 20% concentrations is implemented in the dock et spreadsheet “EPA_avg_natural_bg.xls”

195 Federal Land Managers’ Air Quality Related Values Work Group (FLAG) Phase I Report—Revised (2010) , U.S. Forest Service, National Park Service, U.S. Fish And Wildlife Se rvice, October 2010. Often referred to as “FLAG 2010”. See http://www.nature.nps.gov/air/Permits/flag/ Direct link: http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdfTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 93 of 129 and is consistent with current Federal Land Manager Guidance on assessing visibility impacts,

the FLAG 2010 document as well as with the initial EPA recommendations for BART

assessments. 196

AECOM conducted modeling for NGS according to modeling protocols submitted to

EPA. 197 The modeling analysis generally follo wed the BART protocol developed by the Western Regional Air Partnership (WRAP), except as noted below. 198

The WRAP protocol received extensiv e scrutiny during 2005-2006 by various States, EPA Regions, and Federal Land Managers (FLMs). So me key features of the protocol are listed here. Meteorological fields were derived from the MM5 prognostic meteorological model, using a 36 km grid resolution, for the years 2001, 2002, and 2003 and with the continental United States as the modeling domain. Subdomains were extracted for us e by individual states, such as

Arizona and New Mexico. The MM5 fields were then processed using CALMET (meteorological pre-processor, part of the CALP UFF modeling system) as preparation for use in the CALPUFF air quality model, using a 4 km gr id resolution. After much discussion, WRAP elected to blend meteorological station observati ons into the MM5 fields, instead of relying on the CALMET “no observations” (“no obs”) mode.

For visibility calculations, the pollution c oncentration predictions of CALPUFF are used in two post-processing steps. First, POSTUTIL considers ammonia b ackground concentrations, temperature, and humidity to determine how mu ch nitrate ends up as particulate ammonium nitrate; this is to reflect the competition betw een sulfate and nitrate for available ammonia. Ammonia background is discussed further be low. Second, CALPOST uses the adjusted concentrations to calculate visibility using th e IMPROVE equation, as described above. For the particular way of applying it, the WRAP protocol specified visibility ca lculation “Method 6” in CALPOST, the original EPA-recommended appro ach that uses monthly average humidity. For this proposal, however, EPA relied on “Method 8”, as discussed above.

The AECOM modeling protocol mainly fo llowed the WRAP protocols. CALMET and CALPUFF settings were almost all the same ; the WRAP-defined Arizona and New Mexico subdomains were used; all Class I Areas within 300 km of NGS were included. However, the AECOM protocol differed in several important respects. First, AECOM used the CALMET and

CALPUFF versions recommended by EPA because they do not have the problems identified in the versions used by WRAP. Second, when blending in meteorological station wind observations, AECOM used a lower radius of influence for stations (R1, R2, RMAX1). As shown in the wind field illustrations provided by AECOM, this resulted in smoother wind fields than those used for WRAP, which had some abrupt changes as one leaves the zone of influence of a given meteorological stati on. After initial input from th e Federal Land Managers, EPA requested that certain other CA LMET option settings be changed. These changes resulted in a more refined approach that is more consistent with approaches used in PSD permit application

196 BART Guidelines, 70 FR 39125, July 6, 2005. “Finally, these final BART guidelines use the natural visibility baseline for the 20 percent best visibility days for comparison to the ‘cause or contribute’ applicability thresholds.”

197 See Modeling Protocol for NGS dated September 2007 and submitted to EPA in June 2008 in the docket for this proposed rulemaking.

198 “CALMET/CALPUFF Protocol for BART Exemption Screen ing Analysis for Class I Areas in the Western United States”, Western Regional Air Partnership (WRAP); Gail Tonnesen, Zion Wang; Ralph Morris, Abby Hoats and Yiqin Jia, August 15, 2006. Available on UCR Regional Modeling Center web site, BART CALPUFF Modeling, http://pah.cert.ucr.ed u/aqm/308/bart.shtmlTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 94 of 129 modeling. The revised modeling has more extensiv e use of meteorological station observations (e.g. IEXTR=-4 to extrapolate surf ace observations up to higher layers ), and thus is responsive to the FLM concerns regarding the “no observations” mode mentioned above. Various relevant CALMET option settings are listed in Table 26. For meteorological input to CALPUFF, EPA used the AECOM CALMET results, which used the settings in the “Revised modeling” column

of Table 26.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 95 of 129 Table 26: Selected CALMET settings for NGS

Option Description EPA

default WRAP Original modeling 199 Revised modeling 200 Comments

version CALMET version 5.8, level

070623 6.211, level

060414 5.8, level

070623 5.8, level

070623

NOOBS No Observation

Mode 0 0 or 1 implied 1 0 Change per FLM recommendation: use both surface and upper air

observations ICLOUD gridded cloud fields 0 0 0 IWFCOD diagnostic winds 1 1 1 IFRADJ Froude wind adj. 1 1 1

IKINE kinematic effects 0 0 0

IOBR O'Brien vertical wind adj. 0 0 0

ISLOPE slope flows 1 1 1 IEXTRP extrapolate wind to upper air -4 1 1 -4 Change per FLM recommendation: to extrapolate up from surface
ICALM extrapolate calm to upper air 0 0 0

BIAS layer biases sfc vs.

UA NZ*0 NZ*0 NZ*0

IPROG gridded initial prognostic 0 14 14 Use prognostic inputs from MM5

RMAX1 max surface radius

of influence NA 50 30 Gives smoot her wind fields, per

AECOM

RMAX2 max aloft radius of

influence NA 100 100

RMAX3 max over-water

radius of influence. NA 100 100

RMIN min wind radius of

influence. 0.1 0.1 0.1

RMIN2 min dist sfc winds

extrap 4 4 4

TERRAD terrain radius of in

influence NA 10 10

R1 weight surface Step

1 vs. obs NA 100 18 Gives smoot her wind fields, per

AECOM R2 weight aloft Step 1

vs. obs NA 200 20 Gives smoot her wind fields, per

AECOM

ITPROG 3D T from obs or prognostic 0 1 or 2 implied 2 1 Change per FLM recommendation: use surface station temperatures

TRADKM radius of influ. for T interp. 500 500 500

IAVET spatial T averaging 1 0 1 Smoothing turned on (WRAP thought MM5 already smooth enough) JWAT1 starting land use for T interp. over water 999 51 51 This area has very little "water" land use; may set to 999 to disable overwater feature, and avoid a CALMET bug JWAT2 ending land use for T interp. over water 999 55 55

As mentioned above, the BART guidelines recommend that impacts of sources be

estimated in deciviews relati ve to natural background. EP A initially used background

concentrations from Table 2-1 of “Guidance fo r Estimating Natural Visibility Conditions Under

199 January 29, 2008

200 December 16, 2009 (ENSR/AECOM report dated November 2008)Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 96 of 129 the Regional Haze Rule”. 201 Although the concentration for each pollutant is a single value for the year, this method allows for monthly variatio n in its visibility impact, which changes with relative humidity. The resulting backgrounds in deciviews differ by roughly 1% from those resulting from the method originally used by AECOM. 202 As discussed above, EPA ultimately relied on area-specific natural background concentr ations for the best 20% of days, from the

FLAG 2010 document.

In addition to the general modeling pro cedures, we must address two additional pollutants when estimating the impact of various control technologies on visibility improvement: ammonia (NH 3 ) and sulfuric acid (H 2 SO 4 ).

B. Ammonia

Ammonia is important because it is a precurs or to particulate ammonium sulfate and ammonium nitrate, both of which degrade visibility. It is present in the atmosphere from both natural and anthropogenic sources. The latter may include livestock operations, fertilizer application associated with farming, and ammonia slip (or un-reacted amm onia) from its use in

SCR or SNCR to control NO

x emissions.

In the CALPUFF modeling inputs, EPA and AECOM both assumed that the remaining ammonia in the flue gas following SCR reacts with sulfuric acid to form ammonium sulfate or

ammonium bisulfate before exiti ng the stack. This particulate a mmonium is represented in the modeling as sulfate (SO 4 ) emissions. Thus, EPA and AECOM both accounted for ammonia slip through additional sulfate emissions, rather than by incorporating ammonia slip into the ambient background ammonia concentrations.

C. Sulfuric Acid

Sulfuric acid (H 2 SO 4 ) is formed from coal-fired pow er plants from the oxidation of sulfur dioxide (SO 2 ) to sulfur trioxide (SO 3 ) and the subseque nt reaction of SO 3 with water vapor (SO 3 + H 2 O = H 2 SO 4 ). Sulfuric acid (also known as su lfuric acid mist) can combine with ammonia to form particulate ammonium sulfate, wh ich is an important cont ributor to visibility impairment. CALPUFF models emissions of H 2 SO 4 as inorganic particulate sulfate.

Sulfuric acid emissions from power plants must be reported to the Toxic Release Inventory (TRI) and can be calcula ted by estimating the amount of H 2 SO 4 produced and the

amount of H 2 SO 4 removed by control equipment using in formation from the Electric Power Research Institute (EPRI). 203 These calculations rely on assumed values for the amount of fuel

sulfur converted to SO 2 , the amount of SO 2 oxidized to SO 3 , and the amount of H 2 SO 4 lost to (or mitigated by) the air preheater and applicable control equipment, such as hot-side ESPs and

201 U.S. Environmental Protection Agency, EPA-454/B-03-005, September 2003, on web page http://www.epa.gov/ttn/oarpg/t1pgm .html, with direct link http://www.epa.go v/ttn/oarpg/t1/memora nda/rh_envcurhr_gd.pdf

202 AECOM’s modeling of FCPP used the annual average de civiews from the guidance document, and calculated the background soil concentrations that would yield those deciviews; the soil concentrations were used by AECOM in the CALPOST visibility, a single value for the entire year irrespective of relative humidity.

203 Sulfuric acid emissions can also be measured using source tests, but source tests are typically not required unless the facility has a sulfuric acid emissions limit. NGS does not have a sulfuric acid emission limit, and is therefore not required to measure sulfuric acid emissions. However, SRP agreed to conduct sulfuric acid sour ce tests on each unit in 2009. We discuss

the results of these tests later in this TSD.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 97 of 129 FGDs. The assumed values are based on averages from a limited number of measurements, or in some cases, single measurement points, and are not specific to NGS or coal from the Kayenta

Mine. Limited stack test data of H 2 SO 4 emissions from NGS are available, however it is not possible to know the individual production and loss terms for H 2 SO 4 in the system because separate measurements of H 2 SO 4 up and downstream of the various ductwork components were not conducted. Therefore, baseline and post-SCR estimates of H 2 SO 4 from NGS are based on the

best current information available from EPRI 204 and other sources.

D. NGS Approach to This Factor

1. AECOM Modeling Inputs

In our ANPRM, we summarized the emission inputs and modeling results AECOM submitted for NGS. Although AECOM included SNCR in addition to LNB and SCR in their modeling, we focused on the LNB and SCR control scenarios. The inputs for the baseline case (Scenario A), and LNB/SOFA (Scenario B), and SCR (Scenarios C – E) cont rol scenarios are repr oduced here in

204 Electric Power Research Institute, Estimating Total Sulfuric Acid Emissions from Stationary Power Plants , 1016384, Technical Update, March 2008.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 98 of 129 Table 27. The modeling scenarios specifi cally presented in the ANPRM were:

Aa = Baseline Visibility Impacts modeled by AECOM, Ae = Baseline Visibility Impacts modeled by EPA, Ba = Visibility Impacts after LNB+SOFA applied to Units 1 – 3 modeled by AECOM, Be = Visibility Impacts after LNB+SOFA applied to Units 1 – 3 modeled by EPA, Ca = Visibility Impacts after SCR+LNB+SO FA on Units 1 and 3, LNB+SOFA on Unit 2 modeled by AECOM, Ce = Visibility Impacts after SCR+LNB+SO FA on Units 1 and 3, LNB+SOFA on Unit 2 modeled by EPA,

De 205 = Visibility Impacts after SCR+LNB+SOFA on Units 1 and 3, Half-SCR+LNB+SOFA on Unit 2 modeled by EPA, Ea = Visibility Impacts from SCR+LNB+SO FA on Units 1 – 3 modeled by AECOM, and Ea = Visibility Impacts from SCR+LN B+SOFA on Units 1 – 3 modeled by EPA.

205 AECOM did not model this scenario.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 99 of 129 Table 27: AECOM Mo deling Inputs (lb/hr)

Scenario A – Baseline

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 4.18 4.48 4.36

NO

x 4,271.42 4,207.50 4,181.67

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05

Scenario B – LNB/SOFA on Units 1 – 3

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 4.18 4.48 4.36

NO

x 2,110.74 2,261.63 2,197.78

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05 Scenario C – SCR + LNB/SOFA on Units 1 and 3, LNB/SOFA on Unit 3

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 64.01 4.48 66.65

NO

x 703.58 2,261.63 732.59

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05

Scenario E – SCR + LNB/SOFA on Units 1 – 3

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 64.01 68.59 66.65

NO

x 703.58 753.88 732.59

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05

Note that although the control technology scenar ios may be the same (e.g., SCR on Units 1 – 3), the assumptions and % control le vels may differ between the mode ling conducted by AECOM and EPA. For example, AECOM and EPA made different assumptions in calculating emissions of H 2 SO 4 , which

resulted in different SO 4 emission rate inputs for the modeling.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 100 of 129 Table 28 outlines the assumptions used by AE COM for the sulfuric acid calculation.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 101 of 129 Table 28: Assumptions Used by AECOM for H 2 SO 4 Emission Estimates

Units 1 – 3

Maximum Sulfur content of coal 0.593

Conversion of SO 2 to H 2 SO 4 via SO 3 due to combustion (%) 0.11%

Conversion of SO 2 to SO 3 due to SCR (%) 1%

H 2 SO 4 penetration 206 through air preheater 0.9

H 2 SO 4 penetration through hot-side ESP 0.63

H 2 SO 4 penetration through wet FGD 0.47

As discussed above, in addition to emissions from the facility, the background ammonia concentrations must be specified for the m odel. The IWAQM default value for ammonia background is 1 ppb year-round (discussed be low). AECOM used background ammonia

concentrations based on concentrat ions used for the PSD ambient air quality impacts analysis for the Desert Rock Energy Center. Table 29 co mpares the IWAQM default values with the ammonia values used by AECOM.

Table 29: Ammonia backgr ound concentration in ppb

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec IWAQM default 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

AECOM values 0.2 0.2 0.5 0.5 1.0 1.0 1.0 1.0 1.0 0.5 0.5 0.2

2. Results of AECOM CALPUFF modeling

AECOM presented various control scenarios’ vi sibility improvements in terms of the 98th percentile (8th highest) of the daily maximum delta deciviews from CALPUFF for each Class I area, averaged over 2001 – 2003. As outlined in the 1999 Regional Haze rule (64 FR 35725, July 1, 1999), a one deciview change in visibility impairment is a small but perceptible change under most circumstances when viewing scen es in a Class I area.

206 Sulfuric Acid removal efficien cy = (1 - Penetration ) x 100%Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 102 of 129 Table 30 presents the impact of NGS on visibility at each Class I area, based on the 98th percentile of daily maxima from 2001 – 2003, as modeled by AECOM. SRP assessed visibility impacts individually for each Class I area, howev er, in our ANPRM, we summed the impacts at all Class I areas as part of the assessment of the overall impact of NGS on visibility.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 103 of 129 Table 30: Impacts of NGS on Visibility (98 th Percentile of daily maximum dv) at Eleven Class I Areas as Modeled by AECOM and as reported by EPA in ANPRM
Visibility Impact (dv) after applying: Baseline (A) LNB+SOFA (B) SCR+LNB+SOFA and LNB+SOFA (C) SCR+LNB+SOFA (E)

Arches 2.05 1.51 1.19 0.99 Bryce Canyon 2.00 1.58 1.36 1.23 Canyonlands 2.47 1.96 1.53 1.35 Capitol Reef 2.68 2.31 2.06 1.89 Grand Canyon 2.56 2.29 2.25 2.29

Mazatzal 0.71 0.47 0.41 0.38

Mesa Verde 1.42 1.04 0.77 0.58

Petrified Forest 1.52 1.14 0.92 0.76

Pine Mountain 0.66 0.46 0.38 0.34 Sycamore Canyon 1.31 0.92 0.78 0.63

Zion 1.83 1.47 1.26 1.10

Sum of Class I areas 19.29 15.15 12.88 11.54

E. Discussion of Factor in EPA ANPRM

1. Sulfuric Acid Emission Estimates

In our ANPRM, we disagreed with certai n assumptions used by AECOM for NGS to calculate the sulfuric acid emissions, in particular, the rate of SO 2 to SO 3 oxidation from the SCR catalyst and the amount of sulfuric acid that pene trates through (or is lo st to) the air preheater. We used an air preheater penetration factor of 0.49 in the ANPRM, whereas AECOM assumed 0.9, and we used an SO 2 to SO 3 conversion rate of 0.5% from the SCR catalyst, whereas AECOM assumed 1%. Although it is not discussed specifically in the Federal Register Notice for the ANPRM, EPA also revised the control effi ciency of sulfuric ac id in the hot-side ESP from 37% used by AECOM to 0%.

2. Ammonia Background Concentrations

In our ANPRM, we described the method we used to a estimate ammonia background concentrations that we determined to be appr opriate for the CALPUFF m odeling to represent the

amount of available ammonia that emissions fr om NGS would encounter on the way to a given Class I area. Because very little monitored ammonia data is available, the IWAQM Phase 2

document 207 recommends a default ammonia background va lue, which is 1 ppb for arid regions. Alternative levels may be used if supported by data. In th eir January 2008 BART modeling protocol (p. 4-1) SRP expresse d the concern that CALPUFF over-p redicts ammonium nitrate in winter. On the other hand, the USDA Forest Serv ice expressed the concern that ammonia levels used by AECOM were too low, partly based on measurements in the Four Corners area. 208

207 Interagency Workgroup On Air Quality Modeling (IWAQM ) Phase 2 Summary Report And Recommendations For Modeling Long Range Transport Impacts (EPA-454/R-98-019), EP A OAQPS, December 1998, http://www.epa.gov/scram001/7t hconf/calpuff/phase2.pdf

208 Personal communication, Rick Graw, USDA Forest Service to Scott Bohning, EPA, February 2, 2009.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 104 of 129 To address these concerns using an object ive approach based on monitored data, EPA estimated ammonia background for all Class I ar eas (except Mesa Verd e National Park, see below) by a back-calculation from measuremen ts at monitors run by the IMPROVE program. 209

IMPROVE monitors do not measure ammonia direc tly; rather, they measure particulate sulfate and nitrate. In the atmosphere, particulate sulfate and nitrate are essentially all in the form of

ammonium sulfate and ammonium nitrate, respectively. Using th e chemical formulas of these compounds, EPA calculated the amount of ammonia needed to combine with gaseous sulfate and nitrate in order to form the measured partic ulate sulfate and nitrate. The formulas are respectively (NH 4 ) 2 SO 4 and NH 4 NO 3 , so there must be two ammonia molecules (NH 3 ) for each sulfate (SO 4 ), and one ammonia for each nitrate (NO 3 ). The IMPROVE measurements are in μg/m 3 (NH 3 mass per volume of air), while CALPU FF ammonia input must be in ppb (NH 3 volume per volume of air), so results must be co nverted to ppb using the ideal gas law, which depends on temperature and pressure. Since te mperature and pressure are not available at IMPROVE sites, a standard atmosphere was assumed 210 (pressure of 1 atm = 101.325 kPa; temperature = 298.16 K = 25° C). The result of the calculation is a 24-hour average ammonia estimate in ppb for each monitor and for each measurement day (typically every 3 rd calendar day).

The monthly values required by CALPUFF were based on these daily values, as described below. The estimate represents a lower bound on the ammonia that must have been present; it does not include any ammonia remain ing in gaseous form, since the latter is not reflected in the particulate sulfat e and nitrate measured at the m onitor. For the ANPRM and this proposal EPA consulted with the FLMs on using this method. EPA recognizes that it is not perfect, but the lack of monitored ammonia data and the limitations in how the CALPUFF model uses ammonia make it a reasonable approach th at does rely on available measured data.

For the ANPRM, EPA performed this back-c alculation using 2005-2007 data for all 14

IMPROVE monitors at Class I areas in the mode ling domains. For each monitor, EPA used the

maximum calculated value for each calendar mo nth to represent the month. Then, for each month, EPA averaged over all monitors, 211 resulting in a single valu e for each of the 12 calendar months. For the months of May and July, this back-calculation resulted in a somewhat lower

value than the IWAQM default of 1 ppb which was also used by SRP; for these months EPA used 1 ppb. The back-calculation results ranged from 0.7 ppb in the winter to 1 ppb in summer, except for the value of 1.3 ppb in June.

As a basic check in the ANPRM on the reasonableness of the ammonia background concentrations, EPA compared the nitrate m easured at the Grand Canyon with the nitrate predicted by CALPUFF for Nava jo Generating Station. EPA f ound that the predicted values were within the range of observed values, though at the high end. Thus they have a degree of conservatism while remaining realis tic. In the real atmosphere, NO

x from many sources competes with NGS for the available ammonia. But for purposes of modeling visibility impacts relative to natural background, i.e. the situation for which there are no anthropogenic sources, it

is reasonable to assume the ammonia is all availa ble for reacting with the pollutants in the plume

from NGS.

209 Interagency Monitoring of Protected Visual Environments http://vista.cira.colostate.edu/improve/

210 The Class I areas are at higher elevations than used in the standard atmosphere, so pressure and also temperature would be lower. Since these work in opposite directions in the formula fo r converting to ppb, these effect s tend to cancel each other. In any case the net effect is small relative to that of the other uncertainties and assumptions in the method.

211 Results from Zion were not used, as they were incomplete and also appeared anomalous.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 105 of 129 Ammonia background concentrations for Mesa Verde National Park were derived from

measured ammonia concentrations in the F our Corners area, as described in Sather et al.

, (2008). 212 Monitored data was available within th e park, but because particulate formation happens within a pollutant plume as it travels, ra ther than instantaneously at the Class I area,

EPA also examined data at locations outside the park itself. Monitored 3-week average ammonia at the Substation site, some 30 miles south of Mesa Verde, were as high as 3.5 ppb, though generally levels were le ss than 1.5 ppb. Maximum values in Mesa Verde were 0.6 ppb, whereas other sites' maxima ranged from 1 to 3 ppb, but generally values were less than 2 ppb. EPA used values estimated from Figure 5 of Sather et al. , (2008), in the mid-ra nge of the various stations plotted. The results ranged from 1.0 ppb in winter to 1.5 ppb in summer. See Table 31.

Table 31: Ammonia background concentrations in ppb determined by EPA used in ANPRM

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

All Class I areas 0.8 0.7 0.7 1.0 1.0 1.3 1.0 1.0 1.0 1.0 1.0 0.9

Values for Mesa Verde only 1.0 1.0 1.3 1.3 1.3 1.3 1.5 1.5 1.5 1.5 1.3 1.0

3. Hydrogen Chloride and Hydrogen Fluoride

AECOM did not include estimates of hydrogen chloride (HCl) or hydrogen fluoride (HF) in their visibility modeling. During discussi ons with the FLMs prio r to our ANPRM, the National Park Service (NPS) recommended that we address HCl and HF emissions for their potential to impact visibility. HCl is known to have the capacity to react with ammonia to form particulate ammonium chloride. Therefore, alth ough HCl and HF emissions are not included in the WRAP modeling protocol, EPA estimated emi ssions of these compounds and included them in the visibility modeling as fine PM, 213 and provided a detailed di scussion of our emissions

estimates in the ANPRM.

4. Alternative Visibility Metrics

In the ANPRM, we presented four ways to e xpress the visibility improvement from the NO

x and PM control technologies: (1) deciview impairment at each Class I area, (2) the sum of the impairment at all areas, (3) the percentage change in deciview impact s compared to the baseline at each area, and (4) a

metric that accounts for the size of the land area ov er which controls provide visibility benefits. The visibility benefits re ported in the ANPRM are reproduced below (see Table 32, Table 33, and

212 Mark E. Sather et al. , 2008. “Baseline ambient gaseous ammonia concen trations in the Four Corners area and eastern Oklahoma, USA”. Journal of Environmental Monitoring, 2008, 10, 1319-1325, DOI: 10.1039/b807984f

213 NPS recommended HCl and HF be included in the category “condensable organic PM”. For CALPUFF modeling, EPA included HCl and HF into fine PM instead of condensable organic PM because they are inorganic, and because they are not subject to the chemistry in CALPUFF th at is specific to organic compounds.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 106 of 129 Table 34). Note that these tables from the ANP RM report the anticipate d visibility impairment after applying NO

x controls, where as other tables in this document report the visibility improvement after applying controls (Visibility Improvement = Baseline Visibility Impairment – Visibility Impairment after C ontrols). Each visibility metric described above has advantages and disadvantages. Their absolute worth is somewh at in the eye of the be holder, but all of them provide useful information on visibility impact s, as long as their i nherent limitations are understood. Deciview improvement at each Class I area is the primary metric under the BART guidelines. The third and four th of the metrics, percentage and land area weighting, are

described below.

Table 32: Visibility Impairment ( 98th Percentile dv) of NGS on Eleven Class I Areas as Modeled by EPA as reported in our ANRPM
Visibility Impact (dv) after applying:

Baseline (dv) LNB (B) SCR (C) (SCR 1&3) SCR (D) (1/2 SCR) SCR (E) (SCR 1 – 3)

Arches 3.25 2.08 1.33 1.16 0.89 Bryce Canyon 3.66 2.44 1.57 1.39 1.10 Canyonlands 4.37 2.98 1.90 1.65 1.25 Capitol Reef 5.48 4.08 2.97 2.71 2.04 Grand Canyon 5.41 4.35 3.34 3.06 2.46

Mazatzal 1.16 0.73 0.48 0.45 0.37

Mesa Verde 2.24 1.33 0.78 0.67 0.52

Petrified Forest 2.62 1.54 1.00 0.86 0.66

Pine Mountain 1.08 0.64 0.42 0.38 0.32 Sycamore Canyon 1.96 1.28 0.80 0.71 0.59

Zion 3.73 2.65 1.65 1.44 1.05

Sum of Class I

areas 34.95 24.10 16.25 14.48 11.23

Table 33: Percent Improvement in Deciview Impair ment based on EPA modeling for Each Class I Area

from NO

x Controls at NGS as reported in ANPRM
Visibility Impact (dv) after applying: LNB (B) SCR (C) (SCR 1&3) SCR (D) (1/2 SCR) SCR (E) (SCR 1 – 3)

Arches 36% 60% 65% 74% Bryce Canyon 26% 47% 53% 63% Canyonlands 32% 56% 62% 71% Capitol Reef 25% 48% 53% 63% Grand Canyon 22% 43% 48% 58%

Mazatzal 38% 60% 65% 72%

Mesa Verde 40% 63% 68% 76%

Petrified Forest 36% 60% 65% 74%

Pine Mountain 38% 59% 64% 71% Sycamore Canyon 36% 59% 64% 72%

Zion 31% 54% 60% 69%Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 107 of 129 Table 34: Alternative Visibility Metric as reported in ANPRM 214

Visibility Impairment (dv-km 2 ) after applying:

Baseline (dv-km 2 ) LNB (B) SCR (C) (SCR 1&3) SCR (D) (1/2 SCR) SCR (E) (SCR 1 – 3)

Arches 812 514 336 293 223 Bryce Canyon 495 324 212 187 147 Canyonlands 4649 3071 2022 1741 1320 Capitol Reef 4184 3127 2233 2031 1566 Grand Canyon 21,399 17,219 13,157 12,033 9698

Mazatzal 978 618 410 367 297

Mesa Verde 383 226 135 115 87

Petrified Forest 847 515 313 270 217

Pine Mountain 72 44 28 25 22 Sycamore Canyon 390 235 162 144 120

Zion 1574 1104 739 649 494

Sum of Class I

areas 35,783 26,997 19,747 17,855 14,191

The motivation for the second and fourth metr ics, which involve sums over Class I areas, is to provide a single number for comparing control scenarios to each other. There are multiple Class I areas, with different visibility impacts for each, but there is no established metric for expressing visibility impact considering all ar eas together in a single number. The overall impact can be assessed more or less intuit ively, weighing the various area impacts and the

number of affected Class I areas. As an altern ative to such intuitive or implicit weighing, in the ANPRM, EPA presented two explicit metrics, described below.

For the percentage metric, EPA used least-s quares regression analyses of the visibility modeling results from the 2001 – 2003 modeling pe riod to determine the percent change in deciview impacts resulting from the applica tion of control technologi es compared to the baseline. The percent change is equal to one minus the slope from linear regression of the control scenario’s daily delta deciviews against those of the baseline. Data from all modeled days was used, not just the highest impact days. Ba sed on the modeling we conducted for the ANPRM, we estimated delta deciview improvements of 58 – 76% from SCR+LNB/SOFA on all 3 units,

and 22 – 40% from LNB/SO FA on all 3 units.

The percentage metric is not intended to re present the visibility improvement relative to current conditions, which include impacts from other anthro pogenic and nonanthropogenic sources; 76% improvement does not mean that visibi lity impairment in the current atmosphere is reduced by that amount. Rather, it represents improvement in just the NGS contribution to impairment. By the nature of percentages, a featur e of this metric is that when baseline impacts are small, even a small deciview benefit from co ntrols may give a large percentage improvement. Conversely, when baseline impacts are high, even a relatively large deci view improvement may

214 In the ANPRM, EPA mistakenly reported the sum of all Class I areas for the alternative visibility metric for Baseline (reported as 24,943), Scen ario B (19,708), Scenario C (19,708), Scenario D (15,716), and Scenario E (19,708).

Table 34: Alternative Visibility Metric as reported in ANPR Mreports the correct sums over all Class I Areas for the alternative visibility metric.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 108 of 129 give only a modest percentage improvement. Th is metric emphasizes relative improvements in NGS’s impairment contribution over absolu te deciview improvements in visibility.

For the land area metric, we multiplied the 98th percentile delta deciviews for each Class I area by its land area in km 2 , giving a size-weighted measure of visibility improvement. We presented these for each Class I area, and also th e sum of these for all Class I areas together. This weighting by land area reflects the fact that a larger Class I area will have a visibility improvement at more locations than a smalle r area. The Grand Canyon has a land area of 3972

km 2 , so this metric gives substantially more we ight to improvements there than to the Black Canyon of the Gunnison, with an area of only 53 km 2 , whereas a simple sum of deciviews weights them equally. The main effect of the land area metric, as compared to a simple sum of deciviews, is to give greater weight to the la rger Class I areas such as Canyonlands, Capitol Reef, West Elk, and especi ally the Grand Canyon.

The simple sum of delta deciviews consider s each Class I area to be equally important, while the land area weighted sum considers larger areas to be more important, reflecting the fact that a larger Class I area will have a visibility improvement at more locations than a smaller area. A feature of the metric is that a relatively sm all improvement at a large area would count more than a large improvement at a small area. We ighting by land area can seem reasonable or not, depending on how relevant one considers the par ticular sizes of the Cl ass I areas defined by Congress, and how relevant the magnitude of an improvement is in comparison with the land area experiencing that improvement. A defect of the land area metric is that it assumes that the visibility improvement is the same at every lo cation within a given Class I area; in reality visibility impacts and improveme nts vary in time and space. A more elaborate metric could consider this variation, and even the number of visitors at va rious times of year, the specific locations they visit, and the degree of enjoyment they experience. The weighted land area metric considers the relative sizes of Class I areas, but in a way that can easily be calculated, unlike

those elaborations.

F. Affected State, Tribe, and FLM Consultation

1. Baseline Visibility Impacts of NGS

The Navajo Nation commented that coal-f ired power plants are relatively small contributors to regional haze in the surrounding Class I areas based on studies by the Grand Canyon Visibility Transport Commission and th e Western Regional Air Partnership (WRAP),

which estimated that NO

x emissions from stationary sources probably cause 2 – 5% of visibility impairment on the Colorado Plateau. 215

The estimate from the initial WRAP assessm ent of the visibility impairment from stationary sources is based on the 20% worst visibility days on the Colorado Plateau. WRAP determined that on those worst visibility days, visi bility impairment from particulate nitrates is 6 – 18%. Because stationary source s contributed 25% of the WRAP NO

x emissions inventory, WRAP estimated that stationary sources were re sponsible for 25% of the visibility impairment

215 Stationary Source NO

x and PM Emissions in the WRAP Region: An Initial Assessment of Emissions, Controls, and Air Quality Impacts – Final Report of the WRAP Market Trading Forum. October 1, 2003. http://www.wrapair.org/f orums/mtf/nox-pm.html.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 109 of 129 (i.e., 25% of 6 – 18% = 2 – 5%). However, the 2003 WRAP report further states that upon cursory examination of the daily data collect ed in 2001 on the Colorado Plateau, some of the 20% worst days are dominated by particulate ni trate and exceed the annual average. WRAP provided a few examples of nitrate contributions to visibility impairment ranging from 31 – 55%. EPA notes that there is likely to be much gr eater variability in the nitrate contribution to visibility impairment than suggested by the WRAP estimate of 2 – 5% based on a 20% subset of

annual data.

2. Sulfuric Acid Emission Estimates

The Navajo Nation supported the penetration factor for the air preheater relied on by SRP

in its calculations for sulfuric acid emissions , but encouraged EPA to use measurement data when available. The Nation pointed to EPA’s re quest to SRP to conduct source tests to measure current (baseline) sulfuric acid emissions fr om Navajo Generating St ation and recommended we

review the test results and revi se the modeling as necessary.

3. Ammonia Background Levels

The Arizona Department of Environmental Quality (ADEQ) stated 216 that since the backcalculation method only indirectly estimates ammonia via measuremen ts of sulfate and nitrate, it may not qualify as “specific data... availa ble for the modeling domain”, which the IWAQM

Phase 2 document recommends if alternatives to the 1 ppb default are to be used. 217 This can be interpreted as an implicit ADEQ recommendation fo r staying with the 1 ppb default. ADEQ also expressed concern that the back-calculation method for estimating ammonia background may over-estimate the concentration, be cause it relies on particulate su lfate and nitrate measurements that a) already include the effect of NGS em issions, leading to “doubl e-counting”, and b) may have formed due to distant sources, rather than having been formed locally. Finally, ADEQ further recommended additional ammonia monitoring for assessment of the accuracy of the

back-calculation method.

The National Park Service and the U.S. Forest Service (NPS and FS, and together,

FLMs 218 ) supported the back-calcula tion methodology and results we presented in the ANPRM.

The FLMs determined the back-calculation me thod was more comprehensive because it

considers both ambient ammonia measurements at specific locations within the modeling domain

and the amount of ammonia that must have been present along the tran sport path from the

emissions sources to the Class I areas. Becau se CALPUFF uses of only a single value for monthly concentrations to repr esent ammonia, which shows si gnificant spatial and temporal variability, the FLMs determined that it is most appropriate to consider the amount of ammonia along the regional transport path in the ammonia background value. Additionally, the FLMs recommended that the modeling results be used in a relative sense for comparing control

216 ADEQ, October 28, 2009 comment letter to EPA’s ANPRM docket, comments 12- 17 (electronic file “10-28-09 Grumbles.pdf”)

217 IWAQM Phase 2 document, section 2.2.2, p.14

218 The U.S. Fish and Wildlife Service is also a Federal Land Ma nager in charge of National Wildlife Refuge Class I areas. No refuges are within the 300 km modeling domain of FC PP and EPA did not receive comments on our ANPRM from the U.S. FWS – National Wildlife Refuge System – Branch of Air Quality, therefore we use the term FLM in this proposal to refer only to the National Park Service and the Forest Service. The FWS – Ne w Mexico Biological Services Field Office did submit comments on the ANPRM, bu t in the capacity of a FLM of an impacted Class I area.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 110 of 129 technologies rather than conti nue disagreement over the absolute values used for the background ammonia. However, the Forest Service s till recommended placing more emphasis on the visibility results from EPA modeling using back -calculated ammonia values. The Navajo Nation supported the use of ambient measurements wher e possible and noted th at Salt River Project (SRP), primarily in the interest of Navajo Ge nerating Station, has installed ammonia monitors near Grand Canyon National Park to better in form background ammonia levels for CALPUFF modeling. SRP provided the results of the monitoring study to EPA in September 2010. 219

4. Additional Modeling Results

During our consultations with the FLMs prior to our ANPRM, NPS commented that AECOM likely underestimated visibility impact s of the facilities because AECOM modeled inorganic condensable particulate matter as only sulfuric acid mist. NPS conducted their own CALPUFF modeling analysis (See Tabl e 35) to estimate visibility be nefits of controls and used

AECOM estimates for SO 2 and NO

x and NPS estimates of PM emissions and background ammonia. Although NPS supported our use of b ack-calculated ammonia background values, for comparison purposes, NPS used a year-round background ammonia concentration of 1 ppb, consistent with the IWAQM default. NPS submitted its comments on AECOM’s BART analysis for NGS to EPA by letter dated July 24, 2009, just prior to EPA’s publication of the ANPRM. EPA posted the NPS letter and appendices 220 to the docket for the ANPRM.

Table 35: NPS Modeling Results – Average 8 th High Baseline and Delta dv Improvement from 2001 –

2003

Class I Area Baseline Impact Improvement from

LNB/SOFA Improvement From SCR +

LNB/SOFA

Arches 3.857 1.360 2.643 Bryce Canyon 4.222 1.058 2.377 Canyonlands 5.104 1.689 3.365 Capitol Reef 6.127 1.047 3.034 Grand Canyon 6.609 1.131 2.893

Mazatal 1.121 0.442 0.693

Mesa Verde 2.154 0.867 1.523

Petrified Forest 2.784 1.006 1.930

Pine Mountain 1.195 0.474 0.808 Sycamore Canyon 2.261 0.885 1.550

Zion 3.808 1.099 2.386

Total 39.242 11.058 23.201

5. Visibility Metrics

The FLMs supported our consideration in the ANPRM of the cumulative visibility improvement anticipated at all of the impact ed Class I areas. However, the FLMs did not support the alternative vi sibility metric we introduced in the ANPRM that multiplies the 98 th

219 Measurements of Ambient Background Ammonia on the Colorado Plateau and Visibility Modeling Implications, Prepared by Salt River Project, Contributors: Ivar Tombach and Robert Paine, September 2010.

220 See document IDs 0017 and 0036 in the ANPRM docket: EPA-R09-OAR-2009-0598 at www.regulations.govTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 111 of 129 percentile change at the highest receptor by the land area of the Class I areas because the metric values larger Class I areas more than smalle r Class I areas. Instead, NPS and FS discussed alternatives to our area-weighted visibility metrics. FS discu ssed two different techniques for accounting for visibility impacts over multiple days at multiple Class I areas. The first technique sums the daily maximum receptor deciview impacts, over 365 days, at all Class I areas in the modeling domain to yield a metric in units of $/Class I area dv -day (dollar per Class I area deciview-day). The second technique is simila r to the first, but the single daily maximum receptor is chosen from all of the Class I areas in the modeling domain pooled together, yielding a metric in units of $/dv-day.

NPS introduced another visibility metric cal led the pollutant effectiveness (PE) factor, which is the visibility improvement (in dv) divi ded by the annual emission reduction (in tons). NPS uses the PE factor to estimate visibility improvement resulting from the proposed controls on each EGU individually, without modeling each E GU separately. NPS then uses the estimated visibility improvement from each EGU to derive uni t-specific dollar per dv values for the various

control scenarios. Based on th eir modeling and cost analyses, NPS estimates that the cost effectiveness of SCR ranges from $1.9 – 2.7 million per dv, in contrast to SRP’s cost effectiveness of $12.7 – 17.4 million per dv. N PS asserts that SRP’s costs for SCR are overestimated and visibility benefits are underestimated, but acknow ledge that there are

considerable uncertainties and differences betw een the approaches used by SRP and NPS to

derive their cost estimates. To create a “middle-ground” estim ate, NPS combined the cost estimates from SRP and their own visibility mode ling results to calculate cost effectiveness values of $4.9 – 6.6 million per dv. Considering a $17 million per dv reasonable cost benchmark based on other facilities, NPS determined that al l estimates of cost effectiveness, including SRP’s upper range cost estimates for SCR and lower range estimates for visibility improvements, are at or below the benchmark, and thus NPS conc luded that SCR is BART for all units at NGS.

Various ANPRM commenters objected to our use of the land area weighted metric described in the ANPRM on grounds of its seem ing artificiality, its complexity, and its unfamiliarity. Any metric entails judgements about the relative importance of the magnitude, frequency, and spatial coverage of visibility improvements; this is especially so for a metric that combines impacts from multiple Class I areas, since it assigns an importance to each area relative to the others. Without guidance or general ag reement on these various judgements, discussion

tends to focus on the merits of the metric itself rather than on the visibility implications of its calculated value. For this proposal EPA did not calculate or consider the land area weighted

metric.

G. EPA Conclusions Regarding this Factor

EPA remodeled the visibility impacts of NG S using emission inputs based on revisions to (1) our sulfuric acid emissions calculation – the hot-side ESP pe netration factor (from 1 to 0.63), the air preheater penetration f actor (from 0.49 to 0.50), and the SO 2 to SO 3 conversion efficiency of the SCR catalyst (from 0.5% to 0.67%), (2) HCl and HF emissions in the fine PM input to CALPUFF, (3) background ammonia estimates using the IWAQM 1 ppb default, and (4) two

NO

x control levels to 0.08 lb/MMBtu and 0.05 lb/ MMBtu, as discussed in Section 3.D of this

TSD.

1. Sulfuric Acid Emission EstimatesTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 112 of 129 SRP submitted comments regarding our assumptions in the ANPRM. The following discussion provides a brief summary of each assu mption used in the sulfuric acid emissions calculation, and a more detailed rationale for the two cases where EPA disagreed with the assumption used by AECOM, i.e., SO 2 to SO 3 oxidation from the SCR cata lyst and loss in the air preheater.

The amount of fuel sulfur that is oxidized to SO 2 is estimated for three different coal types. Hardman et al. (1998) 221 report sulfur conversion to SO 2 (based on AP-42) to be 0.95 for bituminous coal, 0.875 for subbituminous coal, and 0.55 – 0.85 for lignite coal, based on sodium (Na) content. AP-42 explains th at the alkaline nature of sub-bi tuminous coal ash results in some

of the sulfur to form sulfat e salts, reducing the amount of SO 2 in the flue gas. EPA agrees with SRP that the ash generated at NGS ha s relatively low available alkalinity, 222 therefore AECOM and EPA both rely on the value of 0.95 for estimating SO 2 production from fuel sulfur.

For coal-fired power plants without SCR, SO 3 is only formed during the combustion process. The amount of SO 2 that is oxidized to SO 3 during combustion depe nds on coal type and the type of boiler. Measurements of SO 3 production show a wide range (0.00111 – 0.016) but many of the values reported in the EPRI 2008 document are based on single measurements.

EPRI 2008 and Harrison 2005 223 both report the SO 3 production factor from Western bituminous coal from dry bottom boilers to be 0.00111, or 0.111% of SO 2 production, and AECOM and

EPA both used this value.

For coal-fired power plants with SCR, SO 3 is also formed as a result of oxidation of SO 2 to SO 3 on the SCR catalyst. As discussed in Sec tion 3 of this document, AECOM assumed a 1%

conversion of SO 2 to SO 3 across the SCR catalyst layers, whereas EPA used 0.5% conversion efficiency in our ANPRM because low conversi on catalysts are commercially available to specifically reduce H 2 SO 4 formation following the application of SCR. In its comment letter to EPA on the ANPRM, SRP agrees with EPA that u ltra low oxidation catalyst can be used. In 2010, based on information EPA submitted to Hit achi Power Systems America regarding NGS, Hitachi guaranteed that a total 0.5% conversion of SO 2 to SO 3 using 3 layers of CX series catalyst, can be achieved while controlling NO

x by 80 – 90%. 224 After an initial 16,000 hours of use, an additional layer of catalyst would be used, adding an additional 0.167% conversion. In our ANPRM, we did not account for the addi tional conversion resulting from the 4 th layer of catalyst. Therefore, we now use 0.67% SO 2 to SO 3 conversion in our calculations, which is the maximum conversion rate when using 4 layers of catalyst assuming a 3+1 system to achieve 0.05 lb/MMBtu. In our modeling, we also include a scenario where we assume a 2+1 system to

achieve 0.08 lb/MMBtu with a 0.5% SO 2 to SO 3 conversion rate. Although comments submitted by the Environmental Consortium recommend usi ng a 0.1% conversion rate, EPA relied on the vendor guarantee. EPA recognizes that the rate achieved may be lower than the guarantee, however, to be conservative, EPA has determined that maximum conversion rate with all layers in use is most appropriate for our sulfuric acid estimates used in the visibility modeling. EPA

notes that SRP revised its cost an alysis to include the cost of the ultra low conversion catalyst.

221 Hardman, R., R. Stacy, E. Dismukes. Estimating Total Sulfuric Acid Emissions from Coal-Fired Power Plants. Southern Company Services, Revised September 1998.

222 APS Comments on ANPRM (See EPA-R09-OAR-2009-0598-0195).

223 Harrison, K.E., L.S. Monroe, J.E. Cichanowicz, Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: Revision 3 (2005). Southern Company Services, October 2005.

224 Anthony Favale, Hitachi Power Systems America to Anita Lee, electronic mail, April 21, 2010.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 113 of 129 At NGS, H 2 SO 4 removal can occur in the hot-side E SPs, air preheaters, and wet FGDs. In its modeling for NGS, AECOM assumed a sulfuric acid removal efficiency through the hot-side ESP of 37% (or a penetration factor of 0.63). In the modeling EPA conducted for the ANRPM, EPA assumed a penetration factor of 1, i.e., no sulfuric acid remova l by the hot-side ESP. Although EPA inadvertently did not provide an explanation in the ANPRM for our use of a penetration factor of 1 for the hot-side ESP, EP A expected that temperatures within the hot-side ESP would be too high for efficien t capture of sulfuric acid in th e hot-side ESP. In its comment letter to EPA on the ANPRM (see page 42), SRP st ated that a control efficiency from the hotside ESP of 37% should be used. The 2008 EPRI report similarly recomme nds use of a control efficiency of 37% for hot-side ESPs and all coal types based on one measurement at one facility. EPA believes there is also considerable uncertainty regarding how much sulf uric acid will be lost to the hot-side ESP, however, the best availabl e information on hot-side ESP control efficiencies for sulfuric acid appears to be the only avai lable information, theref ore, as recommended by SRP, EPA used a control efficiency of 37% in our modeling (penetrati on actor of 0.63), and is requesting comment on this penetration factor and whether additional information on removal

efficiencies from hot-side ESPs is available.

Specific air preheater remova l efficiencies were not available from EPRI 2008 and other references for non-Powder River Basin (PRB) Western bituminous coal, and only one datum point is available for PRB coal. EPRI 2008 re ports penetration factor s of 0.49 (Low Sulfur Eastern Bituminous coal), 0.85 (Med-High Sulfur Eastern Bituminous coal) and 0.56 (PRB coal).

Most data is available for low- sulfur Eastern bituminous coal: measurements from eight units show a range of percent removal from 0 – 69%. Before calculating the average % removal of

H 2 SO 4 observed from low-sulfur Eastern b ituminous coal, EPRI 2008 and Harrison 2005

excluded the 0% removal value because “the data point showing 0% remo val at approximately 600 ppm SO 2 is believed suspect, as an identical comp anion unit firing the same coal exhibited sulfuric acid capture of 38%”. Because data fr om other coal types was not available, EPRI 2008 and Harrison 2005 suggested that western coals with acidic ash (e.g., bituminous) may consider adopting the low sulfur, eastern bituminous value of 0.49 for the H 2 SO 4 penetration (1- removal), which is equivalent to 51% removal. EPA used the 0.49 value for the ai r preheater penetration factor for our analysis presented in the ANPRM. This was consistent with SRP’s statement cited above that their ash has low alkalinity.

In its analysis for NGS, AECOM used an ai r preheater penetration factor of 0.9 (10% removal). The 0.9 penetration factor is consiste nt with the value for PRB coal in Harrison 2005

and for Western bituminous and subbituminous coal in Hardman 1998, but in consistent with the

value for PRB coal from EPRI 2008. The values in EPRI 2008 document are identical to those in Harrison 2005, except for the change from 0.9 to 0.56. AECOM chose to use the earlier PRB

value from Harrison 2005 rather than EPRI 2008.

SRP submitted comments to EPA regarding our use of 0.49, stating that SRP considered

the use of this factor and determined that it wa s not appropriate because (1) removal in the air preheater is limited by the hot-side ESP, which removes fly ash, located upstream of the air preheater, because low-dust air pr eheaters have cleaner internal ba skets resulting in less surface area to collect sulfuric acid, and (2) the low alkalinity ash at NGS suggests that less sulfuric acid

would be removed. 225 For these reasons, SRP concludes that it is more appropriate to rely on the

225 See SRP Comment letter on ANPRM, document number 0126 in ANPR docket.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 114 of 129 value of 0.9 in Hardman 1998. However, Harris on 2005 associates the 0.9 value specifically

with PRB coal. Because Harrison 2005 is the updated version of the Hardman 1998 publication from Southern Company Services, EPA concl udes that the PRB coal is the appropriate categorization for the 0.9 value. EPA was not ab le to determine from Hardman 1998 or Harrison 2005 how many measurements the 0.9 value was ba sed on, however, given that no standard deviation was reported for this value (but a stan dard deviation was reported for the six units on

which the Eastern low-sulfur bituminous value wa s based) in Harrison 2 005, EPA concludes that the 0.9 value is based on a very limited number of data points.

The 2010 EPRI update 226 to its 2008 publication revised the air preheater penetration factor for PRB coal down from 0.49 (2008 vers ion) to 0.36 (2010 version). Given the high alkalinity of PRB ash, we expect removal of H 2 SO 4 from PRB coal to provide more than just

10% removal of H 2 SO 4 , and the revised EPRI report is cons istent with this expectation.

Formation of SO 3 is highly dependent on coal and boiler type and ash characteristics, and PRB coal and NGS coal are not identical. EPA believes it is inappropriate to rely on the penetration factor for PRB coal for NGS because of the exp ected difference in ash alkalinity. EPA also notes that the 2010 EPRI update also doe s not list an air preheater penetr ation factor of 0.9 for any coal type, but does list an air prehea ter penetration factor of 0.85 for medium to high sulfur (>2.5%) eastern bituminous coal. The coal used by NGS is clearly not medium to hi gh sulfur coal (<1%). The remaining air preheater penetration factor is 0.50 for low sulfur eastern bituminous coal. The 2010 EPRI update recommends the use of this factor for other coal types if the ash is acidic. Because of the relatively low alkalinity of the ash produced at NGS, EPA believes that the best available data from the 2010 EPRI update suggests using the air preheater penetration factor of 0.50. EPA’s modeling assumes a penetration f actor from the air preheater of 0.50.

Downstream of the air preheater, H 2 SO 4 is additionally lost to SO 2 control equipment. EPA and AECOM used the EPRI-recommended pene tration factor of 0.47 through a wet spray tower FGD reported for eastern bituminous coal.

Table 36: Assumptions used in Sulfuric acid (H 2 SO 4 ) Emissions Calculations

AECOM EPA (ANPRM) EPA (Proposal) Fuel Impact Factor (SO 3 formation from combustion) 0.00111 0.00111 0.00111 Coal sulfur content (%) 0.772 0.772 0.772

Coal S conversion to SO 2 0.95 0.95 0.95

Conversion of SO 2 to SO 3 from SCR catalyst (%) 1 0.5 0.67

Penetration factor 227 through the Hot-side ESP 0.63 1 0.63 Penetration factor through Air Preheater 0.9 0.49 0.50 Penetration factor through wet spray tower 0.47 0.47 0.47

In its comment letter, the Navajo Nation r ecommended we consider the results of the sulfuric acid emissions testing SRP conducted at NGS. The source tests provide a useful baseline for sulfuric acid emissions, howev er the testing protocol was not designed to measure inlet and outlet concentrations at each poten tial sulfuric acid control po int (e.g., air preheater, hot-side ESP, etc.), therefore, it is not possible, base d solely on exit emission rates from the stack, to determine which of the many assumptions used in the sulfuric acid emissions calculations requires revision.

226 Electric Power Research Institute, Estimating Total Sulfuric Acid Emissions from Stationary Power Plants , Version 2010a, 1020636, Technical Update, April 2010.

227 Penetration factor = 1 - Control EfficiencyTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 115 of 129 However, we agree with the Navajo Nation that it is instructive to examine predicted and

measured sulfuric acid emissions from NGS. NGS conducted source tests on November 16 – 17,

2009 to measure baseline sulfuric acid emissions from all thr ee units using the controlled

condensate method. 228 These baseline emissions represent su lfuric acid emissions without SCR. From three units, NGS reported an averag e emission rate of 0.00009 lb/MMBtu (9 x 10 -5 ). The three units show significa nt variability (9.43 x 10 -5 , 1.64 x 10 -4 , and 1.75 x 10 -5 ), but are all below emissions predicted by the EPRI model us ing both EPA’s and SRP’s assumptions for the EPRI calculation (4.2 x 10 -4 and 4.9 x 10 -4 lb/MMBtu). 229 These source tests from NGS suggest that the cumulative result of all the assumptions is that the EPRI model overpredicts sulfuric acid emissions compared to measurements. Because EP A used a lower penetra tion factor for the air preheater than AECOM, the EPA estimate is closer to the measured values. 230 Again, there are numerous assumptions and control points in the EPRI calculation methodology, and EPA believes the source tests do not provide enough information to inform which of the many assumptions in the EPRI methodology result in th e overprediction of sulfuric acid emissions in the model compared to measurements. However, EPA can conclude that the source test results do suggest that EPA’s choice of air preheater penetration efficiency, in addition to other assumptions, were generally more conservative and appropriate than those used by SRP.

2. HCl and HF Estimates

EPRI submitted comments 231 on the ANPRM stating that the inclusion of HCl and HF as fine PM is inappropriate and provided calcula tions suggesting that after emission into the atmosphere, HCl and HF tend to remain in the ga s phase, not the particulat e phase, and also that the solubility of chloride and fluoride ions into water-containing particle s would be inhibited by the presence of sulfate, whose solubility is orders of magnit ude higher. Therefore, in this proposal, EPA removed HCl and HF emissions from our modeling inputs for fine PM.

3. Ammonia Background Values

For ammonia background concentrations in this proposal, EPA used the IWAQM default of 1 ppb, and corroboration from modeling usin g ammonia levels from a back-calculation procedure relying on sulfate and nitrate measuremen ts at Class I areas. EPA considered various objections to the back-calcula tion procedure raised by commen ters on the ANPRM. EPA also strongly considered the opinions of the FLMs, who generally favored the back-calculationapproach. EPA has determined that the 1 ppb default and corroboration from the backcalculation results are a reasonable basis for as sessing visibility impacts, in light of the uncertainties involved in estimating ammonia. However, EPA also performed sensitivity modeling using the lower ammonia concentrations originally used by SRP in their modeling. Below we describe the approach used, and th en address various concerns over the backcalculation procedure.

228 Salt River Project Navajo Generating Station – Acid Mist Emissions Test Report by Catalyst Air Management, Inc. Report Number 264-001 (December 31, 2009).

229 Note that for the hot-side ESP at NGS, EPA assumed a pene tration factor of 1, whereas AECOM assumed a penetration factor of 0.63, thus the difference in th e air preheater penetration factor used by EPA (0.49) and AECOM (0.9) is less apparent compared to FCPP, which does not use hot-side ESPs.

230 If we included additional penetration from the hot-side ESP, EPA’s estimated sulfuric acid emissions would be closer to

measurements.

231 Comments submitted by Eladio Knipping, EPRI dated October 26, 2009.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 116 of 129 Based on comments we received on the ANP RM, we reexamined the ammonia background values. For this proposal, EPA used the IWAQM de fault of 1 ppb, with corroboration from a variant of the back-calculation procedure that was used for the ANRPM, describe d above. In the back-calculation for this proposal, instead using of the maximum fo r each month, EPA used the mean plus two standard deviations. (For the normal dist ribution, this represents the 97.5 th percentile.) This remains a conservative estimate, but compared to the maximum it is more in line with the BART Guidelines principle of avoiding unusual meteor ological conditions (the rationale in the BART Guidelines for using

the 98 th percentile delta deci views instead of the maximum), and partly addresses some commenters’ concerns that the method is overly conservative. The monthly average was also considered, but was felt to be too low to represent the da ily high impact conditions that can occur and that are the focus of visibility assessments under the BART guidelines. Als o, instead of averaging over all Class I areas, EPA

used different sets of values for each of five different groups of Class I areas. The groups were defined geographically, with one for each of the directions nor thwest, northeast, southeast, southwest, and with the Grand Canyon in a group by itself. Areas that ar e nearer to each other geographically and have broadly similar ammonia estimates are grouped togeth er, providing a better matc h to particular areas than the single average over al l areas used in the ANPRM. The gr oups are listed in Table 37 and the ammonia background concentrations are inTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 117 of 129 Table 38. For the northwest areas , the values range from 0.6 to 1.0 ppb; for the northeast the range is 0.4 to 0.8 ppb; for the Grand Canyon and the southeast group the range is 0.5 to 1.1 ppb; and for the southwest it is 0.6 to 1.3 ppb. The lowe r values are in the wi nter, and the higher ones

in summer.

Table 37: Class I area groupings for a mmonia background used in this proposal
Grouping IMPROVE monitors Class I Areas Grand Canyon GRCA2 Grand Canyon northwest areas BRCA1, CANY1, CAPI1 Arches, Bryce Canyon, Canyonlands, Capitol Reef northeast areas GRSA1, WEMI1, WHPE1,

WHRI1 Black Canyon of the Gunnison* 232 , Great Sand Dunes*, La Garita*, Maroon Bells Snowma ss*, Pecos*, Weminuche*, West Elk*, Wheeler Peak* southeast areas BAND1, SAPE1 Bandelier*, San Pedro Parks* southwest areas IKBA1, PEFO1, SYCA1 Mazatzal, Pe trified Forest, Pine Mountain, Sycamore Canyon

232 Areas denoted with a “*” were not modeled for NGS, but mon itors included in ammonia calcu lation as nearest to the areas

modeledTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 118 of 129 Table 38: Ammonia background concentrations in ppb modeled by EPA used in proposal

Ammonia scenario Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Am1: IWAQM default 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

Am2: AECOM values 0.2 0.2 0.5 0.5 1.0 1.0 1.0 1.0 1.0 0.5 0.5 0.2 Am3: EPA average of

max 233 0.8 0.7 0.7 1.0 1.0 1.3 1.0 1.0 1.0 1.0 1.0 0.9

Am4: Mesa Verde only 1.0 1.0 1.3 1.3 1.3 1.3 1.5 1.5 1.5 1.5 1.3 1.0 Am5gc 234 : Grand Canyon only 0.52 0.46 0.63 0.97 1.02 1.12 0.93 0.98 0.77 0.82 0.83 0.58

Am5nw: northwest areas 0.74 0.79 0.56 0.94 0. 84 0.99 0.91 0.83 0.65 0.61 0.73 0.90

Am5ne: northeast areas 0.43 0.49 0.49 0.75 0. 70 0.81 0.66 0.66 0. 61 0.68 0.59 0.45

Am5se: southeast areas 0.80 0.66 0.62 0.82 0.79 1.14 0.94 1.11 1.00 1.01 0.81 0.50

Am5sw: southwest areas 0.71 0.67 0.76 1.11 1.09 1.27 1.05 1.10 1.05 0.99 1.04 0.61

EPA could rely solely on the IWAQM defau lt, but believes the back-calculation method is also useful, since it is an obj ective approach and relies on mon itored data at the Class I areas where visibility is being assessed, and has a degr ee of conservatism. EPA is aware of various limitations inherent to the method, some of which were raised by ANPRM commenters.

Per the ADEQ comment on the ANPRM stated a bove (in section F.c.), for an alternative to default ammonia levels, the context in the IWAQM Phase 2 document does seem to envisage measurement of ammonia itself, rather than of other compounds that indirectly imply ammonia concentrations via a calculation: “However, given all the uncertainti es in ammonia data, IWAQM recommends use of the background levels provided above, unless specific data are available for the modeling domain that would discredit the values cited”. 235 For this proposal, EPA is considering visibility impacts estimated using the 1 ppb ammonia default. This is consistent with BART analyses carried out in many other parts of the country. However, EPA

continues to believe that the in direct back-calculation method provi des a useful estimate that is based on measured data, and helps ensure th e robustness of the BART determination.

As noted in the IWAQM Phase 2 document, ammonia con centrations vary with temperature by a factor of 3 – 4, and also vary strongly with soil pH, and with the presence of

local ammonia sources. 236 Thus ammonia is expected to vary temporally and spatially. Unfortunately, there is relatively little monitored ammonia data available to determine typical concentrations or their variation. Expanded a mmonia monitoring would be desirable, but the BART guidelines do not envisage the initiation of a new monito ring program as necessary for BART determinations; that would be a much la rger undertaking than th e analysis procedures described in the guidelines. Other than th e IWAQM default supplemented by available measurements, there is not an accepted method for estimating ammonia for use in CALPUFF visibility modeling. In addition, even if such data were avai lable, CALPUFF accepts only a single ammonia value for each modeled month for the whole modeling domain, so it uses little temporal variation, and no spatial variation. Ther e are substantial uncerta inties associated with

233 Am3 is the average over all areas of the maximum calculated ammonia; used in the ANPRM, but not in this current proposal.

234 Am5xx is the average over areas in group xx of the mean plus two standard deviations of calculated ammonia.

235 IWAQM Phase 2 document, section 2.2.2, p.14

236 IWAQM Phase 2 document, section 2.2.2, pp.14-15Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 119 of 129 the background ammonia concentration, and also compromises involved in any approach to

estimate it.

New ammonia monitoring data was collected by SRP at several sites between NGS and the two nearest Class I areas, Capitol Reef Na tional Park and Grand Ca nyon National Park, from December 2009 through April 2010. The monitoring report 237 describes a surprisingly high spatial variability in ammonia concentrations. The two monitors in th e Cameron area south of NGS (and east-southeast of the Grand Canyon) s howed consistent con centration differences despite being less than 5 miles from each other; th is may be due to relatively localized ammonia sources. These sites also showed consistently lo wer measurements than the Hall’s crossing site, north of NGS (and southwest of Capitol Reef). The range in concentrations was comparable to the range seen between the AECO M values at the low end, EPA’s back-calculated values at the high end. Unfortunately, because of the variabil ity and its unknown causes, the data collected did not lead to a clear picture of appropr iate and representative ammonia background

concentrations to use with CALPUFF.

EPA views the back-calculation method as pr oviding a reasonable objective indicator of

ammonia concentrations that the emission source’s plume can encounter as it travels to a Class I area, and not necessarily as a definitive estima te of ammonia concentrat ion within the Class I

area itself. It is not definitive because it is not a direct ammonia measurement, but rather an indirect estimate based on integrated 24-hour sulfat e and nitrate measurements. An effect of the indirectness is that it can only acc ount for ammonia that is present at the monitor in the form of particulate ammonium (NH 4 + ), and not any that is presen t as free gaseous ammonia (NH 3 ). The method thus provides a lower bound on the total amount of ammonia present, and tends to

underestimate the total a mmonia available to interact with the source plume. (Conversely, a

direct measurement of free ammonia does not incl ude particulate ammonium, and so would also

tend to underestimate the to tal ammonia available.)

While the method may tend to underestimate th e total ammonia availa ble because it does not account for gaseous ammonia, anot her aspect of the method is that it assumes that all of that

ammonia is available to interact with emissions from the single source being modeled. In the real atmosphere, SO

x and NO

x emissions from multiple sources compete for the available ammonia. But CALPUFF modeling using th e ammonia back-calcu lated from those

measurements assumes all that ammonia is availa ble to interact with the NGS plume. This procedure would not be appropria te for assessing the actual impact of NGS in the real atmosphere as part of a source apportionment; in that case it might be considered “double counting”, since the calculated ammonia includes ammonium from NGS itself as well as from

other sources. But for BART modeling it is acceptable because the assumption that all the ammonia is available to NGS emissions is comp arable to assuming that there are no competing sources, similar to natural background conditi ons. EPA believes that the back-calculation

method is in accord with the BART Guidelines ’ recommendation to assess visibility impacts

relative to natural conditions.

The above-mentioned 24-hour integration as pect of the back-calculation method is desirable in that concentrations in the source pl ume when it arrives at the Class I area are the cumulative (integrated) result of conditions the plume has encountered on the way. The

237 “Measurements of Ambient Background Ammonia on the Colo rado Plateau and Visibility Modeling Implications”, Salt River Project, Dr. Ivar Tombach, Consultant, and Robert Paine, AECOM Environment, September 2010Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 120 of 129 IMPROVE concentrations reflect particulate amm onium formation that resulted from various gaseous ammonia concentrations and various me teorological conditions encountered, which is desirable for estimating 24-hour visibility impacts. 238

On the other hand, an undesirable aspect of the integration is that for different hours within a given day, the sulfate and nitrate at the IMPROVE monitor may have arrived via different routes. Some of those routes may have little relevance for the plume of the source being assessed, but the method assumes ammonia along all routes is available to interact with the source plume. The same issue arises considering different days: some days’ transport routes to

the monitor will have little rele vance for the source plume, yet their back-calculated ammonia is assumed to be available for that plume. That is, ammonium sulfate tran sported to the monitor from a completely different direction than NGS adds to the ammonia calculated as available to the NGS plume. Two considerations lessen the severity of these issu es. First, other things being equal, these other transport rout es would be just as likely to encounter below-average ammonia concentrations as to encounter above-average ammonia. The various contributions to an IMPROVE monitor within a day and over multiple da ys tend to balance each other in the overall

distribution of calculated ammonia values, especially since av erages over several monitors are used. Second, this potential source of inaccuracy is lessened by consid ering multiple years of data; in the aggregate the range of ammonia values derived from the method for hundreds of days is likely to be seen by the source’s plume at various times during that span. In any case, to properly assess the net effect of these potential problems would require a much more complex analysis than envisaged under the BART guideli nes, involving modeling of multiple sources, the development of an ammonia inventory, and a model with more complete chemistry than

CALPUFF.

In view of the lack of available amm onia data, and counterba lancing tendencies for

under- and overestimation within the back-cal culation method, EPA believes that it remains useful as a “ballpark” estimate of ammonia c oncentrations contributi ng to particulates at IMPROVE monitors, since it is based on actual measured data, is easily computed, and on many days would be expected to represent ammonia concentratio ns encountered by the source’s plume. It appears to be conservative, while rema ining realistic. Some conservatism is warranted given the BART guidelines’ emphasis on the higher (98 th percentile) impacts, and also given that ammonia has generally been tre nding upward over the past decade. 239

As a rough check on the appropriateness of the ammonia background concentration estimates, EPA compared CALPUFF predictions of nitrate impacts from NGS to nitrate

measurements at IMPROVE monitors in Grand Canyon National Park. If the assumed ammonia is too high, then too much ammonium nitrate wi ll be simulated in the model, and predicted

nitrate will exceed the nitrate measured at the IM PROVE monitors. Given the uncertainty in the ammonia estimates, some over-prediction is accep table, but consistently large over-predictions would be grounds for concern. Particular re ceptor points were selected based on their high modeled nitrate impacts, and then a 2001-2003 time series of daily n itrate was generated for each

238 Since nitrate has a fast equilibrium between gaseous and par ticulate forms, it could be argued that for nitrate the spatial integration over the plume path is less relevant than conditi ons in the immediate vicinity of the Class I area. By this argument, for nitrate the 24-hour values co uld be considered as more of a temporal integration of conditions at the area,

which is still desirable for estimati ng 24-hour visibility with CALPUFF.

239 Christopher M. B. Lehmann et al. , “Monitoring Long-term Trends in Sulfate and Ammonium in US Precipitation: Results from the National Atmospheric Depositio n Program / National Trends Network”, Water, Air, & Soil Pollution: Focus, Volume 7, Numbers 1-3, March, 2007, DOI:10.1007/s11267-006-9100-zTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 121 of 129 Graphical comparisons were made between these predictions and the GRCA2 Grand Canyon IMPROVE monitor measurements, an alternative ammonia scenario. 240 The nitrate check scenario was modeled prior to the main CALPU FF visibility modeling for this proposal. It is comparable to the Am5 scenario, but uses a just single set of monthly values, instead of separate monthly values for various groups of areas; the single set is derived from an ammonia backcalculation considering a ll the Class I areas inst ead of just values for a particular grouping.

Table 39: Ammonia background concentrations in ppb for modeled by EPA for nitrate check

Ammonia scenario Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

NGS nitrate check 0.8 0.7 0.7 1.0 1.0 1.3 1.0 1.0 1.0 1.0 1.0 0.9

EPA concluded from these checks that nitrat e predictions were somewhat high in that high values occurred more frequently than in the measured IMPROVE data, but their maxima were in the range of maxima seen in the measured data. Since the values used in the proposal’s Am5 scenario are comparable to or lower than those used in this check, a comparable check using Am5 would be expected to show better ag reement with measured data. This provides support for the Am5 scenario used as corroborati on in this proposal, and some evidence against using Am2 (the AECOM values).

In addition, EPA conducted more extensive ch ecking of nitrate predictions for the BART proposal for the Four Corners Power Plant (FCPP). 241 EPA found that the predicted highs were comparable to the measured highs, based on the maximum, the 98th percentile, and inspection of peaks on the time series graphs. At the higher imp acts which are of the most regulatory interest, there was general agreement between the model pr edictions and the measurements. While this additional checking was conducted for FCPP ratherthan NGS, it does lend support to the backcalculation methodology Am5 used as corroboration in this proposal , and also corroborates the results of the Am3x checks that were performed for NGS. EPA concludes th at there is not any systematic overprediction of nitrate highs us ing either of the ammonia background scenarios Am1 or Am5 considered by EPA for this proposal.

Finally, there may be an additional incremen t of ammonia from “ammonia slip”, that is,

ammonia added to control NO

x as part of the SCR and SNCR, but which remains unreacted.

Some of this unreacted ammonia can react with sulfuric acid crea ted from oxidation of sulfur in the coal fuel, including oxidation by the SCR cat alyst. The ammonia and the sulfuric acid can

react to form ammonium bisulf ate and ammonium sulfate; th e amounts of these and of any leftover ammonia and sulfuric acid depends on th e relative amount of amm onia and sulfuric acid present originally. Following the EPRI 2010 sulfuric acid estimation document, 242 EPA

calculated the amounts of the vari ous reaction products in the em ission calculation spreadsheet cited below. For purposes of visibility m odeling, the relative amounts of sulfuric acid,

240 See Excel spreadsheets entitled “NH3_scenarios_ANPRM.xls ” and “NO3_compare_ANPRM.xls”. Note that these spreadsheets use a different ammonia scenario numbering scheme th an that used in the notice for this proposal and in this TSD. In the spreadsheets, “am3” is the s cenario that appears in this TSD as “NGS nitrate check”. The spreadsheet’s “am1” is the same as the “Am2: 0.5 – 1 ppb” scenario here, and “am4 ” is identical to “Am4” here. The spreadsheet’s “am2” was a high ammonia test case, and is not being used for this proposal.

241 “Technical Support Document, Proposed Rule: Source Speci fic Federal Implementation Plan for Implementing Best Available Retrofit Technology for Four Corners Power Plant: Navajo Nation”, Docket Number: EPA-R09-OAR-2010-0683. EPA Region 9, October 10, 2010.

242 EPRI 2010, op. cit.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 122 of 129 ammonium bisulfate, and ammonium sulfate in the end products (t hat is, the partitioning of the starting sulfate into these end products) does not matter, since all of these are conservatively assumed to be sulfate (“SO 4 ”) in the CALPUFF modeling. Ho wever, the amount of ammonia remaining, the net ammonia slip, may matter, because it may cause formation of additional

ammonium sulfate and a mmonium nitrate downwind.

For SCR, there is sufficient sulfuric acid that all of th e ammonia slip is consumed, leaving no net ammonia slip, and no e ffect on the visibility modeling.

For SNCR, however, some net ammonia slip remains. To account for its effect on visibility, EPA followed the same procedure as SRP did for NGS. First EPA applied 90%

ammonia control from the wet FGD at NGS. 243 Then EPA used CALPUFF to model ammonia as an inert pollutant, and determined the 8th highest ( cf. 98th percentile) amm onia concentrations

at the Class I areas within 300 km. The result could be added to th e ammonia background used in the main CALPUFF visibility modeling. Howe ver, the concentrations were about 0.01 ppb or less; this is only 1% of the va lues EPA used for ammonia scenario Am1 (1 ppb), and about 5% of the lowest for scenario Am2 (0.2 ppb). EPA then assessed the visi bility effect of this additional ammonia at Grand Canyon and Capitol Reef, the two nearest Class I areas and the ones with the largest predicted inert ammonia c oncentrations; this was done only for scenario Am2, since the 1% addition relative to Am1 and Am5 are negligible. The effect on the 8th high delta deciviews prediction was about 0.06 dv or less. If this were included in the main CALPUFF visibility modeling, fo r ammonia scenario Am2 this could potentially increase estimates of post-SNCR impacts by 0.1 dv, and co rrespondingly decrease th e estimates of the benefit from SNCR by 0.1 dv. As discussed be low, the benefits from SNCR under ammonia scenario Am2 range are above 2 dv for multiple Class I areas; therefore, including this net ammonia slip effect would have essentially no effect on EPA’s assessmen t of SNCR, especially since EPA is mainly re lying on scenario Am1.

4. Revised Emission Inputs for CALPUFF Modeling

For this proposal, we remodeled the anticipat ed visibility improvement from the use of LNB+SOFA, SCR, or SNCR on Units 1 – 3 for NO

x control. The emission inputs we used are listed in listed in Table 34 and are provided in more detail in the docket. 244 Because the modeling files are in a are in a format that cannot be uploaded to www.re gulations.gov, these files ar e not in our online docket docket but are available upon request . EPA modeled several SCR contro l cases assuming varying levels

levels of NO

x control and catalyst layers (whi ch affect sulfuric acid emissi ons), as well as a scenario scenario using the air preheater penetration factor supported by SRP, and SCR on a limited number of number of units at NGS. The modeling scenarios are described in

243 “Estimating Ammonia Emissions from Stationary Power Plan ts”, Electric Power Research Institute (EPRI), Palo Alto, CA: 2009, Report No. 1017985. http://my.epri.com/portal/server.pt?Abstract_id=000000000001017985

244 See Excel spreadsheet entitled “NGS_BART_Scenarios_Emissions_EPA_proposal.xls”.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 123 of 129 Table 40.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 124 of 129 Table 40: Scenarios Modeled by EPA for our BART Analysis for NGS

Code Name Description

N0 Baseline 2001 - 2003 baseline N1 Control Option 1 LNB/SOFA on Units 1 - 3, NO

x = 0.24 lb/MMBtu N2 Control Option 2 SCR+LNB+SOFA on Unit 1 – 3, NO

x = 0.05 lb/MMBtu, SO 2 to SO 3 conversion =

0.67% N3 Control Option 3 SCR+LNB+SOFA on Unit 1 – 3, NO

x = 0.08 lb/MMBtu, SO 2 to SO 3 conversion =

0.5% N4 Control Option 4 SCR+LNB+SOFA on Unit 1 – 3, NO

x = 0.05 lb/MMBtu, SO 2 to SO 3 conversion = 0.67%, with SRP's air preheater penetration value of 0.9 N5 Control Option 5 SCR+LNB+SOFA on Unit 1 (0.05 lb/MMBtu); LNB+SOFA on Unit 2, 3 N6 Control Option 6 SCR+LNB+SOFA on Unit 1, 3 (0.05 lb/MMBtu); LNB+SOFA on Unit 2 N7 Control Option 7 SCR+LNB+SOFA on Unit 1 – 3, same as for N2, but SCR placed after ESP N8 Control Option 8 SNCR+LNB+SOFA on Unit 1 – 3 (0.18 lb/MMBtu) N9 Control Option 9 SNCR+LNB+SOFA on Unit 1 – 3 (0.15 lb/MMBtu)

Table 41: EPA Modeling Inputs (lb/hr)

Scenario N0 – Baseline

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 2.32 2.49 2.42

NO

x 4,271.42 4,207.50 4,181.67

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05 Scenario N1 – Control Option 1 – LNB/SOFA on Units 1 – 3

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 2.32 2.49 2.42

NO

x 2,110.74 2,261.63 2,197.78

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05 Scenario N2 – Control Option 2 – SCR + LNB/SOFA on Units 1 – 3, NO

x = 0.05 lb/MMBtu

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 16.35 17.52 17.03

NO

x 439.74 471.17 457.87

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05 Scenario N3 – Control Option 3 – SCR + LNB/SOFA on Units 1 – 3, NO

x = 0.08 lb/MMBtu

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 12.79 13.71 13.32

NO

x 703.58 753.88 732.59

SOA 35.18 37.69 36.63Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 125 of 129 PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05 Scenario N4 – Control Option 4 – SCR + LNB/SOFA on Units 1 – 3, NO

x = 0.05 lb/MMBtu,

Air Preheater Penetration = 0.9

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 29.44 31.54 30.65

NO

x 439.74 471.17 457.87

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05 Scenario N5 – Control Option 5 – SCR + LNB/SOFA on Units 1, LNB+SOFA on Units 2 and 3

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 16.35 2.49 2.42

NO

x 439.74 2,261.63 2,197.78

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05 Scenario N6 – Control Option 6 – SCR + LNB/SOFA on Units 1 and 3, LNB/SOFA on Unit 2

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 16.35 2.49 17.03

NO

x 439.74 2,261.63 457.87

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.20 107.87

EC 2.45 2.12 3.05 Scenario N7 – Control Option 7 – same as N2 but SCR after ESP

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 24.59 26.35 25.61

NO

x 439.74 471.17 457.87

SOA 35.18 37.69 36.63

PM fine 63.86 55.27 79.28

PM coarse 86.89 75.2 107.87

EC 2.45 2.12 3.05

Scenario N8 – Control Option 8 – SNCR+LNB+SOFA on Unit 1 – 3 (0.18 lb/MMBtu)

Unit 1 Unit 2 Unit 3

SO 2 487.75 526.92 576.17

SO 4 2.32 2.49 2.42

NO

x 1583.06 1696.22 1648.34

SOA 35.18 37.69 36.63

PM fine 0.03 0.02 0.03

PM coarse 86.89 75.2 107.87

EC 2.45 2.12 3.05

Scenario N9 – Control Option 9 – SNCR+LNB+SOFA on Unit 1 – 3 (0.15 lb/MMBtu)

Unit 1 Unit 2 Unit 3Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 126 of 129 SO 2 487.75 526.92 576.17

SO 4 2.32 2.49 2.42

NO

x 1319.21 1413.52 1373.61

SOA 35.18 37.69 36.63

PM fine 0.03 0.02 0.03

PM coarse 86.89 75.2 107.87

EC 2.45 2.12 3.05

5. Baseline Visibility Impacts of NGS

Modeled impacts on the Class I areas of NGS without additiona l controls for each ammonia

scenario are shown inTechnical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 127 of 129 Table 42. The table shows the 98 th percentile delta deciview impacts, considering days from all three modeled years together (rather than separate 98 th percentiles for each of the modeled years as was done by SRP). Impacts depend strongl y on the background ammonia assumed, increasing as ammonia does. From lowest to highest, the ammonia concentrations as well as the impacts are in the order Am2 (AECOM values), Am5 (t he back-calculated mean plus two standard deviations), Am1 (IWAQM 1 ppb default). 245 Scenario Am2 impacts are roughly half of the other scenarios, which are fairly close together. The Am5 scenario is a refined version of the

Am3 variant in the ANPRM Both are based on th e back-calculation approach, but Am5 assigns ammonia for several groups of Class I area s individually, whereas Am3 lumped all areas together.

Impacts generally decline with distance from NGS, as would be expected since the plume disperses as it travels, though conditions can be more or less favorable for transport to Class I areas in particular directions. The Gr and Canyon is the closest area and has the highest impact, while Pine Mountain is the second mo st distant and has the lowest impact. The northwestern areas of Arches and Canyonlands have impacts a bit high for their distance, while Sycamore Canyon impacts are a bit low for its distan ce. For all areas and ammonia scenarios, the modeled impact of NGS without additional contro ls exceeds 1 deciview (except for Mazatzal and Pine Mountain for Am2, with impacts of 0.8 dv), confirming that NGS causes visibility impairment in a large number of Class I areas.

245 As for the other tables, Mesa Verde impacts in the Am5 column is actually Am4, with concentrations derived from

ammonia measurements rather th an the back-cal culation method.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 128 of 129 Table 42: EPA Modeling Results – 8 th High Delta dv Baseline Impacts of NGS on 11 Class I Areas from 2001 – 2003 for the Different Ammonia Background Scenarios

Class I Area Baseline Impacts

Am1 (1 ppb IWAQM default) Am2 (AECOM) Am5 (back-calculation)

Arches NP 4.5 2.6 4.1 Bryce Canyon NP 4.9 3.0 4.4 Canyonlands NP 6.0 3.6 5.4 Capitol Reef NP 7.7 3.7 7.1 Grand Canyon NP 8.4 4.3 6.4

Mazatzal WA 1.5 0.8 1.3

Mesa Verde NP 3.2 2.0 3.2

Petrified Forest NP 3.4 2.0 3.2

Pine Mountain WA 1.3 0.8 1.2 Sycamore Canyon WA 2.4 1.6 2.3

Zion NP 4.4 2.3 4.0

Total 47.8 26.7 42.8

6. Anticipated Visibility Improve ment Based on New Modeling

For assessing visibility improvement for th is proposals, EPA relied primarily on the ammonia scenario with the IWAQM 1 ppb default (Am1), corroborated by a scenario with the back-calculated mean plus two standard devia tions (Am5) or measured data for Mesa Verde (Am4, but for convenience listed in tables under “Am5”), with the other scenario (Am2) considered as a sensitivity an alysis. Also, EPA mainly cons idered improvement in delta

deciviews relative to the baseli ne, with additional consideration of its percent improvement. The delta dv improvement and percent change for each ammonia background sc enario are shown in Table 43, Table 44, and Table 45. Additional tabl es, including comparisons of alternative ammonia, other background concentrations and visibility methods, and the number of days having impacts over 0.5 and 1.0 dv, are in th e docket for this proposed rulemaking. 246

The following summarizing results for LN B/SOFA, SCR at 0.05 lb/MMBtu, and SNCR at 0.18 lb/MMBtu. The visibility improvement from applying SCR is about tw ice as large as that from applying LNB/SOFA, while the improvement fr om SNCR is about a third larger than that from LNB/SOFA. Improvements from the Am2 a mmonia assumption are about half of those for Am1; improvements from Am5 are less than those fr om Am1, but still subs tantially larger than

for Am2.

For ammonia scenario Am2, (suggested by SR P), the absolute deciview improvements for Am2 are only about half of those for the ot her ammonia scenarios. Improvements range from 0.25 dv to 0.86 dv for LNB/SOFA, and 0.48 dv to 2.37 dv for SCR. All SCR benefits are at about 0.5 dv or higher, except for Pine Mountain. The 0.5 dv level is an amount considered to be perceptible and to “contribute” to visibility impairment under the BART Guidelines (p. 39120). So, even for the lowest ammonia scenario, AECOM’s Am2, the visibility improvement from SCR is significant, especially considering th at 14 Class I areas would experience that improvement. By contrast, improvements from LNB/SOFA are below or approximately at the 0.5 dv level for five areas. Improvements fr om SNCR range from 0.70 to 3.09 dv, with all but two areas having improvements over 1.0 dv.

246 See Excel spreadsheet entitled “NGS_RHFIP_TSD_vis_tables .xlsx” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page 129 of 129 For Am1 (IWAQM 1 ppb default) visibility improvements from LNB/SOFA, SNCR+LNB/SOFA, and SCR+LNB/SOFA are r oughly double those for Am2. LNB/SOFA improvements range from to 0.54 to 2.12 dv, with all areas experiencing more than a 0.5 dv improvement, and two areas showing improvement s over 2 dv. For SCR+LNB/SOFA, benefits range from 0.99 to 5.45 dv, with all areas having an improvement of about 1 dv or greater. Eight have more than a 2 dv improvement, and three have more than a 4 dv improvement. Thus both

LNB/SOFA and SCR+LNB/SOFA re sult in visibility improvements above the “contribute to impairment” or just perceptible level of 0.5 dv at all 16 Class I areas. Ho wever the benefits of SCR+LNB/SOFA are generally more than twice as high as for LNB/SOFA, and are all at or above the BART Guidelines “cause impairmen t” level of 1.0 dv; these changes would be definitely noticeable by most observers at the Class I areas. Improvements from SNCR+LNB/SOFA range from 0.63 to 2.65 dv, with all areas having improvements over 0.5 dv.

For Am5 (back-calculated mean plus two standard deviations, except Mesa Verde from measurements), the LNB/SOFA improvements range from 0.49 dv to 1.96 dv; all 11 areas’ improvements are at 0.5 dv or above. The S CR+LNB/SOFA improvements are again about twice as high as for LNB/SOFA, ranging fr om 0.87 dv to 4.89 dv. All the SCR+LNB/SOFA improvements are above 0.5 dv; 9 of the 11 areas have improvements over 1.0 dv, and two have more than a 4 dv improvement. While the modeled improvements are less than for the Am1 case, the conclusion is similar: LNB/SOFA benefits would be per ceptible and significant, and for SCR+LNB/SOFA much more so, with improvement s definitely noticeable by most observers at the Class I areas. Improvements from SNCR+LN B/SOFA range from 0.63 to 2.65 dv, with all areas having improvements over 0.5 dv.

Despite uncertainty over background ammonia concentrations, severa l conclusions can be

drawn. Installation of LNB/ SOFA, SNCR+LNB/SOFA, or SCR+ LNB/SOFA at NGS would all contribute to visibility improve ment, except that the LNB benef it is under 0.5 dv for one area for

the low-ammonia Am2 scenario. 247 The benefit of SCR+LNB/SOFA is significantly greater than for LNB/SOFA, improving visibility by a percep tible amount even for the lowest ammonia scenario for 9 of the 11 nearby Class I areas, and by substantially larger amounts for the other ammonia scenarios, which EPA believes give more accurate estimates. The benefit of

SNCR+LNB/SOFA is intermediate between LNB/SOFA and SCR+LN B/SOFA, though closer to those from LNB/SOFA. The visibility benefit of SCR+LNB/SO FA is double that of LNB/SOFA, and the benefit of SNCR+LNB/SOFA is about a third higher than that of

LNB/SOFA.

Based on the anticipated improvement in visibi lity that may be reasonably expected from controls, EPA is proposing to find that the s ubstantial visibility benefit of installing

SCR+LNB/SOFA at NGS does not warrant elimination of SCR as the top control option for

BART.

247 Even though that improvement would not be perceptible in itsel f, it is still worth considering as part of the overall regional haze planning process, since it would occur cumulatively with improvements due to controls on other sources.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page130of130Table 43: EPA Modeling Results – 8thHigh Delta dv Improvement and Percent Changein Delta dv Impact Compared to BaselineImpacts from 2001 – 2003 using Ammonia Background Scenario Am1Vis.method/ammoniaControlScenariovm8b/am1:1ppbn0:Baselinen1:LNBn2:SCR0.05lb/MMBtun3:SCR0.08,SO30.5%n4:SCR,APHp=0.9n5:SCRon1,LNBon2&3n6:SCRon1&3,LNBon2n7:SCRafterESPn8:SNCR0.18lb/MMBtun9:SNCR0.15lb/MMBtuClassIAreaDeltadvImpactDeltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%ArchesNP4.51.737%3.577%3.270%3.476%2.248%2.862%3.477%2.250%2.556%BryceCanyonNP4.91.633%3.674%3.366%3.572%2.245%2.959%3.673%2.346%2.652%CanyonlandsNP6.02.135%4.676%4.269%4.575%2.847%3.761%4.676%2.948%3.354%CapitolReefNP7.72.128%5.471%4.862%5.369%3.039%4.052%5.470%3.140%3.545%GrandCanyonNP8.41.923%5.464%4.756%5.262%2.833%3.947%5.363%2.935%3.440%MazatzalWild.1.50.641%1.175%1.070%1.173%0.750%0.962%1.174%0.852%0.858%MesaVerdeNP3.21.342%2.681%2.475%2.680%1.754%2.267%2.680%1.855%2.061%PetrifiedForestNP3.41.441%2.778%2.574%2.677%1.853%2.266%2.677%1.854%2.060%PineMountainWild.1.30.541%1.075%0.971%1.074%0.752%0.864%1.074%0.754%0.860%SycamoreCanyonWild.2.40.937%1.875%1.770%1.874%1.249%1.562%1.874%1.250%1.457%ZionNP4.41.431%3.376%3.068%3.375%1.944%2.658%3.375%2.045%2.352%TotalddvorAverage%47.815.635%35.175%31.768%34.373%21.147%27.560%34.674%21.648%24.554%Table uses 98th percentilefor the three-year period 2001-2003.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page131of131Table 44: EPA Modeling Results – 8thHigh Delta dv Improvement and Percent Changein Delta dv Impact Compared to BaselineImpacts from 2001 – 2003 using Ammonia Background Scenario Am2Vis.method/ammoniaControlScenariovm8b/am2:0.2–0.5ppbn0:Baselinen1:LNBn2:SCR0.05lb/MMBtun3:SCR0.08,SO30.5%n4:SCR,APHp=0.9n5:SCRon1,LNBon2&3n6:SCRon1&3,LNBon2n7:SCRafterESPn8:SNCR0.18lb/MMBtun9:SNCR0.15lb/MMBtuClassIAreaDeltadvImpactDeltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%ArchesNP2.60.728%1.868%1.661%1.767%1.037%1.351%1.867%1.039%1.246%BryceCanyonNP3.00.724%1.859%1.549%1.756%0.930%1.239%1.757%0.932%1.137%CanyonlandsNP3.60.924%2.466%2.158%2.364%1.335%1.850%2.365%1.336%1.644%CapitolReefNP3.70.718%2.053%1.643%1.950%1.026%1.335%1.951%1.028%1.232%GrandCanyonNP4.30.716%1.945%1.638%1.841%1.126%1.432%1.842%1.227%1.331%MazatzalWild.0.80.334%0.561%0.558%0.558%0.342%0.453%0.559%0.445%0.450%MesaVerdeNP2.00.629%1.573%1.365%1.571%0.840%1.154%1.572%0.841%1.048%PetrifiedForestNP2.00.526%1.367%1.260%1.365%0.840%1.154%1.366%0.842%1.049%PineMountainWild.0.80.333%0.563%0.459%0.561%0.344%0.453%0.562%0.446%0.451%SycamoreCanyonWild.1.60.532%1.165%1.059%1.064%0.742%0.953%1.064%0.745%0.850%ZionNP2.30.522%1.461%1.252%1.358%0.834%1.043%1.459%0.836%0.940%TotalddvorAverage%26.76.326%16.062%14.055%15.460%8.936%11.847%15.660%9.438%10.943%Table uses 98th percentilefor the three-year period 2001-2003.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page132of132Table 45: EPA Modeling Results – 8thHigh Delta dv Improvement and Percent Changein Delta dv Impact Compared to BaselineImpacts from 2001 – 2003 using Ammonia Background Scenario Am5Vis.method/ammoniaControlScenariovm8b/am5:backcalculationn0:Baselinen1:LNBn2:SCR0.05lb/MMBtun3:SCR0.08,SO30.5%n4:SCR,APHp=0.9n5:SCRon1,LNBon2&3n6:SCRon1&3,LNBon2n7:SCRafterESPn8:SNCR0.18lb/MMBtun9:SNCR0.15lb/MMBtuClassIAreaDeltadvImpactDeltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%Deltadv%ArchesNP4.11.536%3.276%2.869%3.175%1.946%2.560%3.176%2.047%2.254%BryceCanyonNP4.41.329%3.272%2.965%3.169%1.739%2.555%3.170%1.841%2.249%CanyonlandsNP5.41.731%4.074%3.667%4.073%2.444%3.158%4.074%2.444%2.851%CapitolReefNP7.12.028%4.969%4.259%4.766%2.536%3.550%4.867%2.637%3.144%GrandCanyonNP6.41.218%3.555%3.046%3.453%1.726%2.437%3.454%1.828%2.134%MazatzalWild.1.30.538%0.973%0.967%0.971%0.648%0.860%0.972%0.650%0.755%MesaVerdeNP3.21.442%2.681%2.475%2.680%1.854%2.267%2.680%1.855%2.061%PetrifiedForestNP3.21.239%2.477%2.373%2.475%1.651%2.165%2.476%1.752%1.959%PineMountainWild.1.20.541%0.973%0.869%0.972%0.651%0.864%0.973%0.653%0.759%SycamoreCanyonWild.2.30.938%1.875%1.670%1.773%1.250%1.563%1.774%1.251%1.357%ZionNP4.01.331%2.973%2.665%2.972%1.641%2.255%2.973%1.742%1.948%TotalddvorAverage%42.813.334%30.373%27.266%29.671%17.744%23.458%29.972%18.346%21.052%Table uses 98th percentilefor the three-year period 2001-2003.Technical Support Document for NGS Proposed BART Determination, January 17, 2013 | Page133of133Table 46: Number of days with delta deciviewimpacts greater than or equal to 0.5 dv in 2001-2003Vis.method/ammoniaControlScenariovm8b/am1:1ppbn0:Baselinen1:LNB/SOFAn8:SNCR+LNB/SOFA0.18lb/MMBtun3:SCR+LNB/SOFA0.08lb/MMBtu,SO30.5%n2:SCR+LNB/SOFA0.05lb/MMBtuClassIAreaSumAvgSumAvgSumAvgSumAvgSumAvgArchesNP242811886315451107368127BryceCanyonNP16956138461214092317926CanyonlandsNP390130308103259862107017458CapitolReefNP368123318106287962528422475GrandCanyonNP3681233311103131042949828194MazatzalWild.61204114301020783MesaVerdeNP20869137461143859204013PetrifiedForestNP1705711438933158194415PineMountainWild.55183913331115572SycamoreCanyonWild.12441782668233612289ZionNP1374611338973266225017Maximum3901303311103131042949828194Cumulative(sum)22927641805602156952312094031016339Technical Support Document for NGS Proposed BART Determination | Page 134 of 134 

### 8. Overall Proposed BART Determination

The final step in the BART analysis is to sy nthesize these factors and reach an overall proposed

determination of BART.

A. NGS Approach to This Factor

In the summary of its BART analysis, which included technology and cost analyses by S&L and visibility modeling analyses by AECO M, SRP recommended that BART limits for NO

x be 0.24 lb/MMBtu for Units 1 – 3. These limits are based on the installation of LNB/SOFA on all units. AECOM and SRP explained that they rejected SNCR and SCR because its modeling analysis indicated that the visibility impr ovement from SNCR and SCR would be small. Additionally, AECOM and SRP cited the high ca pital and O&M costs for SCR and SNCR, and

other considerations associated with the shipping, storage, and injection of anhydrous or aqueous

ammonia.

The BART Guidelines provide presumptive NO

x limits for coal-fired EGUs, greater than 200 MW, located at power plants with a capac ity that exceeds 750 MW, and operated without post-combustion controls. At NGS, Units 1 – 3 are now equipped with advanced combustion controls (LNB/SOFA) with a permitted emission limit of 0.24 lb/MMBtu, which is lower than the presumptive NO

x limit of 0.28 lb/MMBtu for tangential- fired boilers firing bituminous coal, therefore, SRP contends its ex isting controls represent BART.

B. Affected Tribe, State, and FLM Consultation

EPA began consulting with affected tribes after publication of our ANPRM in 2009. Since that time, representatives from EPA have met w ith tribal leaders and tribal representatives on

numerous occasions to discuss their concer ns regarding an EPA rulemaking on NGS. In recognition of the unusual complexity of regulati ng NGS, representatives fr om EPA, including the Assistant Administrator and the Regional Admini strator for Region 9, visited NGS and affected

communities in the area. EPA officials also met w ith numerous additional stakeholders, at various locations, including EPA offices in San Franci sco, CA and Washington, DC, and offices of individual Tribal Governing C ouncils and at the Inter Tribal Council of Arizona. A timeline of EPA consultations with tribes on NGS is included in the docket for this proposed rulemaking. The timeline also lists consultations with the Navajo Nation on Four Corners Power Plant. 248 On several occasions, consultations with the Navajo Nation on FCPP also included discussion of NGS. However, the majority of the consultatio ns and correspondence listed in the timeline focused solely on NGS.

In its comment letter on the ANPRM, as an exte nsion of the cost of compliance factor of the five factor analysis, the Navajo Nation stressed the importance of NGS on the Navajo economy. Specifically, the Navajo Nation st ated that in 2005 – 2006, NGS employed 512 permanent full-time employees, 69 % of whom are Native American, and 300 seasonal employees,

248 See document titled “Timeline of Consultation and Corresponden ce on Navajo BART FIPs” in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination | Page 135 of 135 93% of whom are Native American, with a total pa yroll of $47 million. SRP stated that it employs 545 full time employees, 80% of whom are Navaj o, with annual payro ll and benefits of $52 million. SRP further stated that the Kayenta Mine, which supplies coal solely to NGS (and NGS is similarly its sole customer), employs 422 tribal members, and expects that in 2009, NGS and the Kayenta Mine will contribute $140 million in reve nue and wages to the Navajo Nation, and $12 million to the Hopi Tribe. Additionally, the Navajo Nation cited that NGS annually burns 8.3 million tons of coal from the Peabody Kayenta Mine, which provides jobs to approximately 400 workers, a large percentage of whom are Nativ e American, with a tota l payroll of $44 million.

The Navajo Nation commented that the intent of the BART requirement of the RHR was to provide a measured response to emissions from ag ing power plants, and th at requiring expensive

controls would be inconsistent with the law and regulations governing the BART process, particularly in light of the high incremental cost of SCR and the impacts to economic interests of the Navajo Nation. The Nation recommended a phased approach to reducing emissions at NGS to allow time for resolution of lease and right of way issues and to allow interested parties to review measurements rather rely on mode ling results before determining th e most stringent control option is appropriate. The Nation concluded that com bustion controls represent BART at this time.

The Hopi Tribe commented that it supplies both coal (the Kayenta Mine is located on both Navajo and Hopi land) and water to NGS, and deri ves a significant portion of its annual tribal budget from NGS-derived revenue. Because the H opi Tribe is geographically isolated from employment opportunities in Arizona, the Hopi st ate that there is no industrial development on its land, and the Hopi have also re jected gaming as a potential so urce of revenue. The Hopi Tribe stressed EPA’s trust and fiduciary responsibilities to Indian Tribes and stated that if NGS closed, the economic impacts would be catastrophic and in clude curtailment of cr itical social programs, lost employment, and loss or slowing of critical infrastructure programs. In its comment letter on the ANPRM, the Hopi Tribe submitted a report it commissioned from ICF International to examine the potential for BART, in combination w ith other possible regulatory requirements, to cause NGS to close. Although EPA is including this report in the docket for our proposed rulemaking, EPA has not conducted a critical review of the analysis or report.

The Gila River Indian Community commi ssioned a report by Harvey Economics to examine potential impacts of several air pollution control scenarios and closure of NGS on water rates, and thus the agricultural economy of the Gila River. A lthough EPA is including this report in the docket for our proposed rulemaking, EPA has not conducted a critical review of the analysis or report. Comments submitted in writing and concerns expressed in consultation by other tribes generally focused on potential increases to wate r rates and the potential that regulatory requirements might cause NGS to close. Comments received from the stat e of Arizona and local governments generally echo the concerns raised by tribes.

Comments and concerns raised by tribes and state and local governments during our extended and on-going consultation on NGS reinforced the need for EPA to provide flexibility to the owners of NGS in reducing emissions of NO

x because of the potential far-reaching impacts of

increased water costs and because of the critic al importance of NGS to the regional economy.

The National Park Service concluded in its comment letter on our ANPRM that SCR to

control NO

x emissions at NGS is technically feasible , cost effective, and will substantially improve visibility in the impacted Class I areas . NPS compiled BART analyses across the U.S.Technical Support Document for NGS Proposed BART Determination | Page 136 of 136 and found that the average cost pe r dv proposed by either a state or a BART-subject facility is $10 – 17 million / dv. The Park Service applied the cumulative approach to assessing visibility impacts and determined that SCR at NGS resulted in a cost per dv of $1.9 – 2.7 million / dv.

C. EPA Conclusions regarding This Factor

1. BART Guidelines

In making a BART determination for the Re gional Haze Rule, the BART Guidelines allow

states to determine that an alternative level of control, beyond presumptive limits, may be appropriate based on careful consider ation of the statutory factors. See 70 FR 39171. The presumptive NO

x limits for tangential-fired boilers us ing bituminous coal is 0.28 lb/MMBtu.

The presumptive limits are not binding requireme nts for BART, rather they are included in the BART guidelines as limits that most EGUs can meet through the us e of current combustion control technologies. Ind eed, NGS has shown that with the installation of m odern LNB/SOFA, each unit at NGS can meet its permitted emi ssion limit of 0.24 lb/MMBtu. However, the BART guidelines further state that the re viewing authority may determine th at an alternative control level is appropriate based on the caref ul consideration of the statut ory factors. The RHR allows reviewing authorities to determin e the weight prescribed to each BART factor independently and on a case-by-case basis.

2. Summary of Five Factor Analysis

The first factor evaluates the cost of controls . EPA finds that even using the cost analysis submitted by Sargent and Lundy (S&L) for SRP, the costs per ton of NO

x removed for SCR ($2,528 per ton - $3,172 per ton) are within a range that has been determined reasonable for

BART. EPA used S&L’s cost estimates and made several revisions to assumptions based on guidelines in the EPA Control Cost Manual to generate cost projections that are more consistent with the BART guidelines. EPA estimated an av erage cost effectivenes s of less than $2,500 per

ton to install SCR on all three units at NGS to achieve a NO

x limit of 0.055 lb/MMBtu. EPA

estimates that the incremental cost effectiven ess of SCR+LNB/SOFA co mpared to LNB/SOFA (the technology SRP recommended as BART) is less than $3,400 per t on (average of Units 1 – 3),

and the incremental cost effectiveness of S CR+LNB/SOFA to SNCR+LNB/SOFA is less than $3,000 per ton (average of Units 1 – 3). Based on th e cost data presented by SRP, EPA’s revisions to SRP’s cost estimates, and our analysis of av erage and incremental cost effectiveness, EPA is proposing to determine that SCR+LNB/SOFA at NGS to achieve 0.055 lb/MMBtu is cost

effective.

The second factor involves consideration of the energy and non-ai r quality impacts of

controls. Because NGS is not located on a commer cial rail line, the installation of SCR or SNCR

would result in increased truc k traffic deliveries of anhydrous ammonia or urea to NGS. EPA conducted analyses of the potential air quality imp acts associated with emissions from increased truck traffic, and also consider ed potential risks associated with transporta tion and use of anhydrous ammonia, and determined that SCR and SN CR are not likely to re sult in a significant health risk to the local population. Because of the importance of NGS to the economy of the Navajo Nation and the Hopi Tribe, EPA also c onsidered the concern expressed to EPA thatTechnical Support Document for NGS Proposed BART Determination | Page 137 of 137 requiring SCR as BART will cause NGS to shut down and result in a loss of jobs at NGS and the Kayenta Mine. The Navajo Nation receives taxes a nd lease payments directly from NGS, and both the Navajo Nation and Hopi Tribe receive roya lties and taxes from Peabody Energy associated with coal mined from the Kayenta Mine a nd used at NGS. EPA conducted an affordability analysis to determine whether requiring SCR at NG S would cause electricity generation costs to exceed the cost to purchase wholesale power on the open market. Based on this analysis, on a 25- year Net Present Value analysis, the increase in el ectricity generation costs associated with SCR is expected to be lower than the cost to purchase electricity on the wholesal e market, suggesting that

the cost increase from SCR should not cause NGS to shut down. This analysis further estimates that the NGS cost of electricity generation as a result of SCR will increase by 16%, or by 0.6 cents per kilowatt-hour (kWh). This generation cost increas e translates into an in crease of less than 1% to electricity customers of SRP.

In addition to impacts on electricity cust omers, numerous parties submitted comments on the ANPRM that raised concerns about the potent ial impact to water customers of the Central

Arizona Water Conservation Distri ct (CAWCD) that operates, main tains, and is responsible for repayment to the Federal Government for the Ce ntral Arizona Project (CAP). Reclamation’s 24% ownership share in power produced by NGS is used by CAP to pump surface water from the Colorado River to municipal, industrial, agricult ural, and tribal water users in Arizona. Excess power owned by Reclamation that is not used by CAP is sold and profits are deposited into the Lower Colorado River Basin Development Fund (D evelopment Fund). This fund was originally

authorized under the Colorado River Basin Act of 1968 for the purpose of repaying the federal government for the cost to build CAP, and subseque nt settlement acts with several tribes located in Arizona authorized use of the fund to pay the delivery portion of the cost of CAP water (fixed OM&R costs) for certain Indian Tribes, and to pay the costs to construct the delivery systems to bring CAP water to those Tribes. Reclamation, CA WCD, and several Tribes submitted detailed comments on the ANPRM outlining the potential e ffects that requiring SCR as BART for NGS might have on the cost of water and on Indian water settlement agreements.

Costs associated with Reclamation’s share of capital improvement s at NGS are passed

onto CAP customers in the variable OM&R cost s, i.e., “pumping energy rate”. Tribal and nonIndian agricultural (NIA) users of CAP water pa y only variable OM&R. Municipal and Industrial (M&I) CAP customers pay both th e variable OM&R costs and fi xed OM&R (delivery charges). EPA estimates that the increased electricity gene ration cost at NGS from the installation of SCR on all 3 units may result in an energy rate (variable OM&R) in crease of $8.15 per acre-foot (AF). Based on projected water rates, an increase of $8.40 per AF represents an estimated 6% increase in the CAP water rate paid by M&I users, and a 14. 5% increase in the CAP water rate paid by NIA

and Indian water users. NIA a nd Indian water users experience a higher percentage increase in

water rates than M&I users because NIA and I ndian water users pay less for water than M&I

users.

EPA understands that at least sixteen tribes in Arizona ei ther have water settlement agreements that allocate CAP water to the tribes in exchange for releas ing rights and claims to other surface and groundwater resources in Arizona (see nine trib es listed in first column of Table ES-2), or are in the process of negotiating CAP wate r settlement agreements (see eight tribes listed in second column of Table ES-2). Additionally, Table ES-2 lists five tribes located in Arizona

where EPA lacks information on th e tribe’s relationship to CAP wa ter. EPA understands that all tribes generally each have di fferent CAP allocations and unique water settlement agreements;Technical Support Document for NGS Proposed BART Determination | Page 138 of 138 therefore, potential impacts may be different for each tribe and should be considered individually. EPA’s preliminary assessments are based on li mited available information, and EPA requests

comments or additional information from the tribes listed in Table ES-2, and other tribes that may be affected by EPA’s proposed rulemaking for NGS.

In summary, for Factor 2, EPA’s affordability analysis suggests that the cost to produce power at NGS with SCR installed on all units sh ould be below the market prices of wholesale power and therefore SCR should not cause NGS to close. Additionally, increased electricity rates

to customers of the utilities that own NGS s hould be relatively low. EPA understands that a potential increase in water rates to tribes is a critical issue for them. We note that past pollution

control investments at this faci lity have made use of alterna tive financing methods that limited impacts on CAP water rates. Furthermore, the NREL report indicated that mechanisms may exist to help avoid or mitigate the estimated level of impact. EPA, in conjunction with DOI and DOE, have committed to work together on several shor t- and long-term goals, including innovative clean energy options for electricity generation and seek ing funding to cover expenses for the federal portion of pollution control at NGS. However, it is not clear at this time whether or what type of mechanisms might be available to lessen increased costs.

Given the extent of federal and tribal interests in NGS, EPA, DOI, and DOE have

committed to collaborate on several short- and lo ng-term goals, including analyzing and pursuing strategies for providing clean, affo rdable and reliable power, affordab le and sustainable water, and sustainable economic development to key stakeholders who currently depend on NGS. 249 The agencies will work together with stakeholders to identify and undert ake actions that support implementation of BART, including seeking fundi ng to cover expenses fo r pollution control or other necessary upgrades for the federal portion of NGS. The agencies will also work to jointly support a phase 2 report on NGS clean energy options and work with stakeholders to develop a roadmap for accomplishing the goals described above. EPA is proposing to determine that energy, non-air quality environmental impacts, and poten tial impacts to tribes of SCR, do not warrant elimination of SCR as the top control option under BART, however, the uniqueness of NGS does justify an exploration of altern atives to BART, within the fram ework of the Regional Haze Rule, to provide additional flexibility to allow the Department of Interior, affected tribes, and other stakeholders additional time to secure funding fo r Reclamation’s share of capital costs, or to develop a plan to mitigate potenti al economic harm to tribes.

Factor three explores the existing controls at the source. Units 1 – 3 at NGS are equipped with flue gas desulfurization units to reduce emissions of sulfur dioxide (SO 2 ) and electrostatic precipitators to reduce emissions of particulate matter. In 2 008, EPA issued a pre-construction permit authorizing SRP to install low-NO

x burners plus separated overfire air (LNB/SOFA) on Units 1 – 3 at NGS. Over 2009 – 2011, one unit per year at NGS was retrofit with new NO

x combustion controls to meet a permitted emi ssion limit of 0.24 lb/MMBtu. Because EPA, SRP, and Grand Canyon Trust, an environmental orga nization that filed comments on the proposed permit, agreed that EPA’s issuance of the PSD permit authorizing SRP to install and operated LNB/SOFA on Units 1 – 3 should not pr ejudice the analysis of additional NO

x controls under the BART requirement of the Regional Haze Program, EP A has determined that consideration of the existing controls at the NGS does not warrant elim inating SCR as the most stringent, technically

249 See Joint Federal Agency Statement Regarding Navajo Generating Station dated January 4, 2013, in the docket for this proposed rulemaking.Technical Support Document for NGS Proposed BART Determination | Page 139 of 139 feasible, cost effective NO

x emission control technology in our BART analysis. EPA notes that over the period from 2009 – 2018, the early installa tion of LNB/SOFA at NGS will result in over 90,000 tons more NO

x reductions than would have been achie ved if LNB/SOFA were installed in conjunction with a BART determination (with a five-year compliance timeframe by 2018). EPA is proposing to determine that existing controls at NGS do not warrant elimination of SCR as BART, but that the early NO

x reductions achieved from SRP’s volunt ary installation of LNB/SOFA in

2009 – 2011 warrants further consideration when weighing all five factors.

The fourth factor considers the remaining useful life of th e facility. Although comments to the ANPRM have cited the age of NGS and impe nding lease and right-of-way negotiations with the Navajo Nation as a rationale to consider a shorter useful li fe, EPA is proposing to determine that the default 20-year amortizati on period is most appropriate to use as the remaining useful life of the facility. Without an enforceable obliga tion to shut down early, EPA cannot consider a shorter amortization period in our analysis. Additionally, EPA furt her understands that the owners of NGS are pursuing a lease agr eement with the Navajo Nation to operate until 2044. EPA is proposing to determine that there are no issues with the remaining useful life of NGS that warrant rejecting SCR as BART.

The fifth factor examines the visibility improvement resulting from controls. The anticipated visibility benef its were modeled using CALPUF F Version 5.8. Background ammonia concentrations assumed in the model are an importa nt component of the visibility impacts model.

Based on results from four di fferent ammonia background scenarios, EPA determined that although the assumed concentration impacts the abso lute modeled visibility benefits, it does not change the ranking of controls, i.e., the most st ringent control technology , SCR, results in the highest modeled visibility improvement. All am monia background scenarios result in perceptible improvements in visibility at the most impacted Class I areas. EPA’s m odeling suggests that the baseline impairment at the eleven Class I areas affected by NGS ranges from over 1 deciview at the least-impacted Class I areas to over 8 de civiews at the most-impacted Class I area. The

installation of SCR in combinati on with LNB/SOFA on all 3 units at NGS is anticipated to reduce the visibility impairment caused by NGS by over 5 deciviews at the two most-impacted Class I areas (Grand Canyon National Park and Capitol R eef National Park). The greatest visibility

benefits from LNB/SOFA alone and SNCR in combin ation with LNB/SOFA is anticipated to be 2 and 3.5 deciviews, respectively. EPA is proposing to determine that the visibi lity benefits of SCR are significant and do not warrant its elimin ation as the top cont rol option for BART.

3. EPA’s Proposed BART Determination

The BART Guidelines give states (and EPA) discretion in determining the relative weight of each factor in making a BART determination. EPA is proposing to determine that the average

and incremental costs of SCR are cost effective and comparable to other facilities where SCR has been determined BART. Additionally, the visibil ity benefits from SCR are anticipated to be significant, and given the long expe cted useful life of NGS (at le ast until 2044), EPA is proposing, as BART, an emission limit of 0.055 lb/MMBtu, achievable with instal lation and operation of SCR within five years of the eff ective date of a final rulemaking.

However, as discussed in Factor 2, NGS is uni que compared to all ot her coal-fired power plants in the nation in terms of its relationshi p with water and tribal water users in Arizona.Technical Support Document for NGS Proposed BART Determination | Page 140 of 140 Because of the potential advers e economic impacts of higher wate r costs on tribes located in Arizona, EPA is proposing a BART Alternative c onsistent with the RHR (40 CFR §51.308(e)(2)).

Under the RHR, Alternatives to BART must achieve greater reasonable progress than would be achieved through the installation and operation of BART, and all necessary emission reductions must take place during the period of th e first long-term strategy for regional haze, which, for states that were required to submit RH SIPs in 2008, ends in 2018. EPA is proposing that consideration of compliance schedules be yond 2018 for alternative measures at NGS is appropriate for several reasons, including the singul ar importance of NGS to many tribes located in Arizona and their water settlement agreemen ts with the federal government, the numerous uncertainties facing the owners of NGS, the requ irement for NEPA review of a lease extension, and the early and voluntary inst allation of modern combustion controls over the 2009 – 2011 timeframe. EPA is proposing to find that an alterna tive is “better than BART ” if the adjusted total

NO

x emissions over the 2009 – 2044 timeframe (i.e., emissions remaining after subtracting 92,715 tons for the LNB/SOFA credit for early and vo luntary emission reduction s) are less than total emissions under our proposed BART determina tion for the same period (i.e., 358,974 tons).

We are proposing, as an alternative to BART, to require NGS to meet a NO

x limit of 0.055 lb/MMBtu on one unit per year in 2021, 2022, and 2023. EPA expects that the uncertainties

related to renewals of leases and other agreements would be su fficiently resolved to allow the owners of NGS to install new air pollution cont rols beginning in 2021 wi th certainty that NGS would continue to operate at least until 2044. As shown in Table 47 below, EPA has calculated

that the total amount of NO

x that will be emitted from NGS over the 2009 - 2044 timeframe under EPA’s proposed BART determination (i.e., co mpliance by 2018) will equal 358,974 tons. EPA

has also calculated that the total NO

x emissions over 2009 – 2044 under Alternative 1, with credit for the early and voluntary emission reductions, w ill be 338,189 tons. Based on its adjusted total

NO

x emissions, Alternative 1 meets the “better than BART” threshold (i.e. 338,189 tons is less than 358,974 tons). Therefore, EPA is proposing Alternative 1 (complian ce with BART emission limits on one unit per year in 2021, 2022, and 2023) as a better-than-BART alternative that results in greater reasonable progress th an would be achieved under BART.

Table 47: Analysis of Proposed BART Alternative

BART Alternative 1 Installation Years by 2018 2021, 2022, and 2023 Total Emissions over 2009 - 2044 (tons) 358,974 430,904 LNB/SOFA Credit (tons) n/a 92,175 Adjusted Emissions (tons) n/a 338,189

Better than BART? n/a Yes (338,189 tons < 358,974 tons)

EPA recognizes that some limited additional flexibility beyond the 2021 – 2023 compliance schedule under Alternative 1 may be appropriate, given the importance of NGS to a broad range of interests. EPA ha s evaluated two other alternative schedules, using the “better than BART” analysis framework described above, to evaluate additional time for compliance, i.e., compliance on one unit per year in 2023, 2024, a nd 2025 (Alternative 2) and compliance on one unit per year in 2024, 2025, a nd 2026 (Alternative 3).Technical Support Document for NGS Proposed BART Determination | Page 141 of 141 As shown in Table 48, Alternatives 2 and 3 do not meet the “better than BART” threshold because the adjusted emissions (accounting for the LNB/SOFA credit) exceed total emissions under BART. In Table 48, the amount total emissi ons from the alternatives exceed BART are NO

x emissions reduction deficits. For Alternatives 2 and 3, the NO

x emission reduction deficits are 15,179 tons and 33,160 tons, respecti vely, showing that as the compliance dates under a given alternative extend further into the future, the NO

x emission reduction deficit grows. Because

Alternatives 2 and 3 do not meet the “better than BART” threshold, EPA views Alternatives 2 and 3 as viable only if the owners of NGS achieve additional emission reductions to bridge the deficit

in NO

x emission reductions. These additional emission reductions could be implemented as shortterm (i.e., for some subset of the period 2009 - 2044) or long-term (i.e., achieved annually until 2044) measures.

As shown in Table 48, if the owners of NGS complied with the sche dule under Alternative 2, a short-term emission reduction bridge (impleme nted, for example, over a 10-year period from 2013 – 2023), the owners of NGS would need to achieve additional NO

x emission reductions of 1,518 tons per year. Similarly, implementing a long-te rm emission reduction bridge (for example, over the period of 2013 – 2044) would require additional NO

x emission reductions of 490 tons per year. The short and long term emission reduction bridges in Table 48 provide examples of how additional emission reductions might be dist ributed over time. The actual annual emission

reductions that NGS would need to bridge the NO

x deficit would depend, not only on the size of the deficit, but on the specific measures and time periods chosen by the owners of NGS.

Table 48: Analysis of Additional Alternatives

BART Alternative 2 Alternative 3

Installation Years by 2018 2023, 2024, and 2025 2024, 2025, and 2026 Total Emissions (tons) 358,974 466,869 484,849 LNB/SOFA Credit (tons) n/a 92,175 92,175 Adjusted Emissions (tons) n/a 374,154 392,134

Better than BART? n/a No No Emission Reduction Deficit (tons) n/a 15,179 33,160 Short-term Emission Bridge (tpy) (years in place) n/a 1,518 tpy over 2013-2023 3,015 tpy over 2013-2024

Long-term Emission Bridge (tpy) (years in place) n/a 490 tpy over 2013-2044 1,070 tpy over 2013-2044

EPA is requesting comment on technically an d economically feasible technologies or

mechanisms to serve as enforceable emission reduc tion bridges (whether short or long term) that

would allow consideration of alte rnatives that would not otherwis e meet the “better than BART”

threshold for NO

x (e.g., Alternatives 2 or 3 or other alternatives suggested by stakeholders during the public comment period for this proposed rule).

The Black Mesa Water Coalition and the To Nizhoni Ani, two Navajo non-governmental organizations (NGOs) provided to EPA their reco mmendations related to a just transition of Navajo Generating Station and th e Kayenta Mine to tribal rene wable energy projects at BlackTechnical Support Document for NGS Proposed BART Determination | Page 142 of 142 Mesa. 250 In general, the two NGOs recommended a replacement of Reclamation’s share of NGS with a large-scale renewable en ergy project at the Black Mesa Mine by 2019, retirement of the shares of NGS owned by LADWP and Nevada Powe r, and continued operat ion of the shares of NGS owned by SRP, APS, and TEP until 2029. After 2029, the groups recommend complete

retirement of NGS and conversion to solar en ergy. EPA does not have authority to require

Reclamation or other owners of NGS to transi tion away from NGS or coal-fired power. EPA encourages interested stakeholders to work colla boratively to explore additional Alternatives to BART that satisfy requirements under the CAA as well as goals of the stakeholders, and submit

these alternatives as comments to EPA. As st ated previously, if st akeholders develop an

alternative recommendation that meets CAA requirements, EPA may issue a Supplemental Proposal to put forth that altern ative, along with EPA’ s analysis of the alternative, for public

review and comment.

In weighing the statutory f actors, EPA believes that our BART determination for NO

x is appropriate for NGS. NGS is among the largest pow er plants in the nation, both in terms of its heat input capacity and in te rms of total emissions of NO

x . Therefore, EPA is proposing that SCR,

which is cost effective and will result in si gnificant visibility improvement, should not be eliminated as BART for NGS, because it is expected to continue operation for at least three more decades and is surrounded by eleven mandatory Fe deral Class I areas, including the Grand Canyon National Park. Because of the potential adverse econom ic impacts to tribes located in Arizona, we are proposing Alterna tive 1 as a “better than BART” Alternative that gives Reclamation and the other owners of NGS flexibility in the schedule for compliance, to resolve outstanding lease and rights-of-way agreements to ensure conti nued operation of NGS, and to allow time for Reclamation to work with other federal agencies to seek funding for the fede ral portion of the cost of controls, recognizing the impor tance of the continued operati on of NGS to numerous tribes located in Arizona and the broader regional economy.

250 See “Recommendation for Just Transition of the Navajo Generating Station and Peabody Coal Mines for the Black Mesa to Tribal Renewable Energy Project at Black Mesa”, in the docket for this proposed rulemaking. Black Mesa and To Nizhoni Ani also provided two additional documents related to the Navajo Aquifer: one is a resolution that the Navajo Aquifer be designated a sole-source aquifer, and one is an issue paper wr itten by the Natural Resources Defense Council. Both documents are also provided in the docket for this proposed rulemaking.