U.S. Environmental Protection Agency 

Region 9 

Response to Public Comments on Proposed Prevention of Significant

Deterioration and Tribal Minor New Source Review Permit 

Four Corners Power Plant – Selective Catalytic Reduction Project on Units 4 and 5

PSD Permit: NN 14-01

Tribal Minor NSR Permit: T-0002-NN

Prepared By: Lisa Beckham, Eugene Chen

Reviewed By: Gerardo Rios

December 2014

 

 
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1. Introduction – Summary of the Formal Public Participation Process

On July 24, 2014, the U.S. Environmental Protection Agency (EPA), Region 9 provided notice of, and 

requested public comment on, Region 9’s proposed permit to allow construction of pollution control 

systems called Selective Catalytic Reduction (SCR) at Units 4 and 5 of the Four Corners Power Plant 

(hereinafter “FCPP SCR Project”). The public comment period on the proposed permit for the FCPP SCR 

Project began on July 24, 2014 and closed on September 24, 2014. 

Region 9 announced the public comment period through public notices published in the Navajo Times

and Daily Times on July 24, 2014. Region 9 also distributed the public notices to the necessary parties 

in accordance with 40 CFR part 124, including notices sent by mail and email on July 25, 2014. Parties 

notified by Region 9 included agencies, organizations, and public members for whom contact 

information was obtained through a number of different methods, including requests made directly to 

Region 9 through Region 9’s website, contacts provided by the Navajo Nation Environmental 

Protection Agency (NNEPA), and other parties known to Region 9 that may have an interest in this 

action based on interest in previous actions within the Navajo Nation. 

The administrative record for our proposed permit for the FCPP SCR Project was made available at EPA 

Region 9’s office. Region 9 also made the proposed permit, the Fact Sheet, and most of the other 

supporting documents in the administrative record available through Region 9’s website. Region 9 also 

made the key documents available at the following public libraries and colleges: San Juan College in 

Farmington, NM, Diné College Shiprock Branch in Shiprock, NM, and Shiprock Branch Library in 

Shiprock, NM. 

As part of our public participation process for soliciting comment on the proposed permit, EPA held 

three formal public hearings. One public hearing was held on August 27, 2014 at the Nenahnezad 

Chapter House in Fruitland, NM, and two hearings were held on August 28, 2014: one at the Phil L 

Thomas Performing Arts Center in Shiprock, NM (afternoon) and one at San Juan College, Farmington, 

NM (evening). A court reporter was present at each hearing, as well as a Diné language interpreter for 

oral translation. 

Prior to each public hearing described above, EPA also held a public information meeting. The purpose 

of the public information meeting was to provide interested parties with additional information and an 

opportunity for informal discussion on the FCPP SCR Project. EPA responded to questions at these 

meetings but did not formally record remarks from those in attendance. However, attendees of the 

meetings were given the opportunity to submit written comments. 

EPA’s July 24, 2014 public notice for the proposed permit provided the public with notice of two of the 

public hearings. EPA received a request from a member of the public for an additional hearing. EPA 

accommodated this request and notice of the third public hearing and informational meeting – at the 

Phil L. Thomas Performing Arts Center on August 28, 2014 – was provided by mail and email on July 31, 

2014; in the Daily Times on August 1, 2014; and in the Navajo Times on August 7, 2014. 
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EPA received oral and written comments from numerous individuals at the hearings. During the public 

comment period EPA also received several comment letters by email and mail. All timely comments 

received equal weight, regardless of the method used to submit them. 

2. Region 9’s Response to Public Comments

This section excerpts the significant public comments received by EPA during the July-September 2014 

public comment period. Our responses to all significant comments made during the 2014 public 

comment period are provided following each comment. This document also includes an explanation of 

what changes have been made in the Final Permit as a result of those comments – see additional 

information in Section 3. In some instances similar comments are grouped together by topic into one 

comment summary, and addressed by one EPA response. The full text of all public comments and 

many other documents relevant to the permit are available through a link at our website, 

http://www.epa.gov/region9/air/permit/r9-permits-issued.html, or at www.regulations.gov (Docket ID 

EPA-R09-OAR-2014-0545). 

Comments and Responses on the Proposed Prevention of Significant Deterioration and

Tribal Minor New Source Review Permit for the Four Corners Power Plant Selective

Catalytic Reduction Project

Commenters:

Oral commenters 

· Victoria Gutierrez (also submitted written comments at a hearing) 

· Sara Jane White 

· Wayne Lane 

· R.G. Hunt 

· Brian Tremko 

· Mike Eisenfeld – San Juan Citizens Alliance 

· Mark Notah 

· James Pioche 

· Joe Allen 

· Johnson Brown (also submitted written comments at a hearing) 

· Virgil Frazier 

Written commenters 

· Scott Hicks - Virtual Technology 

· C. Kent Applegate, BHP Billiton Mine Management Company (BHP Billiton) 

· Stephen B. Etsitty, Navajo Nation EPA (NNEPA) 

· W. Gregory Kelly of the Frye Law Firm, on behalf of the Navajo Transitional Energy Company 

(NTEC). The NTEC comments also incorporated the BHP Billiton comments by reference. 

· John Barth of the Law Office of John M. Barth, on behalf of the San Juan Citizens Alliance and 

the Center for Biological Diversity (SJCA) 

· Victoria Stamper, preparer of a report attached to the SJCA comments (Stamper Report) 
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· Vincent H. Yazzie 

· David C. Bloomfield, Arizona Public Service Company (APS) 

· Unidentified Commenter who submitted a comment directly to the docket without 

identification 

Health impacts

Comment 1:

(Commenters: Victoria Gutierrez, Sarah Jane White, Joe Allen) 

Commenters are concerned that FCPP negatively impacts the health of the residents in the area. 

Excerpts of representative comments on this topic are as follows: 

The air quality in the Four Corners is very poor and it's been this way for many years. We previously 

didn't pay attention to it and now it’s gotten much worse. We have two power plants, the San Juan 

Generating Station and the Four Corners Power Plant, which have been messing up our air and slowly 

getting worse. 

You may want to talk with tribal groups about raising environmental justice concerns at the hearing. A 

study at Los Alamos Labs here in New Mexico states "Air pollution and greenhouse gas emissions from 

the Four Corners Power Plant and the San Juan Power Plant makes this area, the Four Corners San Juan 

Basin, the highest and most polluted area in the entire country." The commenter submitted a press 

release from the Los Alamos National Laboratory titled “Power plant emissions verified remotely at 

Four Corners sites," which is available in the administrative record for this action. 

Based on the studies from Los Alamos, it's obvious that we have very poor air quality in the Four 

Corners. 

My family, friends, neighbors, and others living near the power plant suffer from respiratory illnesses 

and heart disease. 

We have health problems, including respiratory problems, heart problems, kidney problems, brain 

problems, and digestive problems. All of these problems come from the bad air pollution that we 

breathe 24 hours a day. And sometimes you can smell it. 

There are a lot of health risks related to the FCPP. A lot of people have health issues all the way down 

to the preschool level. We have respiratory ailments like asthma and many other related respiratory 

health issues. We have preschoolers that have health issues. My own kids and grandkids have 

cumulative health issues and problems from the toxic pollution. These health risks are related also to 

our gardens, to our livestock, to the ground that we walk on. For over 50 years we've been in the 

pollution of FCPP. When we go to work, it gets onto our vehicle, it gets onto our clothes. We bring fly 

ash contaminants home to our kids. It affects our health through respiratory complication, heart 

disease, related brain effects and headaches. It blows in the wind, downwind of communities that live 

in the area. We have premature births. Many kids have been affected. The FCPP is a big well of toxic 

pollutants that affects everybody. Some of the toxins have no smells, no taste. We need to get away 
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from fossil fuel and go into the clean energy. We've been in it for 50 years. I think it's time to phase out 

of fossil fuels. We need to close the power plant. And with every improvement, it will never move 

away from all the toxic pollution that we encounter every day. 

All these years we've been breathing this pollution and people say, "My kids, my kids." I hear that a lot, 

but isn't it kind of too late for some of the kids that breathed in all this pollution? I care about the 

grandmas, the grandfathers, the kids and all the people that live around these two power plants. So it's 

good that you guys are putting this in. What people want is solar, wind power, and stuff like that. 

Response 1:

The EPA appreciates the commenters’ concerns for the health and wellbeing of their community. The 

area in which the FCPP is located is currently designated as attainment (or unclassifiable) for all of 

EPA’s National Ambient Air Quality Standards (NAAQS). EPA sets the primary NAAQS limits to protect 

public health, including the health of at-risk populations such as people with pre-existing heart or lung 

disease (such as asthmatics), children, and older adults. In addition, the EPA sets secondary NAAQS 

limits to protect public welfare, including protection against visibility impairment, damage to animals, 

crops, vegetation, and buildings. 

The FCPP SCR Project will decrease NOX emissions from the FCPP by 19,000 tons per year, and will only 

cause a significant net emissions increase for sulfuric acid mist (SAM). Although the PSD regulations 

apply when a project causes a significant net emissions increase in SAM, there is no NAAQS for SAM. 

Therefore, it was not within the scope of the FCPP SCR Project for EPA to conduct an analysis of 

impacts of this Project on any NAAQS and the SCR Project will not cause or contribute to a violation of 

a NAAQS. 

Regarding the study by Los Alamos Labs identified by one commenter, EPA recognizes that the FCPP is 

a large point source of air pollution as stated in the press release provided by the commenter, and 

agrees that the area near the FCPP is an environmental justice community. However, the commenter 

has not identified any particular environmental justice concern associated with the FCPP SCR Project or 

how environmental justice concerns should influence the outcome of this particular action. Please see 

our response to Comment 15 regarding environmental justice concerns and the environmental justice 

analysis prepared for this action. We also note, this study is not relevant to this action, and we did not 

review the study beyond the press release provided by the commenter, because it specifically looked 

at new technologies for verifying emissions from space and not at determining the most polluted area 

in the country. One major impact of the FCPP SCR Project is to reduce the emissions of NOX from FCPP 

by over 19,000 tpy, resulting in a significant beneficial effect on ambient air quality. 

Regarding concerns of emissions of air toxics, consideration of these pollutants (also called “hazardous 

air pollutants”) is outside the scope of this permitting action – the impacts of regulated NSR pollutants 

from the installation of SCR on Units 4 and 5. Section 112(b)(6) of the CAA states: “The provisions of 

part C of this subchapter (prevention of significant deterioration) shall not apply to pollutants listed 

under this section.” See also, Wildearth Guardians v. USEPA, 759 F.3d 1196, n.8 (10th Cir. 2014). 

However, EPA promulgated the Mercury and Air Toxics (MATS) Rule in February 2012 that applies to 

Units 4 and 5 at the FCPP. The MATS Rule sets new limits on mercury and other air toxic emissions for 
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sources like the FCPP to meet the Maximum Achievable Control Technology. The FCPP will have to 

comply with the requirements of this rule. Additional information is available on EPA’s website at: 

http://www.epa.gov/mats/. 

Due to the potential health impacts from the FCPP, some commenters would prefer to use renewable 

energy, such as solar and wind power, instead of the fossil fuel at FCPP. However, requiring 

consideration of switching the energy source of FCPP away from fossil fuel is outside the scope of this 

permitting action and would fundamentally redefine the project. EPA’s Environmental Appeals Board 

(EAB) has held that consideration of alternatives that would fundamentally redefine a project do not 

need to be evaluated under the PSD program. See In Re Prairie State Generating Company, 13 E.A.D. 1 

(EAB 2006), affirmed in Sierra Club v. EPA, 499 F.3d 653 (7th Cir. 2007).

We appreciate the commenters’ concerns for health impacts and environmental justice (which is 

discussed further in our response to Comment 15), however, we continue to conclude that the FCPP 

SCR Project will not result in disproportionately high and adverse human health or environmental 

effects on minority populations and low-income populations. The FCPP SCR Project will result in 

substantial reductions of NOX emissions and the increases in SAM emissions are not expected to result 

in adverse health effects to any population, as discussed in more detail below, including responses to 

Comments 11 and 15. 

Climate Change

Comment 2:

(Commenters: Victoria Gutierrez, Sara Jane White) 

Commenters believe that FCPP contributes to climate change, as excerpted below: 

The climate change here is really bad. We are experiencing dust storms with zero visibility mimicking 

the dust bowl of the 1930s. There is zero vegetation, downsizing of livestock, and severe drought and 

water shortage. 

There is very bad climate change. All you see is sand dunes, we lost a lot of vegetation, we have 

droughts, and we have no snow in the wintertime. It has a lot to do with how our air is. 

Response 2:

The EPA appreciates the commenters’ concerns regarding climate change. The FCPP SCR Project is not 

subject to review under the PSD program for greenhouse gas emissions, the group of pollutants that 

contribute to climate change. The only pollutant subject to the PSD regulations for the FCPP SCR 

Project is SAM. 

For more information regarding EPA’s actions related to carbon pollution from existing power plants 

please visit: http://www2.epa.gov/carbon-pollution-standards. We note that on November 4, 2014, 

EPA issued a supplemental proposal for controlling carbon pollution from existing power plants in 

Indian country, including for FCPP and the Navajo Generating Station. See 79 Fed. Reg. 65481 (Nov. 4, 

2014) 
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Coal Ash and Cumulative Impacts

Comment 3:

(Commenters: R. G. Hunt, Sara Jane White, Mike Eisenfeld, SJCA) 

Some commenters are concerned about the impact that coal ash from FCPP and the San Juan 

Generating Station and other pollution has on the area. Their concerns are excerpted as follows: 

The existing pollution problems in the Four Corners region of the U.S. Southwest are enormous. EPA is 

a Cooperating Agency on the Draft FCPP/Navajo Mine Environmental Impact Statement (EIS) released 

in March of 2014. On June 26, 2014 EPA Region 9 commented on the Draft EIS, 

“Based on our review of the DEIS, we have rated the Preferred Alternative A as 

Environmental Concerns – Insufficient Information (EC-2) (with enclosed “Summary of 

Rating Definitions”). Our concerns regard the existing contamination of groundwater 

from coal combustion residue (CCR) disposal and the need for enforceable 

commitments regarding future CCR management, monitoring and remediation. We 

also have concerns regarding the assessment of cumulative health impacts from 

continued operation of the project, given the severely compromised existing public 

health environment. Pollutants from the disposal of CCR have contaminated 

groundwater at the FCPP.” Signed by Kathleen Martyn Goforth, Manager, 

Environmental Review Section, EPA R9. 

We agree that there is extensive pollution in the vicinity of the Four Corners plant that is adversely 

affecting public health and the environment. We ask EPA to deny the PSD permit application by APS as 

one means to prevent additional future contamination and future adverse health effects. We also 

request that EPA disclose in the administrative record for this proceeding the basis for its 

determinations that CCR has contaminated groundwater at FCPP and the severely compromised 

existing public and health environment. The cumulative impacts associated with over 50 years of 

FCPP/Navajo Mine operations causing groundwater contamination and severely compromised existing 

public health and the environment must be fully evaluated and disclosed to the public before 

approving a PSD permit for FCPP. In addition, EPA must review historic Toxic Release Inventories for 

the region and determine how adding additional SAM and other pollutants (including particulate 

matter) to the region will cumulatively impact the Shiprock area. Oil and gas activities in the region are 

thought to be increasing methane, volatile organic compounds (VOC), and hydrogen sulfide emissions. 

This must be assessed in the EPA PSD permit process, as well as scientifically assessed in the Draft EIS 

for FCPP/Navajo Mine, of which EPA has a critical role as a Cooperating Agency. 

Another commenter notes that he has been all around APS and the surrounding area, and the bad 

thing about it is that when they take pollution out of the air, they put it in a mine, just like the mess at 

San Juan. They have taken all the fly ash and the bottoms out of the boilers and buried it in the mines. 

Then they dewater the mines, and in doing so, when these people leave town, the water is going to get 

back into the mines and it's going to be a cesspool. It would become toxic waste. 
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They are never made to clean up anything they have done, like at the site where there are 80 acres of 

fly ash. Behind my house, it's nothing but a waste dump. What they take out of the boilers they're 

going to put right back in the ground. And a hundred years from now San Juan River will be a dump. 

The water will be worth nothing and the water in a desert is worth a fortune. So many people don't 

understand that. But across the reservation a lot of the people are drinking out of the old artesian 

wells and having to haul their water. I hope EPA makes the power plants take the local people around 

once a week and even to school to show them what they have done, the messes that they have made. 

Instead of covering it up and hiding it, it needs to be brought out in the open. Because we don't need 

our kids 50 years from now saying, "What in the hell happened? Where in the hell are they all at?" The 

only people who are going to benefit from this are the stockholders. It's not going to be the ratepayers, 

because the ratepayers are going to have to pay for it. And the sad part about it is that the ratepayers 

are poor, innocent people who cannot afford it. The stockholders are billionaires making fortunes. You 

should make the people who own it, just like the stockholders, pay for this kind of nonsense, instead of 

innocent people who are having a hard time making ends meet. 

If you make a mess and you're a little seven-year-old kid, you get punished. But these are men that are 

making a mess and walking away and leaving it. There's no excuse for that. The Navajo Reservation, 

just like the land out behind us, is very sacred any way you look at it, and people need to take 

responsibility for their messes. That's my main concern. I'm all for your permit, but make the 

stockholders pay for it, not the innocent ratepayers. 

We have a problem with coal ash from the Four Corners power plant. I don't know if it is going to be 

listed in the permit, but that is another issue. The coal ash is not being maintained and it is getting 

larger and wider and its right near Chaco Wash, and the Chaco Wash runs into San Juan River and 

many people are dependent on the river. We've been asking for water studies, and that water study 

hasn't happened yet. 

A lot of the coal ash has been leaking and all the ash is coming from the APS. When the wind blows you 

can see the white ash blowing to the east. And there's a lot of people that live in the area, Fruitland, 

Kirtland and Farmington, and beyond, including kids and livestock. 

Response 3:

The EPA understands that the commenters are concerned about the impacts of coal ash and other 

cumulative impacts of the FCPP, but these comments are outside the scope of this immediate 

permitting action for the FCPP SCR Project. The EPA would not have a legal basis for denying this air 

permit for the FCPP SCR Project because of concerns unrelated to this action, which is limited to 

evaluating the air impacts associated with installation of SCR technology on Units 4 and 5. 

However, the EPA has taken other steps to reduce air emissions from the FCPP. EPA has previously 

promulgated two Federal Implementation Plans (FIPs) regulating FCPP pursuant to other authority in 

the CAA. In May 2007, EPA promulgated a FIP requiring FCPP to meet certain emission limitations, 

including an emissions limitation for sulfur dioxide (SOX) emissions that resulted in reducing SOX

emissions by more than 90%. See 72 Fed. Reg. 25698. In August 2012, EPA finalized a Best Available 

Retrofit Technology (BART) FIP requiring that FCPP reduce NOX emissions from the FCPP to improve 
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visibility in surrounding Class I areas. In order to meet that requirement, FCPP is installing SCR on Units 

4 and 5 to reduce emissions approximately 80%. The 2012 FIP also contained certain restrictions on 

emissions of fugitive dust from the coal storage and handling operations at FCPP. See 77 Fed. Reg. 

51620. 

Regarding CCR, the concerns raised by the commenters are outside the scope of the CAA and this 

immediate permitting action. Currently, CCR is considered exempt wastes under an amendment to the 

Resource Conservation and Recovery Act (RCRA). However, EPA is proposing to regulate CCR for the 

first time to address the risks from the disposal of the wastes generated by electric utility and 

independent power producers. See 75 Fed. Reg. 35128. EPA is expected to take final action on the 

proposal in December 2014 per a consent decree deadline. Additional information is available on EPA’s 

website here: http://www.epa.gov/osw/nonhaz/industrial/special/fossil/ccr-rule/. 

The only action under review here is the FCPP SCR Project involving installation of the NOX pollution 

controls on Units 4 and 5, which requires a Clean Air Act permit for SAM emissions. The EPA has 

determined that APS will meet the requirements of the PSD and Tribal Minor NSR programs through 

the conditions set forth in the PSD permit being finalized today. 

The concerns raised by commenters are more appropriately addressed in other actions such as the 

current NEPA review referenced by the commenters, as well as in any proposed NPDES permit for the 

FCPP. Section 793(c) of the Energy Supply and Environmental Coordination Act of 1974 (15 U.S.C. 

793(c)(1)) exempts actions under the Clean Air Act from the requirements of NEPA. As such, the type of 

cumulative analysis suggested by the commenters is not applicable to this action. EPA’s analysis is 

limited to the requirements of the PSD and Tribal Minor NSR programs. 

To the extent the commenters are suggesting that EPA must look at TRI data related to SAM emissions 

as part of our analysis under the PSD program, we disagree. The TRI is an important tool for learning 

about toxic emission releases in your area, and can help inform academic research, public policy 

development, sustainable corporate governance and environmental education. However, it is unclear 

how commenters are suggesting this information should inform EPA’s decision under the PSD and 

Tribal Minor NSR programs. We note that the only facility listed in the TRI for Shiprock and Fruitland, 

New Mexico is the FCPP. 

For this action, the EPA is only evaluating the impacts of NSR regulated pollutants under the PSD and 

tribal minor NSR programs. The EPA determined that the FCPP SCR Project does not result in a 

significant net emissions increase for any NSR regulated pollutant other than SAM. In addition, the EPA 

has made a BACT determination and reviewed the potential ambient impacts of SAM emissions. To the 

extent the commenters are requesting EPA to consider toxic air pollutants listed in Section 112 of the 

CAA, we note that Section 112(b)(6) states: “ The provisions of part C of this subchapter (prevention of 

significant deterioration) shall not apply to pollutants listed under this section.” See also, Wildearth 

Guardians v. USEPA, 759 F.3d 1196, n.8 (10th Cir. 2014). 

One commenter also indicates that stockholders not ratepayers should pay for environmental damage 

cleanups. This comment goes beyond the scope of our proposed action. 
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Navajo Mine

Comment 4:

(Commenter: Joe Allen) 

Commenter expressed concerns regarding the Navajo Mine, which supplies coal to FCPP: 

I grew up on the top here where the Navajo Mine is, and my dad and grandma and I used to herd 

sheep for my grandma when I was 10 years old, when they first started digging up on top the hill, and I 

remember everything. Everything used to be green. You could see everything, like canyons, rock 

formations, some burial grounds. 

And for so many years I just look at that coal mine going, digging up burial grounds, ruining Mother 

Earth. Why don't they go underground instead of tearing up everything? It hurts me when I see this. 

When I was a little kid, it used to be nice and green with rock formations, but it's all torn up now. You 

go up there now and you see missing blooms, nothing. I don't know what all the rocks are for. I don't 

why they put that there. When they try to plant, nothing grows. 

And why is the whole area fenced off? I can't even go for a walk up there anymore. Every time I go for 

a walk, they call security. And I grew up there. I've got my Mom, my Dad, my Grandma, my Nephews, 

and everybody buried up there, and they have a gate there and I can't see them anymore unless I get a 

security guard to come meet me. It hurts me because everything is fenced off. Why don't they just 

open the gate back up for us and let people herd sheep again like it was before? It hurts when you see 

something like that. 

And the whole area is just dead now, no plants, nothing. I used to go walk the mountains up here, the 

hills; I can't do that anymore. People have horses. They can't go there because they have to get 

permission to go there. We used to just walk in there and get our horses, bring them back. We can't do 

that anymore. 

Response 4:

The EPA recognizes that the commenter is very concerned about the Navajo Mine and is frustrated by 

the limited access available to this area. However, the FCPP SCR Project is an action that is only related 

to the installation of SCR on Units 4 and 5 to provide a substantial reduction of NOX emissions. The 

scope of our authority is prescribed by the PSD regulations as those regulations apply to the significant 

net emissions increase in SAM. Our authority does not extend to regulating the Navajo Mine. 

Therefore, this comment is generally outside the scope of the proposed permit action for the FCPP SCR 

Project. 

Improvements to the Environment

Comment 5:

(Commenter: Mark Notah) 

I appreciate having the opportunity to speak here and that you guys are installing the filtering system 

for the APS project; anything to help the environment or the economy. The tribe has done quite a bit 
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for the environment. People may think that we can do more, but I like what we're doing, the direction 

that we're taking at APS. Any time that something is done for the environment in the community, it's a 

positive outlook for us, the Navajo Tribe and APS. It could have been easy just shutting everything 

down and just leaving, but they decided not to. 

Response 5:

This comment generally supports EPA’s proposed action, and does not suggest that EPA should deny or 

revise the proposed permit. 

Economic Impact of FCPP

Comment 6:

(Commenters: Wayne Lane, Brian Tremko, James Pioche, Johnson Brown, BHP Billiton, NNEPA, NTEC, 

Unidentified Commenter) 

Comment excerpted below discuss the economic benefits of continued operation of FCPP. 

I and other small business owners want to see the power plant stay in business and not have to shut 

down because it would affect our business and our employees. We would have to lay off because of 

the loss of business that we could not pick up in the area again. Also, if APS is not allowed to have the 

permit to go ahead with the project it would affect the Navajo Tribe because they just purchased the 

mine from BHP. As a small business owner, I am asking that they give the permit to APS to continue 

their plant work in Farmington or the Four Corners. 

Environmental protection is important. And I think from what I've been hearing, reading and from 

speaking with you folks tonight, that this seems to be pretty good technology. Certainly it's evolving 

and improving on a constant basis. We have to remember that technology is jobs, and the jobs that are 

affected in this area are carpenters, pipefitters and electricians; people that work in this community. 

They provide the dollars that feed the restaurants, the stores, and ultimately, they affect the whole 

community. These are jobs we're talking about. This community has already been impacted by the 

shutdown of the other three units at the plant. So we would like to see this process move forward. We 

think that the technology is good and we support it. We do believe that the jobs it will create will help 

this community continue to grow. It will help the Navajo workers continue to have good jobs, and 

those are few and far between on the Nation right now. We'd like to see them have that opportunity 

until other things are developed, and this project will let that happen. So consider the jobs, the safety 

and environmental protections that are being incorporated into the system, and the effects on the 

local economy. This project is a win and we support it. 

My thoughts are that the EPA thoroughly studied the problem and they've investigated several 

different types of ways to clean up the air. I know they will monitor their air pollution. I approve the 

project being installed with SCR. I also support them. The reason I support them is because I do not 

want our people to be laid off and be left without jobs. This is their livelihood and where they provide 

the jobs that they have for their children. 
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Commenter provides a summary of NTEC’s purchase of the Navajo mine, which supplies coal to the 

FCPP, after FCPP’s decision to retire three older EGU’s to comply with the EPA’s BART determination. 

The NTEC plans to use profits from the Navajo mine to eventually transition the Navajo’ Nation’s 

energy economy into renewables and clean coal technologies. Consistent with the federal trust 

responsibility to NTEC and the Navajo Nation, and federal requirements under the Clean Air Act, the 

PSD permit would allow APS to install SCRs on units 4 and 5 to comply with BART requirements, 

allowing continued operation of the Navajo Mine and its attendant, and tremendous value to the 

Navajo Nation. If the PSD permit is issued, the Navajo Nation will continue to receive royalties and 

taxes for the provision of critical governmental services, well-paying jobs at FCPP and the Navajo Mine 

predominantly filled by Navajo Nation tribal members, and NTEC will begin growing as an asset of the 

Navajo Nation and the Navajo people, with its profits available to help fund the transition to clean 

energy technologies for the benefit of the Navajo Nation and the natural environment. This will allow 

NTEC to eventually transition the Navajo Nation from a source of conventional coal-fired electrical 

generation to a provider of electrical energy by emerging technologies, meeting regulatory and societal 

requirements of the future. 

A recent socioeconomic study (Four Corners Power Plant and Navajo Mine, An Economic Impact 

Analysis, Arizona State University, March 4, 2013) concluded the following about operations of the 

Navajo Mine and FCPP: 

· Over a 25-year period, the combined FCPP and Navajo Mine operations would support 

approximately 760 full-time employees representing an annual payroll of approximately $100 

million. 

· In addition to direct jobs, the combined operations would generate approximately 1,576 jobs in 

New Mexico from supplier purchases, consumer spending by employees and from spending of 

state and local tax revenues annually. 

· The combined labor income from these jobs would generate approximately $165 million 

annually and a gross New Mexico state product of approximately $431 million. 

· The Navajo Nation would enjoy approximately 42,574 job-years of employment, income of $1.8 

billion, and a Navajo Nation GNP of $2.45 billion over the 25-year period. 

Approximately 80 percent of the jobs at FCPP and the Navajo Mine are held by members of the Navajo 

Nation. The long-term benefit from taxes and royalties paid by these operations to the Navajo Nation 

and the direct and indirect jobs supported by these operations are substantial in promoting Navajo 

self-sufficiency and self-determination and protecting the Nation's trust assets. 

As an employer of 20 in Southern Illinois I wish to comment on the impact of essentially halting coal 

fired electrical generation. It would affect my business as we supply product to the local mines and also 

our whole local economy that is heavily dependent on mining. Clean air is important but jobs and 

economics are as well. It will take a combination of all sources of power generation to solve our 

problems, coal, gas, and nuclear. Keep coal viable, keep our energy prices reasonable. 

I've worked at Four Corners Power Plant for 33 years. It's done a lot for me, and I have done a lot for 

them, also. I speak for my fellow co-workers, none of whom are here. I'm a welder for APS, and I have 

worked up through the ranks as a janitor and a laborer. APS has gotten me a mortgage where I can 
FCPP SCR Project 

Response to Comments 

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now call home. I feel fortunate to be working for APS, which has provided me a lot. I put my kids 

through school. 

When it comes down to anything that deals with EPA, we get on it. If pumps fail, we work around the 

clock to try and fix it to meet the requirements of the EPA. We comply with all the regulations. 

APS is installing SCR so the community can enjoy their livelihood. We have worked around the clock 

trying to keep emissions down and the installation of SCR will help us even more. Please consider what 

we are trying to do to clean up the plant. 

I'm proud to say that I work for APS. I have 10 more years to retire, and my kids are looking forward to 

working at the plant, also. 

Response 6:

The EPA acknowledges these comments regarding the economic impacts of the FCPP on the 

surrounding community. None of these comments indicate that EPA should deny or revise the 

proposed permit. 

Support for Proposal 

Comment 7:

(Commenter: NNEPA) 

Commenter generally supports EPA proposals addressing reductions of air pollutants from stationary 

sources, and supports the currently proposed permit pursuant to which the installation of SCR systems 

and equipment at FCPP will achieve increased NOX reductions and improve visibility within the Four 

Corners Region. The permit is necessary to authorize construction of the SCR controls under 40 CFR 

52.21 and to fulfill the Best Available Retrofit Technology ("BART") requirements for FCPP under 40 CFR 

49.5512. Commenter’s more specific suggestions appear in subsequent comments. 

Response 7:

This comment generally supports EPA’s proposed action, and does not suggest that EPA should deny or 

revise the proposed permit. However, the commenter provided comments suggesting other minor 

changes to the permit, which are addressed in subsequent responses. 

Investing in Renewable Energy

Comment 8:

(Commenters: Victoria Gutierrez, Mike Eisenfeld, SJCA) 

Arizona Public Service and other FCPP owners should not be investing in SCR Units 4 and 5 and instead 

should promptly retire these units and reinvest in renewable energy generation sources on the Navajo 

Nation. 

The Four Corners region gets all the pollution but none of the power from the FCPP. Although this 

project will reduce nitrogen dioxide, it will increase SAM and possibly other pollutants, including CO2. 
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Response to Comments 

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We want FCPP closed and replaced with clean renewable energy generation (of which EPA is uniquely 

qualified to assist in the needed transition from reliance on fossil fuels.) 

Response 8:

The EPA acknowledges these comments regarding investments in renewal able energy and the desire 

to close FCPP. However, these comments do not specifically address the EPA’s proposed permit and 

associated analysis for the FCPP SCR Project. To the extent the commenters are suggesting that EPA 

must consider the shutdown of FCPP as a lower emitting technology for the purposes of the best 

available control technology (BACT) for SAM emissions, we disagree. Consideration of this option 

would fundamentally redefine the project and does not need to be considered under a BACT analysis. 

See In Re Prairie State Generating Company, 13 E.A.D. 1 (EAB 2006), affirmed in Sierra Club v. EPA, 499 

F.3d 653 (7th Cir. 2007).

Air Quality Analyses

Comment 9:

(Commenters: Victoria Gutierrez, Mike Eisenfeld) 

Some commenters expressed concern about the results of the air quality analyses that have been 

conducted, as follows: 

If FCPP owners choose to install SCR on Units 4 and 5, EPA should make changes to the proposed PSD 

permit. The purpose of the FCPP/Navajo Mine National Environmental Policy Act process was to fully 

disclose all environmental impacts from a project so that decision-makers can make decisions 

regarding a project, which would avoid or minimize adverse impacts or enhance air quality. 40 CFR 

1502.1. The Draft EIS for the continued operation of the FCPP Units 4 and 5 disclosed several 

potentially adverse air impacts. 

Modeling done for EIS of actual hourly emissions for Four Corners Power Plant Units 4 and 5 paired 

with actual weather data showed one-hour SO2 concentrations that were 98 percent of the one-hour 

SO2 NAAQS. But that wasn't based on the units' allowable emission rate, and it also did not reflect the 

future SO2 emission rates from Units 4 and 5, which are being projected to operate at higher capacity 

factors with the shutdown of Units 1 through 3. EPA should model future one-hour SO2 emissions and 

impose one-hour average SO2 limits on Units 4 and 5 as part of this permit to ensure that the one-hour 

average SO2 National Ambient Air Quality Standards are not violated by the Four Corners Power Plant. 

Similarly, the modeling for the DEIS showed concentrations that were very close to the one-hour NO2

NAAQS, the eight-hour average ozone NAAQS, and the 24-hour PM2.5 NAAQS. These modeling analyses 

were not based on allowable emission rates reflective of the future operations of these units and 

associated emissions sources. EPA should model the NO2, ozone, and PM2.5 emissions and impose 

emission limits on Units 4 and 5 that ensure compliance with NO2, ozone, and PM2.5 national ambient 

air quality standards. Given that FCPP is on tribal lands with no Tribal implementation plan in place to 

protect the NAAQS. Thus, EPA should use the tribal minor New Source Review process, which 

authorizes EPA to impose emission limits to meet the NAAQS, to ensure that the continued operation 
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Response to Comments 

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of FCPP Units 4 and 5 will not adversely affect public health. EPA must impose emission limits on these 

units to ensure the NAAQS won't be violated. 

Response 9: 

EPA Region 9 is a cooperating agency for the NEPA action identified by the commenter and has 

participated in the current NEPA action and Environmental Impact Statement process separately from 

this Clean Air Act permitting action. Please see Section 793(c)(1) of the Energy Supply and 

Environmental Coordination Act, which states that actions under the Clean Air Act are not major 

Federal actions significantly affecting the quality of the human environment within the meaning of the 

NEPA. As such, EPA actions under the CAA are not subject to NEPA. 

Specifically, the commenter asserted that, based on modeling of the FCPP performed for a draft 

Environmental Impact Statement (DEIS), the 1-hour SO2, and 1-hour NO2, 24-hour PM2.5, and 8-hour 

ozone impacts are all very close to the respective NAAQS, and warrant emission controls on FCPP. 

However, none of those impacts reflect the emissions from the project being implemented for this PSD 

permit, which involves SAM increases and NOX emission decreases. Under the PSD program, EPA has 

no authority to impose controls for those pollutants for which there is not a significant net emission 

increase associated with this Project. 

Nevertheless, the commenter is correct that impacts modeled for the EIS are relatively close to the 

NAAQS for those pollutants. Although not necessary to address this comment, since it is outside the 

scope of this action, we are providing additional information for the commenter’s benefit. For SO2, 

NO2, and PM2.5, this issue was addressed in the modeling report for the DEIS and in responses to EPA 

comments on that DEIS. For several reasons, the modeled impacts reported for the DEIS were 

conservatively high, and so the true concentrations are lower than the respective NAAQS levels than 

indicted in the DEIS. For both SO2 and NO2, background concentrations added to the modeling results 

included some of the impact of FCPP itself, leading to some “double-counting” of FCPP impacts. (EIS 

Modeling Study Draft, p.3-18) In addition for SO2, the highest predicted impacts are due to downwash 

of the pollutant plume caused by the presence of the boiler buildings. As portrayed in the model, the 

buildings are solid, whereas in reality the boilers are open frameworks, which cause far less downwash 

and result in lower concentrations. The unrealistically high concentrations in any case occur in only a 

very small area within about 2 km to the southeast. (Responses to EPA comments, pp.4-5, p.9, and 

p.10). For PM2.5, the DEIS modeling added a background concentration that was the highest of those 

available nearby, representing a conservative approach. (Responses to EPA comments, p.4). Also, the 

DEIS modeling followed an older EPA-recommended procedure, in which the highest modeled 

concentration is added to the 98th percentile of the monitored background to get the total value for 

comparison to the NAAQS. But under a more recent EPA guidance procedure, the 98th percentile from 

the modeling is added to the 98th percentile from the monitor under some circumstances, such as 

when the PM2.5 is due to direct emissions rather than formed secondarily from precursor compounds. 

(Guidance for PM2.5 Permit Modeling, pp.58-59). This is less conservative than the DEIS approach, and 

is applicable to FCPP since the highest concentrations are due to direct fugitive emissions. (Responses 

to EPA Comments, p.5). Since the DEIS modeling was performed in a conservative fashion for SO2, NO2, 

and PM2.5, EPA did not recommend further control of FCPP emissions in its comments on the DEIS. 
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Response to Comments 

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Finally, for ozone, the maximum 8-hour ozone concentration modeled was 70.1 ppb. The maximum 

impact due to FCPP was only 4.7 ppb, and did not occur at the location of the overall maximum. More 

typical FCPP ozone impacts were 2-4 ppb. (Draft EIS Ozone Impact Assessment, p.4-4 and p. 4-7) Thus, 

only a small minority of the modeled ozone was attributed to FCPP; and since this project actually 

entails a decrease in the emissions of NOX, an ozone precursor, the FCPP contribution is smaller still. In 

our review of the DEIS we determined that since ozone is a regionally-formed pollutant, due to the 

combined emissions of many sources over a large area, the small contribution of FCPP to an ozone 

concentration that meets the NAAQS does not warrant emission controls in this context. Should the 

area at some point become an ozone nonattainment area, a regional analysis and new Clean Air Act 

planning requirements for the area could evaluate controls on stationary and other sources. 

Regarding the comment related to the Tribal Minor NSR rule, EPA acknowledges that Navajo Nation 

does not have a Tribal Implementation Plan in place (nor is it required to) for ensuring attainment and 

maintenance of the NAAQS. Currently, all areas of Navajo Nation are designated attainment (or 

unclassifiable) for each NAAQS. However, there are several Federal Implementation Plan requirements 

in place that apply within Navajo Nation and that are administered by EPA Region 9 – including the PSD 

program at 40 CFR 52.21 that is the subject of this action. Specifically, the Tribal Minor New Source 

Review (NSR) program referenced by the commenter is one such requirement. The purpose of the 

Tribal Minor NSR program is to establish a preconstruction permitting program for new and modified 

minor sources and minor modifications at major sources located within Indian country to meet the 

requirements of Section 110(a)(2)(C) of the Clean Air Act. See 40 CFR 49.151(b)(1). Section 110(a)(2)(C) 

of the Act requires a program for the regulation of the modification and construction of any stationary 

source to assure that national ambient air quality standards are achieved. To implement this 

requirement, the Tribal Minor NSR program applies its requirements individually to each regulated NSR 

pollutant that would be emitted by the new or modified source. See 40 CFR 49.153(a)(1). For an 

existing major source, the Tribal Minor NSR program only applies if the net emissions increase for a 

particular pollutant equals or exceeds the Tribal Minor NSR thresholds. The SCR Project did not cause a 

significant net emissions increase for any pollutant other than SAM, which is subject to the PSD 

program and not the Tribal Minor NSR program. As such, EPA does not have the authority in this case 

to use the Tribal Minor NSR program to establish emission limits for SO2 or NO2.

1 EPA notes, however, 

that it has established stringent emissions limits for NOX and SO2 in our FIPs as discussed above. In 

addition, a stringent emissions limit for filterable particulate matter will apply to FCPP as a result of the 

MATS rule.

Comment 10:

(Commenters: BHP Billiton, NTEC) 

EPA's analysis properly determined that the Project would not result in adverse impacts to air quality. 

EPA evaluated the potential air quality impacts (Air Quality Related Values or AQRVs) to Class I parks 

 

1 We note that the permit for this action contains requirements under the Tribal Minor NSR program for equipment 

associated with the installation of SCR (increases in truck traffic and addition of storage silos). This equipment only results in 

emission increases of PM, PM10 and PM2.5. This equipment did not trigger review under the Tribal Minor NSR program, but 

since the equipment results in an increase in allowable emissions, the equipment must be included in an NSR permit. See 

40 CFR 49.153(a)(2). 
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Response to Comments 

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and wilderness areas following Federal Land Manager (FLM) guidance. EPA determined that the Project 

would result in an overall decrease of project-related air pollutants (SO2, NOx, PM10 and SAM) and 

therefore would not adversely impact Class I areas near the FCPP. This conclusion is consistent with the 

National Park Service's (the FLM for the Project) conclusion that no further analysis is needed and with 

the overall intent of the BART FIP which is to improve visibility and AQRVs in Class I areas. 

The proposed Project was also evaluated to determine compliance with the National Ambient Air 

Quality Standards (NAAQS) and Minor NSR Program in Indian Country requirements. EPA determined 

that the resulting air quality and reduction in the quantity of emissions would not cause or contribute 

to violations of NAAQS. Because SAM is the only pollutant with a net emissions increase above air 

pollutant thresholds established in the Minor NSR Program in Indian Country and is covered under the 

PSD permit action, the proposed project would be in compliance with the Minor NSR program 

requirements. 

BHP and NTEC 

Response 10:

This comment generally support EPA’s proposed action, and does not suggest that EPA should deny or 

revise the proposed permit. 

H2SO4 Air Impacts for Workers and Community

Comment 11:

(Commenter: Virgil Frazier) 

I'm curious about the extent of the ambient air quality. We're talking about H2SO4. I'm curious about 

the maximum impact levels for workers or community members, and I didn't see that on the map, or 

criteria in the literature that I have. As a community member, I've got to worry from the public side 

about my fellow workers, the environment. I know that the levels are very low, some insignificant. I'm 

curious. What are the human receptors with regards to that? How far away is the maximum 

concentration? Yes, we've got Class I areas, but isn't the emphasis of EPA human welfare, the humans 

here, the people here? And secondarily, we look at the environment, Class I areas. 

Response 11:

EPA understands the commenter’s concern regarding SAM in the air for workers and community 

members. 

First, the EPA’s regulations for attaining and maintaining the NAAQS under the PSD and Tribal Minor 

NSR programs, the subject of this permitting action, only pertain to “ambient air,” as the NAAQS are 

the standards set by EPA to protect ambient air. Ambient air is defined in the Clean Air Act as that 

portion of the atmosphere that is external to buildings and to which the general public has access. 40 

CFR 50.1(e). As such, onsite worker exposure to SAM is not regulated by the Clean Air Act because 

workers are not in ambient air. Workers are within the land owned or controlled by the source and to 

which the general public does not have access. It is our understanding that worker exposure is most 

clearly regulated by standards adopted by the Occupational Safety and Health Administration. We 
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Response to Comments 

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further understand that FCPP is within OSHA Region 6 and commenters may inquire there regarding 

worker exposure to SAM by contacting: 

Joann Figueroa 

El Paso Area Office, OSHA Region 6 

Phone: (915) 534-6251 

Secondly, regarding ambient air exposure to community members, as explained in our Fact Sheet there 

is not a NAAQS (ambient air standard) for SAM. As such, the EPA did not require a demonstration 

under 52.21(k) of our regulations because there would be no standard to compare ambient air impacts 

to under the PSD program. Fact Sheet at 34. Nevertheless, the EPA recognized that increased emissions 

of SAM might generally be of concern due to potential health impacts. At other facilities with wet FGD 

scrubbers like the FCPP, blue SAM plumes have been observed and referred to as plume blight after 

the installation of SCR. Physiological responses such as eye irritation and breathing difficulty have been 

reported for episodes involving visible plumes containing SAM aerosols at ground level. See 

Identification of (and Response to) Potential Effects of SCR and Wet Scrubbers on Submicron Particulate 

Emissions and Plume Characteristics, EPA-600/R-04-107, August 2004, at 2. Visible SAM plumes are 

expected to occur when SAM vapor or aerosol concentrations exceed 2 ppmv. The BACT emission 

limits in the proposed FCPP SCR Project permit were equivalent to concentrations well below 2 ppmv. 

Fact Sheet at 34. With the BACT emission limits in the final PSD permit, we do not expect any visible 

SAM emissions to occur. As a result, SAM plumes that reach ground level and cause adverse 

physiological effects are not expected to occur, regardless of the location of the maximum 

concentration. We would also like to clarify that 2 ppmv is the point at which SAM emissions are 

expected to become visible, and not the point at which SAM plumes would occur at ground level. The 

actual concentration at which a SAM plume would be heavy enough to reach ground level (instead of 

dispersing higher in the atmosphere) and potentially cause adverse health effects is expected to be 

much higher than 2 ppmv. For example, adverse physiological responses from a community near the 

Gavin Power Plant in Ohio were experienced in 2001 when SAM emissions increased from 

approximately 5 tons per day to 32 tons per day.2 With the final PSD permit conditions applying BACT, 

the FCPP will emit less than one ton per day of SAM during the demonstration period and even less 

than that upon the final BACT emission limit of 0.0025 lb/MMBtu. 

Soil and Vegetation Analysis

Comment 12:

(Commenter: BHP Billiton, NTEC) 

EPA conducted a thorough review of potential project impacts. Impacts to soil and vegetation from the 

projected increase in SAM emissions would be offset by the 19,000 tpy decrease in NOX emissions from 

the SCRs and no adverse impacts would result from the proposed Project. 

 

2

See Sulfuric Acid Mist: Regulation Uncertainties, Ecology Law Quarterly, accessed November 13, 2014. 

http://elq.typepad.com/currents/2012/12/sulfuric-acid-mist-regulating-uncertainties.html
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Response 12:

This comment generally supports EPA’s proposed action, and does not suggest that EPA should deny or 

revise the proposed permit. 

Visibility and Visible Emissions

Comment 13:

(Commenter: NNEPA) 

The SCR controls proposed for installation will cause an increase in SAM emissions, which will have the 

potential to adversely impact visibility in the area. However, the installation of SCR equipment will 

reduce approximately 80% of the NOx emissions from the remaining Units 4 and 5, which will improve 

visibility within the region. Consequently, while the installation of SCR controls may result in an 

increase of up to 237 tons per year in SAM emissions, the SCR controls could also result in a decrease 

of over 19,000 tons per year in NOx emissions. The overall significant reductions in NOx and other 

visibility-impairing pollutants from the installation of SCR controls will result in an overall net 

improvement in visibility. The NNEPA therefore supports the installation of SCR controls as 

contributing to a net improvement in visibility in the region. 

Response 13:

The EPA agrees with commenter that the installation of SCR at this facility will result in a net 

improvement in visibility in the region. 

Comment 14:

(Commenter: Scott Hicks) 

As a major source of air pollution causing both regional health effects and visibility impacts in several 

of our National Parks, visible emissions from Four Corners Generating Station must be monitored using 

the best available technology. Based on known sulfuric acid mist emissions causing downstream visible 

impacts on many of our nations treasures, the permit should require the use of US EPA Alternate 

Method 082 (ALT 082) for the monitoring and verification of secondary plume formations. US ALT 082 

provides pictorial reference that can also be made available to the public as well as the EPA. Several 

sections of the proposed permit outline the importance of accurate opacity measurements. 

Due to the fact that ALT 082 standard utilizes digital images and accompanying software to analyze the 

opacity of an emission, the electronic and photographic evidence of the inspection is intrinsically 

embedded within the evaluation itself. The impact of secondary plume formation must mandate the 

use of photographic evidence and inspections documenting the presence or lack thereof a secondary 

plume formation. 

Response 14:

The EPA disagrees with the commenter that monitoring and verification of secondary plume formation 

is warranted by this permit action. First, the proposed permit did not outline the need for accurate 

opacity measurements, as the proposed permit did not contain any opacity limits. See EPA’s response 
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Response to Comments 

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to Comment 44 explaining our basis for not setting an opacity standard in the final permit. As such, use 

of ALT 082 is unnecessary for the final permit. 

We note that it is unclear what the commenter means by “secondary plume formation.” To the extent 

the commenter is concerned about a visible plume or ground level plume occurring, we disagree that 

this concern requires an opacity standard with additional monitoring. As explained in response to 

Comment 11, the SAM BACT limit ensures emissions are below the point at which visible plumes form. 

While the FCPP has an existing opacity standard, monitoring of that standard is not appropriately 

addressed in this permitting action. 

Environmental Justice

Comment 15:

(Commenters: Victoria Gutierrez, Mike Eisenfeld, SJCA) 

Commenters express opinions related to environmental justice: 

EPA has a leadership responsibility to enforce Environmental Justice principles as outlined in Executive 

Order 12898. A cursory review of EPA's website on EJ found at 

http://www.epa.gov/environmentaljustice states that “Environmental Justice is the fair treatment and 

meaningful involvement of all people regardless of race, color, national origin, or income with respect 

to the development, implementation, and enforcement of environmental laws, regulations, and 

policies. EPA has this goal for all communities and persons across this Nation. It will be achieved when 

everyone enjoys the same degree of protection from environmental and health hazards and equal 

access to the decision-making process to have a healthy environment in which to live, learn, and 

work." If the EPA has evidence that groundwater is contaminated at FCPP and that the area has a 

severely compromised existing public health environment, it would be unconscionable for EPA to 

approve continued operation of the FCPP. We request that EPA deny issuing the PSD permit. 

Response 15:

EPA has a defined role in assessing the environmental effects of the FCPP SCR Project and existing 

groundwater issues are outside the scope of this Clean Air Act permit action and cannot be used as a 

basis to deny this permit. 

As acknowledged by the commenters, EPA is aware of contaminated groundwater issues at the FCPP 

and has discussed them in a letter dated June 26, 2014, in which EPA Region 9 provided comments to 

the Office of Surface Mining and the Bureau of Indian Affairs on the Draft EIS: 

“Pollutants from the disposal of CCR have contaminated groundwater at the FCPP. The DEIS 

includes a number of voluntary measures to be taken by Arizona Public Service (APS) regarding 

operations, design, groundwater monitoring, corrective action, and closure and post-closure of 

CCR disposal facilities at the FCPP. Because future regulations by EPA regarding CCR 

management may not apply on Tribal lands, we strongly recommend that the voluntary 

measures be incorporated as conditions of approval by the BIA in the event it approves APS’s 

proposed lease amendment and application for right-of-way renewals. Groundwater 
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contamination from past disposal of CCR in Navajo Mine has also occurred and we recommend 

monitoring of groundwater at the Navajo Mine to confirm the DEIS conclusions that 

constituents of concern would be attenuated as groundwater travels towards the San Juan River 

and the Chaco Rivers.” Letter from Kathleen Martin Goforth, Manager, Environmental Review 

Section, June 26, 2014. 

EPA’s comment letter also provided more detailed comments with specific recommendations for the 

final EIS related to groundwater contamination at FCPP. 

Environmental Justice Concerns 

Regarding environmental justice, EPA has fulfilled its responsibilities under Executive Order 12898 (EO 

12898 or EO) with respect to environmental justice and this permitting action for the FCPP SCR Project, 

as described in detail below. EPA prepared an Environmental Justice (EJ) Analysis in conjunction with 

its proposed PSD permit for the FCPP SCR Project, containing appropriate and adequate support for its 

conclusions. 

Background 

Executive Order 12898, “Federal Actions to Address Environmental Justice in Minority Populations and 

Low-Income Populations,” was signed on February 11, 1994. The EO establishes federal executive 

policy on environmental justice. Its main provision directs federal agencies, to the greatest extent 

practicable and permitted by law, to make environmental justice part of their mission by identifying 

and addressing, as appropriate, disproportionately high and adverse human health or environmental 

effects of their programs, policies and activities on minority populations and low-income populations. 

The EO is designed to focus the attention of federal agencies on the human health and environmental 

conditions in minority communities and low-income communities with the goal of achieving 

environmental justice. 

EPA has determined that the EO applies to our PSD permitting decisions. See, e.g., In re Shell Gulf of 

Mexico, Inc. & In Re Shell Offshore, Inc. (Frontier Discovery Drilling Unit) 15 E.A.D.___, OCS Appeal Nos. 

10-01 through 10-04, slip op. at 63-64 (EAB Dec. 30, 2010) (citing prior EPA Environmental Appeals 

Board (EAB) opinions). EPA defines environmental justice as the fair treatment and meaningful 

involvement of all people regardless of race, color, national origin, or income with respect to the 

development, implementation and enforcement of environmental laws, regulations and policies. EPA 

has this goal for all communities and persons. 

EPA defines meaningful involvement to mean that 1) potentially affected community residents have an 

appropriate opportunity to participate in decisions about a proposed activity that will affect their 

environment and/or health, 2) the public’s contribution can influence our decision, 3) the concerns of 

all participants involved will be considered in our decision-making process and 4) the decision makers 

seek out and facilitate the involvement of those potentially affected. 

EPA’s Public Participation and Outreach Activities for the Proposed PSD Permit for the FCPP SCR Project 
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With respect to public outreach and participation, EO 12898 affords EPA considerable discretion to 

determine appropriate outreach activities. In this case, EPA prepared the EJ Analysis and took 

numerous actions to facilitate input from the community regarding the FCPP SCR Project, addressing 

the objectives described above. EPA’s enhanced public participation process, described below, went 

beyond the specific regulatory requirements set forth in 40 CFR part 124 for PSD permit proceedings, 

and demonstrates a commitment on EPA’s part to ensuring meaningful participation by affected 

communities in the decision-making process. 

In July 2014, EPA provided notice of its proposed PSD permit for the Project, as well as notice of three 

public hearings and informational meetings scheduled for August 27-28, 2014. EPA distributed the 

notices using a number of methods designed to reach the community in the area, including publishing 

the notices in the Daily Times and Navajo Times on July 24, 2014 and on EPA Region 9’s website. EPA 

also distributed the public notices by email or mail to the necessary parties in accordance with 40 CFR 

Part 124, as described above in Section 1 of this document. The public notice provided the public with 

a clear explanation of how to obtain additional information about EPA’s action, including the fact that 

detailed materials relating to EPA’s action were being made available at several locations in the 

communities near the FCPP SCR Project site as well as on EPA Region 9’s website and at EPA’s office in 

San Francisco. The public notice also included the name, phone number, mailing address and email 

address of a contact person so that members of the public could contact EPA directly to ask questions 

or obtain additional information. 

EPA sent a copy of its public notice, the Proposed Permit, Fact Sheet, and EJ Analysis to several 

locations near the FCPP SCR Project site to facilitate review by members of nearby communities: San 

Juan College in Farmington, NM, Diné College Shiprock Branch in Shiprock, NM, and Shiprock Branch 

Library in Shiprock, NM. 

EPA also provided access to key documents in the administrative record for its Proposed Permit on the 

Region 9 website, including the Proposed Permit, Fact Sheet, EJ Analysis, permit application and other 

key supporting information. Although 40 CFR part 124 does not specifically require this approach, EPA 

determined that it would facilitate community involvement by making key information more 

immediately accessible to the public. 

In addition, in order to facilitate community understanding, EPA prepared a Public Information Sheet, 

which included an overview of the proposed PSD permit, Project emissions, and air quality impacts. 

This document was also made available on EPA’s online docket for review by the public during the 

public comment period. 

Region 9 held three public hearings in the vicinity of the FCPP. While Diné translation is not required by 

Part 124, EPA determined that it would be appropriate to provide Diné translation services at the 

hearing, in order to facilitate public involvement by Diné-speaking members of nearby communities. 

Further, prior to each public hearing EPA held an informational meeting to give the public the 

opportunity to informally discuss the FCPP SCR Project with EPA. 

EPA received numerous oral and written comments during the public comment period. 
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EPA had previously determined that there may be minority or low-income populations potentially 

affected by its proposed action on the FCPP SCR Project permit application, and determined that it 

would be appropriate to prepare a separate EJ Analysis for this particular action. EPA prepared the 

analysis and made it available as part of the administrative record for the Proposed Permit at the time 

EPA issued its Proposed Permit for comment. The EJ Analysis was posted on EPA’s online docket during 

the public comment period, and was briefly discussed in EPA’s Fact Sheet and Public Information Sheet 

for the Project. 

EPA believes that all of these efforts, many of which went beyond the required public notice and 

participation procedures in 40 CFR part 124, were consistent with its public participation 

responsibilities under EO 12898, and served to ensure that the public documents, public notice, and 

public hearing relating to its proposed PSD permitting action for the Project were concise, 

understandable, and readily accessible to the public. 

EPA’s EJ Analysis and Consideration of Environmental Justice Comments for the SCR Project 

With respect to EPA’s substantive consideration of environmental justice issues in the context of its 

PSD permitting action for the SCR Project, EPA prepared a succinct, well-reasoned EJ Analysis to 

accompany its proposed PSD permit, in which EPA discussed potential impacts of its action on 

environmental justice communities. EPA’s EJ Analysis described EPA’s proposed permitting action, 

included a brief description of the area near the Project and key demographic information regarding 

the surrounding communities, discussed the actions EPA was taking to provide enhanced public 

participation opportunities for its proposed permit, and considered the impacts of EPA’s permitting 

action on nearby communities. 

The EJ Analysis’ discussion of pertinent demographic information for the FCPP and surrounding areas 

considered populations within 5, 15, and 25 km of the proposed facility; the nearby communities of 

Shiprock, NM and Farmington, NM; San Juan County; and the State of New Mexico as a whole. EJ 

Analysis at 4-5. 

With respect to potential impacts on environmental justice communities from EPA’s proposed 

permitting action, the EJ Analysis identified the fact that the NAAQS are health-based standards, 

designed to protect public health with an adequate margin of safety, including sensitive populations 

such as children, the elderly, and asthmatics. The EJ analysis noted that as EPA’s EAB has observed, in 

the context of an environmental justice analysis, compliance with the NAAQS is emblematic of 

achieving a level of public health protection that demonstrates that minority or low-income 

populations will not experience disproportionately high and adverse human health or environmental 

effects due to exposure to relevant criteria pollutants. EJ Analysis at 1. 

EPA’s EJ Analysis went on to explain that the emissions from the FCPP SCR Project are below the 

significant emission rates for all of the NAAQS, and therefore the Project is not subject to PSD review 

for any NAAQS pollutant. In this case, EPA determined it was nevertheless appropriate to review 

potential impacts associated with the increases in SAM emissions from the FCPP, in order to fully 
FCPP SCR Project 

Response to Comments 

Page 24 of 109 

consider environmental justice issues for this permitting action. For our review, EPA considered the 

threshold at which visible SAM emissions are expected to occur, which could lead to plume blight and 

potential adverse health effects if the plume reached ground level. See response to Comment 11 

where we clarify that visible SAM emissions, above 2 ppmv, do not necessarily lead to ground level 

SAM and adverse health effects. The SAM BACT emission limits in the final PSD permit are simply 

below the threshold at which visible emissions are expected to occur (i.e. 2 ppmv), alleviating any 

concern that ground level SAM emissions could occur and potentially lead to adverse health effects. 

The concentration at which a visible SAM plume is heavy enough to reach ground level is expected to 

be much higher than 2 ppmv. Based on this review, we do not expect the emissions increase of SAM 

associated with the Project to result in adverse human health impacts to any population, and therefore 

will not result in disproportionately high and adverse human health or environmental effects on 

minority populations and low-income populations. EJ Analysis at 6. 

Finally, the EJ Analysis also discussed the fact that the FCPP SCR Project will result in a reduction of 

19,000 tpy of NOX emissions. NOX emissions are a precursor to ground level ozone, which can make it 

difficult to breathe; cause shortness of breath; inflame and damage airways; and aggravate asthma, 

emphysema, and chronic bronchitis. This substantial reduction in NOX emissions will have no adverse 

effects but instead will be beneficial to any nearby populations, including minority or low-income 

populations. 

In conclusion, EPA believes that its public participation process and substantive consideration of 

environmental justice issues with respect to its PSD permitting action for the FCPP SCR Project were 

appropriate and consistent with its responsibilities for implementing the provisions of EO 12898 as well 

as its obligations under 40 CFR Part 124. To the extent commenters' are suggesting that the EPA deny 

this permit due to environmental justice concerns, we disagree. Based on our careful consideration of 

the underlying statutes, regulations, and information provided by commenters, we have determined 

that the applicant has met the necessary requirements for obtaining a PSD permit. As such, we must 

grant a permit to APS for the FCPP SCR Project as conditioned in the final PSD permit. 

Comment 16:

(Commenter: BHP Billiton, NTEC) 

EPA appropriately prepared an Environmental Justice Analysis for the proposed action. Potential health 

impacts from the projected SAM emissions were evaluated using the higher emission rate (more 

conservative approach) of 0.00435 pounds per million British thermal units (lb/MMBtu). This rate is 

equivalent to 1.5 parts per million by volume (ppmv) SAM which is below 2 ppmv - the threshold 

concentration that could cause physiological responses from exposure to SAM aerosols at ground level. 

Comparing to the demonstration concentration of 0.86 ppmv (equivalent to a SAM emission rate of 

0.0025 lb/MMBtu), the potential exposure would be even less. Based on this analysis, EPA correctly 

determined that the Project-related SAM emissions would not result in adverse health impacts to any 

population and would not pose disproportionately high and adverse human health or environmental 

effects on minority or low-income populations near the FCPP or the community as a whole. 
FCPP SCR Project 

Response to Comments 

Page 25 of 109 

Response 16: 

This comment generally supports EPA’s consideration of environmental justice concerns, and does not 

suggest that EPA should deny or revise the proposed permit. 

Comment 17:

(Commenter: NNEPA) 

In considering environmental justice impacts, EPA must consider, and heed, the wishes of the 

environmental justice community of concern – the Navajo Nation – which through its democratic 

institutions and processes has fully supported the selection of Option 2 under BART, as documented in 

the Nation's comments and in government-to-government consultation with EPA. In addition to the 

extensive opportunity for public comment for determining BART under the FIP, including Option 2, EPA 

provided notice of and requested public comment on their proposed APS PSD permit action on July 24, 

2014 and held three public hearings, two of which were on the Navajo Nation. English-Dine' translation 

services were provided at the hearings. EPA provided copies of their BACT and environmental, health 

and environmental justice impact analyses and general information on PSD permitting requirements at 

the public hearings and posted this information online. 

Response 17:

The EPA considered the comments provided by the Navajo Nation. This comment is generally 

supportive of EPA’s approach to environmental justice concerns for our proposed permit decision, and 

does not suggest that EPA should deny or revise the proposed permit. 

National Pollutant Discharge Elimination System

Comment 18:

(Commenters: Mike Eisenfeld, SJCA) 

EPA is the lead agency on the Clean Water Act National Pollutant Discharge Elimination System 

(NPDES) permitting the FCPP. There is no up to date NPDES permit at FCPP issued by EPA. EPA must 

promptly issue a new permit imposing new regulatory requirements. This permit must reflect current 

conditions at the FCPP, where EPA has confirmed groundwater contamination and the FCPP/Navajo 

Mine Draft Environmental Impact Assessment Preferred Alternative is to increase CCR disposal/storage 

on the FCCP lease site, potentially exacerbating contamination issues with SAM (as part of that PSD 

permitting of SCR). EPA’s new NPDES permit should eliminate ground and surface water contamination 

at the site resulting from CCR disposal/storage on the FCPP lease site, instead of potentially 

exacerbating contamination issues with approval of a PSD permit. 

Response 18:

APS submitted a renewal application for the FCPP NPDES permit in October 2005, and EPA recently 

issued a draft NPDES permit for public comment. The public comment period ends January 12, 2015. 

The NPDES permit conditions and the specific groundwater issues raised by the commenter are not 

related to this particular CAA permit action and should be addressed in comments on the NPDES 

permit. Additional information is available through Region 9’s website here: 

http://www.epa.gov/region9/water/npdes/pubnotices.html. 
FCPP SCR Project 

Response to Comments 

Page 26 of 109 

It is unclear why the commenter believes emissions of SAM, or approval of this permit for the FCPP SCR 

Project, would exacerbate groundwater contamination issues related to CCR disposal. Nevertheless, 

consideration of groundwater issues is outside the scope of this immediate permitting action. 

Cultural Resources

Comment 19: 

(Commenters: Mike Eisenfeld, SJCA) 

We received comments as excerpted below: 

Commenters are concerned about the impact of sulfuric acid on the cultural resources in the area. 

Sulfuric acid is a component of acid rain. According to EPA's own website, "acid rain accelerates the 

decay of building materials and paints, including irreplaceable buildings, statues, and sculptures that 

are part of our nation's cultural heritage." See, http://www.epa.gov/acidrain/effects/. The Navajo 

Nation and surrounding area is well known for its numerous cultural buildings, carvings, petroglyphs, 

traditional cultural properties (TCPs), and other cultural sites and features. EPA must more precisely 

assess whether the increase in SAM emissions from the proposed project will cause harm to cultural 

sites and TCP's on and off the Navajo Nation. EPA must fulfill National Historic Preservation Act Section 

106 consultations for the PSD permit project. 

Response 19:

The EPA agrees with the commenter that the Section 106 consultation requirements of the National 

Historic Preservation Act apply to this permitting action, including the implementing regulations at 36 

CFR part 800. To meet these requirements, the EPA initiated consultation with the Navajo Nation Tribal 

Historic Preservation Officer in a letter dated July 23, 2014, invited surrounding tribes and states to join 

the consultation process, determined the area of potential effects, identified historic properties in the 

area, developed a cultural resources report, and made the cultural resources report available for public 

comment. The EPA is issuing this final PSD permit for the FCPP SCR Project because the section 106 

process is complete, which included a finding of no adverse effect. We have included in our 

administrative record for this final PSD permit all of the documents completing the Section 106 

consultation. 

The comment contends EPA should have conducted a more precise assessment of whether the 

increase in SAM emissions from the proposed project will cause harm to cultural resources. We 

disagree that a more precise assessment is warranted. Section 5 of the cultural resources report 

addresses the potential affects from acid rain, identified by the commenter, which could occur because 

of increased SAM, through acid deposition on cultural resources: 

“Acid deposition (also known as acid rain) has the potential to adversely affect historic 

properties...Acid deposition associated with the FCPP can occur as a result of emissions of SAM, 

sulfur dioxide, nitrogen dioxide, sulfur, nitrogen, hydrochloric acid, and hydrofluoric 

acid...However, similar to the impacts on visibility, the FCPP SCR Project is expected to result in 

overall decreases in acid deposition forming pollutants (decrease of 19,000 tpy of NOx and an 

increase in 237 tpy of SAM). As such, no adverse effects of acid deposition are expected to occur 
FCPP SCR Project 

Response to Comments 

Page 27 of 109 

as a result of the FCPP SCR Project.” (pp 3-4, Cultural Resources Report) 

To the extent the commenter believes a more precise identification of historic properties is warranted, 

the EPA also disagrees. The identification of historic properties is discussed in Section 4: 

“No archaeological sites were recorded in the vicinity of the proposed construction area for the 

SCRs and associated infrastructure prior to FCPP construction during the 1961 survey, and no 

sites were documented in this area during the 2013 survey. There are numerous other properties 

with 50 km (or potentially within 50 km) of the FCPP that are already listed on the National 

Register of Historic Places. See Table 1. Further there is the potential for other properties that 

are eligible for inclusion in the National Register to be located within 50 km of the FCPP. 

However, as discussed below the potential effects on these properties, other than to the FCPP, 

relates only to impacts of SAM and NOx emissions on visibility and acid deposition. EPA’s 

evaluation applies to any area or property within 50 km of the FCPP and all properties of 

cultural significance that may exist are expected to incur [the] same effects. As such, a detailed 

review of other potentially affected historic properties was not conducted.” (pp. 2-3, Cultural 

Resources Report) 

In addition, 36 CFR 800.4(b)(1) of the NHPA regulations describes the level of effort required for 

identifying historic properties: 

The agency official shall take into account past planning, research and studies, the magnitude 

and nature of the undertaking, the nature and extent of the potential effects on historic 

properties, and the likely nature and location of historic properties within the area of potential 

effects. 

The EPA has met this requirement by identifying the historic properties, or potentially historic 

properties, within the construction area of the SCR project; and, by identifying the historic properties 

listed on the National Register of Historic Places within 50 km of the FCPP. Identification of other 

properties potentially eligible for inclusion in the National Register, beyond those within the FCPP SCR 

Project footprint, is not warranted given the nature and extent of the potential effects to these 

properties. The only potential effects to these properties would be related to visibility and acid 

deposition, and the extent of these effects (as discussed above) can be evaluated without identification 

of individual properties. Therefore, EPA’s assessment is sufficient and complies with the requirements 

of section 106 of the NHPA. 

Comment 20:

(Commenter: BHP Billiton) 

Another commenter indicates that the EPA appropriately considered the proposed FCPP operations, 

project construction activities and projected air emissions (including a 50 km radius around FCPP) in its 

cultural resources impact analysis, as excerpted below. 

EPA correctly determined that the proposed action would not adversely affect cultural resources as: 
FCPP SCR Project 

Response to Comments 

Page 28 of 109 

• No archeological sites are present in the vicinity of the proposed construction area; 

• Construction activities will be limited to existing industrial areas; and 

• Installation of the SCR system will result in a significant reduction of acid deposition forming 

pollutants, NOx emissions and net improvement in visibility at 16 nearby national parks and 

wilderness areas. 

Response 20:

The EPA agrees that our cultural resources report complies with the statutory and regulatory 

requirements of the NHPA. 

Endangered Species Act

Comment 21:

(Commenters: Mike Eisenfeld, SJCA) 

Some commenters were critical of the ESA analysis process, as follows: 

The U.S. Fish and Wildlife Services has yet to a complete a Biological Opinion (BO) for the FCPP/Navajo 

Mine Draft EIS. Section 7 consultations are theoretically ongoing with a stated goal of having the EIS 

complete in 2015, but the status of the BO and jeopardy determinations by U.S. Fish and Wildlife 

Service is unknown. Due to EPA's stated groundwater contamination problem at FCPP, known surface 

water impacts to the San Juan River (Colorado pikeminnow and Razorback sucker adverse impacts), 

EPA-stated severely compromised existing public health environment, and the fact the FCPP/Navajo 

Mine would still emit over 9 million tons per year of carbon dioxide in a vulnerable region of the 

country (as described in the National Climate Assessment) -- it is incumbent that EPA fully consult with 

U.S. Fish and Wildlife on the proposed PSD permit and not to rely on an incomplete and inadequate 

analysis of impacts to listed species. 

The AECOM Biological Assessment (BA) prepared for APS for the FCPP SCR Retrofit Project is grossly 

deficient, and its methods and assumptions do not provide a reasonable basis for its conclusion that 

retrofit and continued operation of FCPP are not likely to adversely affect listed species including the 

southwestern willow flycatcher, yellowbilled cuckoo, Colorado pikeminnow, razorback sucker, Mancos 

milk-vetch, and Mesa Verde cactus. It was prepared in May of 2014, prior to the public release of the 

draft EIS for the FCPP/Navajo Mine, and omits discussion of numerous significant impacts associated 

with coal combustion emissions and waste disposal. 

First, as discussed in other comments, EPA’s analysis of emissions from the FCPP retrofit project, 

including SO2, are severely understated. EPA should reassess foreseeable emissions of SO2, sulfur 

dioxide mist, and particulates on listed species and critical habitat using the corrected emissions figures 

provided in other comments. In addition, the BA appears to have improperly ignored the impact of 

increased particulate emissions on listed plants. The BA asserts that “As demonstrated in the air 

modeling performed in support of the EIS (AECOM 2013b), the NAAQS for PM10 and PM2.5 would not 

be exceeded during future operations of Units 4 and 5 as a result of the addition of SCR systems. 

Because the NAAQS are developed to be protective of the environment, it can be concluded that the 

PM emissions will not adversely affect the environment or the populations and habitat of listed 
FCPP SCR Project 

Response to Comments 

Page 29 of 109 

species.” BA at 21-22. Ecological risks to plants and the rhizosphere, however, are site specific and 

constituent-specific, and a generalized assertion that NAAQS will not be violated cannot substitute for 

an informed analysis of the constituent-specific effects of FCPP particulate emissions on Mancos milkvetch, Mesa Verde cactus, and the soils that support them. 

Depositional modeling of SAM in the BA goes to great length to minimize impacts to Mesa Verde 

cactus and Mancos milk-vetch. In particular, its treatment of the expected effects of sulfur dioxide 

deposition and sulfuric acid mist on listed plant species fails to support a conclusion that all effects will 

be beneficial or insignificant. The BA asserts that “maximum annual average SO2 concentration in the 

Deposition Area attributed to FCPP emissions was calculated to be 29.9 sulfur equivalents/ha/yr, well 

below the threshold in the WHO (2000) report.” The BA does not appear to contain any disclosure, 

however, of total SO2 concentration in the area. Without knowledge of overall sulfur dioxide levels, it is 

impossible to determine whether sulfur emissions pose a risk to the listed plants, and whether or not 

the contribution of FCPP to that risk is significant. Similarly, with regard to acid effects on soils, the BA 

appears to rely on a generalized qualitative conclusion that acid deposition from FCPP would not 

reduce soil pH below 6.5 (a level recommended by the Natural Resource Conservation Service for 

ranching and agricultural purposes), without any specific analysis of the vulnerability of the Mancos 

milk-vetch, Mesa Verde cactus, and their specific supporting soils to acid deposition. 

In addition, the BA discounts impact to Colorado pikeminnow and Razorback sucker. It contains no 

discussion of the impacts of mercury or selenium, pollutants already determined to jeopardize the 

continued existence of those two listed fish species, and pollutants which will continue to be emitted 

following the proposed retrofit. How will increased acid deposition from the retrofit affect the 

biological availability of mercury and selenium? In addition, the BA’s conclusion that FCPP acid 

deposition cannot affect the pH of the San Juan River, where designated critical habitat for the 

Colorado pikeminnow occurs, is based on an untenable assumption – the average annual flow rate of 

more than 1,700 cubic feet per second (cfs). Relying solely on average flows for a river with highly 

variable flow rates, such as the San Juan, badly understates the effects of deposition during periods of 

lower flow. The use of average flows in a system with large seasonal variability ignores the welldocumented fact that for much of the year, flows at Farmington are in the neighborhood of 500-600 

cfs. ESA consultation should address the effects of acid deposition on surface waters at low flow as well 

as average flow levels, and should analyze how such deposition could affect aquatic biology and critical 

habitat during low-flow seasons. 

We disagree with AECOM's BA determinations on Threatened and Endangered Species (TES) as 

scientifically unsupportable, ignoring the cumulative, direct, indirect and depositional impacts to TES, 

waterways, land, and air in the region. We implore EPA to fully evaluate ESA issues with the proposed 

PSD in the context of the significant adverse cumulative impacts well known at the FCPP/Navajo Mine 

complex. We would appreciate being appraised of Section 7 consultations with U.S. Fish and Wildlife 

Service on the AECOM Biological Assessment prepared for APS for the FCPP SCR Retrofit Project and 

EPA's role in comprehensive and cumulative analysis as a Cooperating Agency for the FCPP/Navajo 

Mine DEIS. 
FCPP SCR Project 

Response to Comments 

Page 30 of 109 

Response 21:

As stated in response to Comment 3, EPA actions under the Clean Air Act are not subject to the NEPA 

process. The NEPA process referred to by the commenter is for actions including: a land lease renewal 

to extend operation of FCPP, renewal of rights-of-way for transmission lines, renewal of the Navajo 

Mine Permit, and issuance of a new mine permit within the existing Navajo Lease area. The lack of a 

Biological Opinion for this ongoing NEPA process for actions at FCPP not regulated under the Clean Air 

Act does not affect our authority to issue a PSD permit for the FCPP SCR Project, provided we complete 

any ESA obligation specifically evaluating the FCPP SCR Project. The Section 7 ESA consultation for this 

action relates only to the FCPP SCR Project. In an email dated May 19, 2014 EPA requested 

consultation with the U.S. Fish and Wildlife Service (the Service). EPA provided a Biological Assessment 

(BA) to the Service, and specifically requested concurrence on EPA’s determination that installation of 

SCR at FCPP is not likely to adversely affect listed species. On June 20, 2014, and after receipt of 

additional information, the Service concurred with EPA’s determination that the FCPP SCR Project is 

not likely to adversely affect any listed species. As detailed in the Service’s letter: “The Federal Action 

under consideration for this consultation is a Federal Prevention of Significant Deterioration (PSD) 

permit for SAM under the Clean Air Act.” In addition, the Service’s letter states: 

“Note that our concurrence is based on the “worst case” emission limit for SAM in the final PSD 

permit that is either equal to, or more stringent than, the “worst case” emission limit 

considered in the BA, then EPA does not need to consult with the Service again on the selected 

emission limit (BACT) for SAM determined in the final PSD permit.” 

Documents and correspondence related to EPA’s completed ESA consultation, including the BA we 

submitted to the Service, are available in the administrative record for this action and were made 

electronically available during the public comment period for this action. EPA’s final emission limit for 

SAM will be at least as stringent as the “worst case” SAM emission limit evaluated in the BA. As such, 

and in accordance with Section 7 of the ESA, EPA has met its obligations to consult with the Service on 

this action, and no further action is required by EPA. The commenter also contends that the BA must 

be revised to account for the need to revise the emissions analysis used for this action based on other 

comments submitted. EPA has fully considered those comments and continues to determine that the 

FCPP SCR Project is only subject to review under the PSD program for SAM emissions and no pollutant 

triggered reviewed under the Tribal Minor NSR program. As such, no revision is necessary. The only 

pollutant under review for this action is SAM. In addition, the BA considered pollutants other than SAM 

emissions. Specifically, for the consideration of acid deposition, the BA considered all acid-forming 

compounds emitted from FCPP – such as, SAM, SO2, NOX, HCl, and HF. See Table 2-2 of the BA. After 

consideration of all of the pollutants reviewed in the BA the Service concurred with EPA’s “not likely to 

adversely affect” determination. 

Finally, the comments only contend that EPA has not performed a consultation. The comments do not 

provide any information indicating that the consultation we undertook, as described above, was 

insufficient or based on erroneous facts. Our consultation and the Service’s concurrence in our 

determination that the FCPP SCR Project is not likely to adversely affect any listed species is 

appropriate and legally sufficient. 
FCPP SCR Project 

Response to Comments 

Page 31 of 109 

Comment 22:

(Commenter: BHP Billiton) 

A commenter asserts that, in consultation with the US Fish and Wildlife Service, in accordance with 

Section 7 of the Endangered Species Act (ESA), EPA properly concluded that federally listed species 

would not be adversely affected by the projected increase in SAM emissions. 

Response 22:

The EPA agrees with this comment. 

Timing of Final Permit Issuance

Comment 23: 

(Commenters: BHP Billiton, NTEC) 

As the PSD program is a preconstruction review and permitting program, the FCPP PSD permit would 

need to be issued before APS can procure, install, and test the proposed SCR and SAM BACT systems. 

Given the necessary pre-construction lead times for a project of this magnitude, the PSD permit would 

need to be issued well ahead of the July 31, 2018 BART compliance deadline for installation of the FCCP 

SCRs. APS estimates that SCR construction and operation would require approximately three years, 

which EPA recognizes as reasonable based on experience with other facilities. Considering the threeyear construction timeline and BART compliance deadline, the commenter urges EPA to issue the PSD 

permit before July 31, 2015. 

Response 23:

The EPA expects to issue the permit within the time frame described in the comment. 

BACT Analysis – Limit – Level of Control

Comment 24:

(Commenters: Victoria Gutierrez, Mike Eisenfeld, SJCA) 

Some commenters took issue with the SAM emission limit proposed as BACT: 

The permit should mandate the use of an SCR catalyst that is designed for no higher than 0.5 percent 

SO2 to SO3 conversion across the catalyst. This is a readily available catalyst that EPA should mandate 

as part of the best available control technology determination for the sulfuric acid mist, and also to 

minimize the visible plume and contributions to haze. 

EPA must not allow for a higher SAM rate to apply for 2.5 years (allowing for a SAM-control 

optimization period). EPA must impose a BACT limit for SAM that reflects BACT. With a lower SO3

conversion catalyst for the SCR and dry sorbent injection, along with the lower sulfur coal and existing 

wet scrubber and baghouse, FCCP Units 4 and 5 should be able to meet the vendor guarantee rate of 

0.0015 pounds/MMBTU. EPA instead has allowed a SAM emission limit that is almost three times 

higher than the vendor guarantee to apply for 2.5 years, during a SAM control optimization period. 

There is no justification for an optimization period. EPA is unlawfully delaying compliance with its 

proposed BACT determination. Because the amount of sorbent injected in the dry sorbent injection 

system is based on the SAM limit that the unit is required to meet, EPA's allowance of a significantly 
FCPP SCR Project 

Response to Comments 

Page 32 of 109 

higher SAM rate for 2.5 years simply allows APS to not operate the DSI system to the best of its 

abilities. Further, such an approach is inconsistent with the purpose of the Regional Haze Program, as 

the increase in SAM emissions will harm visibility. 

EPA’s BACT analysis is deficient. APS proposed a SAM BACT limit of 0.00435 lb/MMBtu as a 

demonstration limit, but EPA has proposed to find that FCPP Units 4 and 5 could achieve a lower BACT 

limit of 0.0025 lb/MMBtu. There is no regulatory basis for a demonstration limit in the PSD regulations. 

Instead, the definition of BACT is an emissions limitation based on the maximum degree of reduction 

that is achievable taking into account energy, environmental and economic impacts. 40 C.F.R. 

§52.21(b)(12). For the reasons stated in the report prepared by Victoria Stamper “Review and 

Evaluation of the U.S. EPA’s Proposed Clean Air Act Prevention of Significant Deterioration Permit and 

Minor New Source Review Permit in Indian Country for the Four Corners Power Plant” (Stamper 

Report), SAM emission rates lower than 0.0025 lb/MMBtu are achievable. Further, since the purpose 

of this project is to reduce regional haze, EPA should impose a visible emission limit reflective of BACT 

as part of its SAM determination. 

Response 24:

The EPA disagrees with the commenters that a lower limit of 0.0015 lb/MMBtu is BACT for SAM 

emissions or that an optimization period is not justified. The EPA’s Fact Sheet provides a detailed 

analysis for the proposed BACT limits and optimization period. The comment does not address or 

provide contrary information regarding the specific reasons that EPA identified when determining the 

proposed BACT limit and that it was necessary and appropriate to allow for an optimization period. 

SO2 to SO3 Conversion Rate for BACT 

The comment asserts that EPA should consider a lower conversion catalyst. However, EPA fully 

considered whether a lower SO2 to SO3 conversion catalyst should be required for BACT, and the 

commenter has not addressed the analysis presented by EPA in the Fact Sheet. To summarize, in Step 1 

(identify all control options) of the top down BACT analysis, the EPA identified the catalyst conversion 

rate as an available inherently lower emitting technology for SAM emissions. Fact Sheet at 21. In Step 2 

(eliminate technically infeasible control options) of the BACT analysis, EPA determined that a lower SO2

to SO3 conversation rate (i.e. lower than the 1% used by APS) is technically feasible and carried it on to 

Step 3 of the analysis. Fact Sheet at 23-24. For Step 3 (rank remaining control technologies) of the 

BACT analysis, the EPA ranked the use of 0.5% SO2 to SO3 conversion catalyst, in conjunction with other 

add-on control technologies, as the top ranked control option for BACT. See Fact Sheet at Table 9. In 

Step 4 (economic, energy and environmental impacts) of the BACT analysis, the EPA first eliminated 

the top control option – use of a wet electrostatic precipitator and 0.5% conversion catalyst – because 

the use of a wet ESP is not cost effective. This analysis also eliminated the control option ranked third – 

wet ESP with a 1% conversion catalyst. See Fact Sheet at 28-30 and footnote 41. As a result, the two 

remaining top control technologies were the use of add-on controls (DSI/SDA and dry ESP/baghouse) in 

conjunction with either 0.5% or 1.0% conversion catalyst. So, EPA looked at the economic, energy and 

environmental impacts of using a 0.5% conversion catalyst and eliminated it based on economic and 

environmental impacts. Fact Sheet at 30-31. The commenter has not provided any information that 

demonstrates that EPA’s analysis was incorrect. We fully considered a lower conversion catalyst in our 
FCPP SCR Project 

Response to Comments 

Page 33 of 109 

BACT analysis and eliminated it for the reasons stated in that analysis, and we continue to conclude 

that an emission limit based on a 1% conversion catalyst is BACT for the FCPP SCR Project. 

Impacts on Visibility and Haze 

The EPA disagrees with the commenters that the use of 0.5% conversion catalyst is needed to minimize 

visible emissions and contributions to haze. First, as identified in the Fact Sheet, the proposed BACT 

limit of 0.0025 lb/MMBtu, and the proposed limit during the demonstration period of 0.00435 

lb/MMBtu3, are not expected to result in adverse plume effects (or visible emissions). The proposed 

BACT limit of 0.0025 lb/MMBtu and demonstration limit of 0.00435 lb/MMBtu4 are equivalent to 

emission rates of 0.8 and 1.5 ppmv, respectively. Adverse plume problems (or visible emissions) are 

only expected to occur when SAM concentrations begin to exceed 2 ppm. Fact Sheet at 34, Section 7. 

Regarding haze, or visibility, Section 8 of the Fact Sheet explains that for visibility purposes, EPA 

determined that the significant reductions in NOX emissions, 19,000 tons per year associated with the 

SCR Project, would offset the 237 tpy increase in SAM emissions, since NOX and SAM both contribute 

to visibility impairment. A lower BACT limit is not needed to prevent adverse visibility impacts from this 

project. While a lower BACT limit would further reduce the SAM emission increases and haze 

formation, the EPA has no regulatory basis for requiring a lower BACT limit to achieve improved 

visibility, particularly for a project that will have a net benefit to visibility with the final BACT limits. 

Regarding the demonstration limit, see our response to Comment 42. 

Comment 25:

(Commenters: BHP Billiton, NTEC) 

EPA conducted a thorough analysis of the proposed SAM BACT. EPA determined that the DSI system, in 

combination with the existing FCPP wet flue gas desulfurization (FGD) and baghouse, is expected to be 

"particularly beneficial" in reducing emissions by allowing SO3 in the flue gas to react with hydrated 

lime to enhance capture of and form removable particulates in the bag house. EPA correctly selected 

this option as the BACT for SAM emissions. APS proposed a SAM emission rate of 0.00435 pounds per 

million British thermal units (lb/MMBtu). However, EPA is proposing a 2-year demonstration period to 

evaluate whether the lower SAM emission rate of 0.0025 lb/MMBtu is consistently achievable. If so, 

EPA would revise the SAM emission limit to the more stringent rate. As a conservative measure, EPA 

used the higher emission limit to evaluate impacts. 

Response 25:

The EPA acknowledges this comment regarding the SAM BACT limit. To clarify, the 0.0025 lb/MMBtu 

SAM emissions limit automatically begins to apply after the demonstration period, unless APS is able to 

satisfactorily demonstrate that the limit is not achievable. A permit revision is only required if the 

0.0025 lb/MMBtu limit is not achievable. 

PSD Applicability for Modifications

Comment 26:

 

3

See also response to Comment 42 where we revised the proposed limit to 0.0040 lb/MMBtu. 

4

Id. 
FCPP SCR Project 

Response to Comments 

Page 34 of 109 

(Commenters: SJCA, Stamper Report) 

The environmental non-governmental organizations’ comment letter and “expert report” are 

excerpted below. 

EPA and APS did not properly evaluate whether the project at FCPP would result in a significant 

emissions increase. 

In evaluating whether a project should be subject to PSD permitting, there is a two -step process 

spelled out in the federal PSD regulations. Specifically, one must determine whether the emission 

increases from a project would result in a significant emission increase for any pollutant. If the 

emission increases from the project do not result in a significant emission increase for a pollutant, then 

the project is not considered subject to PSD for that pollutant and no further applicability analysis is 

needed. However, if the emission increases from the project are projected to result in a significant 

emissions increase, then an evaluation of whether the project will result in a significant net emissions 

increase must be made, considering all contemporaneous emission increases and decreases. If the 

project will result in both a significant emissions increase and a significant net emissions increase for a 

particular pollutant, then it is subject to PSD permitting requirements for that pollutant. 40 C.F.R. 

§52.21(a)(2)(iv)(a). The regulations differ in how emission increases are projected under the two 

different steps, which will be explained below. 

The first step in determining PSD applicability is to determine whether the project will result in a 

significant net emissions increase for any regulated NSR pollutant. For projects that only involve 

existing emissions units such as the proposed project at FCPP, the test is based on the differences 

between the projected actual emissions and the baseline actual emissions. 40 C.F.R. §52.21(a)(2)(iv)(c). 

As is clear in the rules and explained by EPA in guidance statements, only emission increases are 

considered in the determination of projected future actual emissions, and emission decreases can be 

considered in the Step 2 applicability determination of whether the project will result in a significant 

net emissions increase. 

The commenter notes the definition of the term “projected actual emissions” per 40 CFR 

52.21(b)(41), as well as EPA guidance regarding the calculations of projected actual emissions: 

In its rulemaking preamble for its adoption of the projected actual emissions definition, EPA offered 

guidance as to how the projection of the maximum annual rate of emissions following the project is to 

be done: 

You will calculate the unit’s projected actual emissions as the product of: (1) The hourly 

emissions rate, which is based on the emissions unit’s operational capabilities following 

the change(s), taking into account legally enforceable restrictions that could affect the 

hourly emissions rate following the change(s); and 

(2) the projected level of utilization, which is based on both the emissions unit’s 

historical annual utilization rate and available information regarding the emissions unit’s 

likely post-change capacity utilization. 67 FR 80196 (December 31, 2002). 
FCPP SCR Project 

Response to Comments 

Page 35 of 109 

This has been EPA’s longstanding policy since it first adopted the actual-to-projected actual 

applicability approach in the “WEPCO Rule.” EPA and APS did not follow this rule in projecting actual 

emissions of the Four Corners Power Plant following the proposed project. Commenters’ specific 

arguments are presented in the following comments. 

Response 26:

The next series of comments were submitted by two environmental non-governmental organizations. 

The comment letter included a document referred to as “the expert report of Victoria Stamper.” See 

Law Offices of John Barth Comment Letter at p. 1. The procedures governing public participation for 

issuing PSD permits in 40 CFR Part 124 do not include provisions for public comments to qualify as 

“expert” or to be given extra weight in the public comment process. Therefore, despite being selfdescribed as being an “expert report,” we are not giving these comments any greater weight than 

other comments received on the proposed PSD permit for the FCPP SCR Project. The comments in the 

comment letter and the “expert report” are substantially the same although the “expert report” 

contains additional details. We are, therefore, responding to both the comment letter and the “expert 

report” simultaneously in the following Responses, specifically 26-48. Numerous exhibits were 

attached to the “expert report.” To the extent information in the attachments is not explained or 

discussed in the text of the comment letter or the “expert report,” it is not EPA’s obligation to provide 

a response. See In Re Pio Pico Energy Center, PSD Permit Appeals 12-04 through 12-06 (EAB Aug. 2, 

2013) at p. 38 – 42. 

In this excerpt and numerous comments below, the commenter has made several assertions regarding 

multiple elements of the emissions analysis for the FCPP SCR Project. These assertions are discussed in 

greater detail in the following comments and responses. (See Comments 27-38). Broadly speaking, 

these assertions appear intended to demonstrate the following points: 1) the baseline actual emissions 

EPA used in evaluating the proposed PSD permit should have been lower, 2) the projected actual 

emissions EPA used in evaluating the proposed PSD permit should have been higher, and 3) EPA’s 

evaluation of the significant net emissions increase should not have allowed the FCPP SCR Project to 

subtract any emissions decreases. If these assertions were accurate, the commenters contend that 

additional NSR regulated pollutants would be subject to PSD review. 

 

As discussed in our Fact Sheet, we determined in step 1 that the projected actual emissions increases 

for SAM, PM2.5 and PM10 exceeded the PSD significant emission rates (SERs). In the step 2 analysis, we 

determined that the net emissions increases from the FCPP SCR Project exceeded the SERs only for 

SAM and as a result only triggered PSD review for SAM. 

In an effort to show that additional pollutants should be subject to PSD review, the commenter’s first 

two general assertions argue that the FCPP SCR Project would have larger project-only (step 1) 

emission increases, resulting in emission rates exceeding PSD SERs for multiple additional pollutants, 

including potentially NOX, SO2, CO, and GHGs. Stamper Comment Letter Table 7, p. 22. Combined with 

the third general assertion that there are no creditable emission decreases, the net (step 2) emission 

increase for these pollutants would therefore also remain above PSD SERs, triggering PSD review for 

additional pollutants. Id. Table 7 & p. 28. As addressed in detail in the following responses (Responses 

27-38), we disagree that PSD review is triggered for any pollutants other than SAM. 
FCPP SCR Project 

Response to Comments 

Page 36 of 109 

Maximum Heat Input of Units 4 and 5

Comment 27: 

(Commenters: SJCA, Stamper Report) 

Excerpts of the comment letter and “expert report” regarding maximum heat input are contained 

below. 

EPA and APS did not use the FCPP units’ hourly emissions rate based on the emission units’ operational 

capabilities following the project. 

In projecting future emissions, APS assumed that FCPP Units 4 and 5 each have an hourly heat input of 

7,411 MMBtu/hr, which does not reflect the hourly operational capabilities of each unit. Further, 

nothing in the PSD regulations or the December 31, 2002 preamble cited above provide for the use of a 

24-hour average hourly emission rate or a plant-wide 24-hour emission rate in projecting future actual 

emissions. Relying on the heat input assumed in the final BART rule and maximum 24-hour heat input 

does not comport with EPA requirements that specifies projected actual emissions must be based on 

the hourly emission rate reflective of the operational capabilities of each emissions unit. EPA may not 

rely on these values in projecting future actual emissions unless APS wants to accept federally 

enforceable limits on 24-hour average heat input. 

The Title V permit and the Title V Permit Renewal application for Four Corners Power Plant states the 

maximum heat input capacity of Units 4 and 5 is 8,612 MMBtu/hr. In addition, the peak actual hourly 

heat inputs for FCPP Units 4 and 5 reported to CAMD5 have exceeded 7,411 MMBtu/hr. A ranking of all 

hourly heat input rates reported to CAMD during 2011 and 2012 for each Units 4 and 5 shows that for 

4.3% and 7.0% of all operating hours, Units 4 and 5 operated at heat inputs greater than 7,411 

MMBtu/hr, respectively. The peak hourly heat input for Unit 4 was 7,695.3 MMBtu and the peak 

hourly heat input for Unit 5 was 8,603.7 MMBtu/hr. While these hourly heat inputs are below the 

design heat input capacity of 8,612 MMBtu/hr, the values are well above the assumed 7,411 

MMBtu/hr heat input capacity for each unit. 

Based on this information, it is clear that neither EPA nor APS based the projected actual emissions on 

the hourly heat input at which each unit was capable of operating. If the hourly heat input capacity of 

each unit as stated in the Title V permit is in error and is an overstatement of the operational 

capabilities of each unit, then that should be corrected in an amended Title V permit that identifies the 

true maximum heat input capacity of each unit. 

Response 27:

The EPA used the FCPP units’ hourly emissions rate based on the emission units’ operational 

capabilities. The issue in this comment is how EPA as the permitting authority interprets its regulation 

defining “Projected Actual Emissions.” See 40 CFR 52.21(b)(41). Specifically, the comment urges EPA to 

adopt an interpretation that requires the Projected Actual Emissions to be calculated by multiplying 

the hourly heat rate input by the annual capacity factor. Additionally, the commenters contends that 

 

5 The commenter is likely referring to Air Markets Program Data (AMPD), which was previously referred to as Clean Air 

Markets Data (CAMD). The two terms are generally used interchangeably. 
FCPP SCR Project 

Response to Comments 

Page 37 of 109 

the hourly heat input rate of Units 4 and 5 must be equal to its maximum hourly potential to emit 

established in its title V operating permit. Alternatively, the commenter argues, APS must accept a 

federally enforceable heat input limit based on the hourly heat input rate used for calculating 

Projected Actual Emissions. EPA disagrees with both parts of the comment for the following reasons. 

The regulatory definition of Projected Actual Emissions is: “the maximum annual rate, in tons per year, 

at which an existing emissions unit is projected to emit a regulated NSR pollutant” in any one of five (or 

ten) years following the project. 40 CFR 52.21(b)(41)(i)(emphasis added). The regulation further 

provides that in determining Projected Actual Emissions, the owner or operator: 

[s]hall consider all relevant information, including but not limited to, historical operational data, 

the company’s own representations, the company’s expected business activity and the 

company’s highest projections of business activity, the company’s filings with the State or 

Federal regulatory authorities and compliance plans under the approved State Implementation 

Plan. 

40 CFR 52.21(b)(41)((ii)(a). The regulations prescribe using source-specific operating information to 

determine Projected Actual Emissions rather than using a source’s permitted potential to emit. The 

regulations also define “Projected Actual Emissions” as the “maximum annual rate” not the maximum 

hourly rate. In promulgating the regulation during the NSR Reform rulemaking, EPA stated: 

In calculating the projected actual emissions you should consider both the expected and the 

highest projections of the business activity that you expect could be achieved and that are 

consistent with information your company publishes for business related purposes such as a 

stockholder prospectus, or applications for business loans. 

67 FR at 80196 (Dec. 31, 2002). 

Table A-3 of the PSD Application presents APS’ calculation of Projected Actual Emissions. The 

calculation is based on an hourly heat rate input multiplied by expected hours of operation (i.e. 

capacity factor x 8760 hours). The hourly heat rate is a reference point for determining the capacity 

factor. APS used 7,411 MMBtu/hr as a reference point because it represented the 99.25 percentile of 

hours of operation for Units 4 and 5 over the 2009-2011 timeframe.6 This value was used in previous 

analyses, such as the BART analysis for FCPP, and the FCPP and Navajo Mine Energy Project Draft 

Environmental Impact Statement, Volume 1.7 The hourly heat input and capacity factor were then used 

to calculate the projected future annual fuel use (i.e. MMBtu/yr), or how much fuel APS plans to 

combust to generate the electricity to meet the demand it projects. For baseline actual emissions, 

Table A-1.1 lists annual heat input (MMBtu/yr) for each 24-month period in calendars years 2010-2013, 

and Table A-1.2 establishes the baseline period as January 2011 through December 2012 and the 

associated annual heat input (i.e. amount of fuel combusted) of 97,258,307 MMBtu/yr. Then APS 

estimated the annual heat input from demand growth (18,749,957 MMBtu/yr) and extra fuel 

 

6

See November 25, 2014 letter from Thomas H. Livingston, FCPP to Lisa Beckham, EPA, “Four Corners Power Plant SCR 

Retrofit Project – Addendum to Application for PSD Permit, at 1-2. 

7

Id. 
FCPP SCR Project 

Response to Comments 

Page 38 of 109 

combusted for SCR operation (i.e., parasitic load and economizer bypass) of 348,025 MMBtu/yr to 

estimate its Total Projected Future Fuel Use of 116,356,289 MMBtu/yr. Table A-3, line 5. Therefore, 

the expected future annual fuel use is the critical factor for calculating Projected Actual Emissions in 

this PSD Application, not an hourly heat input rate and expected capacity factor. 

The projected capacity factor of 89.35% is a product of the APS’ forecasting model, taking into account 

numerous economic and operational considerations8, based on an assumption of a 7,411 MMBtu/hr 

heat input rate as a reference point. It is this value that informs APS’ decisions regarding such elements 

of its operations such as energy portfolio, investments, and maintenance and operation of its fleet 

units.9 

The Total Projected Future Fuel Use (MMBtu/year) can then be determined using an hourly heat rate 

with a corresponding annual capacity factor. However, requiring APS to increase or decrease the 

hourly heat rate would not cause APS to change its projected annual fuel use (MMBtu/year), but 

instead would change the corresponding annual capacity factor. For example, as presented in the 

proposed PSD permit and April 2014 PSD application, the projected fuel use results in an annual 

capacity factor of 89.35% when assuming an hourly heat rate of 7,411 MMBtu/hour. This same 

projected fuel use results in an annual capacity factor of 76.9% when using an hourly heat rate of 8,612 

MMBtu/hr. 

EPA has considered the comment asserting that Projected Actual Emissions can only be calculated by 

multiplying the title V potential hourly heat input rate and capacity factor. We do not find that our 

regulations are so constrained. 

The commenter cites to language in the preamble to the 2002 NSR Reform rulemaking indicating that 

projected actual emissions should be calculated using: 

(1) The hourly emission rate, which is based on the emission unit’s operational capabilities 

following the change(s), taking into account legally enforceable restrictions that could affect 

the hourly emissions rate following the changes(s); and 

(2) The projected level of utilization, which is based on both the emissions unit’s historical 

annual utilization rate and available information regarding the emissions unit’s likely postchange capacity utilization. 

67 FR 80196 (Dec. 31, 2002). According to the commenter, this language requires EPA to calculate the 

projected actual emissions based on the heat input rate contained in FCPP’s title V permit, which is 

8,612 MMBtu/hr. Essentially, the commenter considers the heat input rate in the title V permit to 

represent the “operational capability” for Units 4 and 5. (“This hourly heat input of 7,411 MMBtu/hr 

per unit does not reflect the hourly operational capability of each unit.” Victoria Stamper comment 

letter at p. 4). We disagree with the commenter that the “operational capability” for calculating 

“projected actual emissions” in this case is the maximum potential to emit in the title V permit of 8,612 

 

8

Id. 

9

Id. 
FCPP SCR Project 

Response to Comments 

Page 39 of 109 

MMBtu/hr. The commenter relies primarily on the value in the title V permit without looking at other 

relevant information such as FCPP’s operating history and expected projections of business activity. 

EPA considers the hourly heat input rate (7,411 MMBtu/hr10) and capacity factor (89.35%) that APS 

associated with its projected annual fuel use (116,356,289MMBtu/yr) to represent the appropriate 

values for its post-project “operational capacity.” 

An important consideration in emissions calculations is how the time period of the operational 

capability matches the time period for the emissions estimate. Per 52.21(b)(41), ‘projected actual 

emissions’ is expressed in tons per year. The commenter has asserted that the heat rate identified in 

the title V permit, 8,612 MMBtu/hr, should represent the operational capability used in calculating 

projected actual emissions. But, this heat rate is the heat rate representing the maximum potential 

over a 1-hr average for title V purposes, which means that the commenter’s assertion relies on the 

assumption that the title V potential hourly heat rate could be sustained for every hour over a period 

of an entire year. As noted by the commenter, historical data indicates that the heat rate was not 

achieved for even a single hour by either unit. As a result, we disagree that it is the required basis for 

determining operational capability for purposes of calculating projected actual emissions, which are 

expressed on an annual basis (i.e., tons per year). Further, using the title V hourly heat input rate, 

which is rarely achieved, would not allow APS to properly forecast expected demand. 

We supported and continue to support using 7,411 MMBtu/hr as the hourly heat input rate that 

represents the operational capability for the projected actual emissions calculation. APS indicated that 

this value was the 99th percentile of hourly boiler operating data for the 3-year period 2009 through 

2011.11 This is also the value that regulators have considered appropriate in other contexts to consider 

maximum emissions, such as the EIS being prepared under NEPA and the BART FIP. Thus, APS, EPA, and 

other regulators have consistently viewed 7,411 MMBtu/hr as the appropriate value for estimating the 

typical maximum hourly heat input rate for FCPP operations following the FCPP SCR Project. EPA 

continues to find that using the 99th percentile of the hourly boiler operating data from 2009 – 2011 is 

appropriate and conservative for calculating projected actual emissions in this permitting action. 

The commenter also states that 7,411 MMBtu/hr cannot represent the operational capability (i.e. 

typical maximum hourly heat input rate) of Units 4 and 5 because those Units exceeded that rate 4.3% 

and 7% of the time Units 4 and 5 operated in 2011 and 2012. Although the commenter does not 

contend that some other value from the actual operating data should be used for calculating the 

projected actual emissions, EPA acknowledges that Units 4 and 5 operated for a minimal number of 

hours with a heat input rate that was higher than 7,411 MMBtu/hr. Attachment 3 to comment letter of 

Victoria Stamper. Without additional information, however, EPA cannot determine that 7,411 

MMBtu/hr does not represent the post-project operational capability (i.e. typical maximum hourly 

heat input rate) of Units 4 and 5. The mere fact of an excursion of this heat input rate does not justify 

 

10 The Comment Letter states that EPA used this value because it is the 24-hr average hourly heat input. Although 7,411 

MMBtu/hr is the 24-hr average hourly heat input rate, that fact was not a basis for our decision on the correct way to 

calculate Projected Actual Emissions. As discussed above, the Projected Actual Emissions calculation is based on APS’ 

estimated future annual fuel use. To the extent the commenter suggests we relied on the 24-hr hourly heat rate input as a 

factor for calculating Projected Actual Emissions, the commenter is incorrect. 

11 Id. 
FCPP SCR Project 

Response to Comments 

Page 40 of 109 

the use of the unit’s potential to emit, based on the worst case emissions in the title V permit. But, 

again, we note using the units’ title V potential hourly rate for determining projected actual emissions 

would not change our analysis, because we would simply revise the capacity factor to arrive at the 

same Total Projected Future Fuel Use (116,356,289 MMBtu/yr) to calculate the project’s tons per year 

of emissions. 

The commenter did not state that EPA should consider any rate other than 8,612 MMBtu/hr. EPA 

notes, however, that the regulations do not prescribe using the pre-project maximum hourly heat 

input rate (7,695 MMBtu/hr for Unit 4 and 8,601 MMBtu/hr for Unit 5). The regulations instead 

evaluate post-project actual emissions based on the “operational capability” of the unit after the 

modification. In this permitting action, EPA reasonably accepted APS’ projection that 7,411 MMBtu/hr 

represented its post-project operational capability based on several considerations: 

(1) Although not the maximum hourly rate recorded, it was the pre-project 99th percentile of 1-

hr boiler operating data from 2009-11; 

(2) The value was used in other regulatory actions to evaluate future operations at the facility; 

and 

(4) As discussed in more detail below, the post-project operational capability will not be 

changing after installation of the SCR pollution controls on Units 4 and 5. See response to 

Comment 28. 

In summary, the heat input rate in the title V permit would be used to calculate the potential to emit 

for Units 4 and 5, not the projected actual emissions. Potential to emit is only required for calculating 

the future emissions from new emissions units, not existing emissions units. The commenter uses the 

term “operational capability” rather than potential to emit, but EPA disagrees with the commenter’s 

interpretation of that quoted preamble language. EPA does not consider the post-project “operational 

capability” to be the same as the post-project potential to emit for an existing unit. EPA agrees with 

information in the PSD permit application that 7,411 MMBtu/hr generally represents the operational 

capability of Units 4 and 5. 

EPA also disagrees with the commenter’s statement that our action is inconsistent with EPA’s 

longstanding policy and WEPCO. EPA has evaluated modifications of existing EGUs based on projected 

actual emissions rather than potential to emit since WEPCO (57 FR 32314 (July 21, 1992)) and for all 

existing units since NSR Reform (67 FR 80186 (Dec. 31, 2002)). We also note that the modification at 

issue in the FCPP SCR Project is fundamentally different than the project that was evaluated in WEPCO. 

The WEPCO project was undertaken to return a coal fired EGU to its prior utilization rate before the 

modification. The FCPP SCR Project, in contrast, will not recover lost capacity. The FCPP SCR Project will 

significantly reduce NOX emissions through installation of pollution controls, but it will not have any 

effect on increasing or even capturing the lost capacity of Units 4 and 5. The FCPP SCR Project will not 

change the capacity of Units 4 and 5 in any way; the only effect on capacity of the SCR will be to cause 

a minor decrease in the potential power available for sale through the parasitic load of the SCR and DSI 

systems. For the numerous reasons discussed above, the maximum hourly heat input rate of 7,411 

MMBtu/hr for Units 4 and 5 is permissible, but the particular value chosen does not affect how 

projected actual emissions were calculated. 
FCPP SCR Project 

Response to Comments 

Page 41 of 109 

Finally, the Commenter states that “[i]f the hourly heat input capacity of each unit as stated in the title 

V permit is in error and is an overstatement of the operational capabilities of each unit, then that 

should be corrected in an amended title V permit that identifies the true maximum heat input capacity 

of each unit.” EPA disagrees. The heat input rate in the title V permit is the maximum potential to 

emit of each unit, not the projected actual emissions. There is no requirement for the projected actual 

emissions to be contained in a federally enforceable permit limitation. See 67 FR 80204 (Dec. 31, 

2002) (“You will not be required to make the projected actual emissions projection through a 

permitting action.”) 

Demand Growth and “Previously Accommodated”

Comment 28:

(Commenters: SJCA, Stamper Report) 

The commenter and “expert report” also criticized EPA’s analysis of the demand growth exclusion on 

two grounds, the first of which is excerpted below. 

Neither APS nor EPA has demonstrated that the projected increase in annual heat input due to the 

increased capacity factors at FCPP unit 4 and 5 meet the PSD requirements to be excluded from 

projected actual emissions as due solely to demand growth. 

In projecting future actual emissions, APS and EPA have excluded a significant portion of emissions as 

due to demand growth. Specifically, APS projected an increase in demand growth at FCPP Units 4 and 5 

with operations at an 89.35% capacity factor. In contrast, the baseline actual emissions calculations 

were equivalent to an annual capacity factor of 74.9%. This is a significant projected increase in 

capacity factor, with an associated significant increase in annual heat input and emissions. Neither APS 

nor EPA included the emissions associated with this demand growth in the projections of future actual 

emissions of FCPP Units 4 and 5 after the project. The federal PSD rules do allow for the exclusion of 

emissions increases in the determination of projected actual emissions, but only “that portion of the 

unit’s emissions following the project that an existing unit could have accommodated during the 

consecutive 24 month period used to establish the baseline actual emissions under [40 C.F.R. 

§52.21(b)(48)] and that are also unrelated to the particular project, including any increased utilization 

due to product demand growth....” 40 C.F.R. §52.21(b)(41)(ii)(c). Neither EPA nor APS submitted or 

included any information in the administrative record to demonstrate that either of these criteria were 

evaluated or that they are met. EPA has the ability to request more detail and documentation from 

APS in this evaluation, and EPA must do so to ensure that any demand growth emissions are justified 

to be excluded from the projected actual emissions calculation. 

The commenter provided an estimate of what Units 4 and 5 were capable of accommodating. The 

commenter’s estimate evaluated the number of hours during the 2011 to 2012 baseline period during 

which Units 4 and 5 reported to CAMD any gross load greater than zero. This data is presented in Table 

1 (See Stamper Report). Table 1 shows the potential availability factor of each unit considering the 

hours the units were able to produce electricity during the baseline period. Because these units are 

base-loaded units and not peaking units, it is safe to assume if the units are available, the units will 
FCPP SCR Project 

Response to Comments 

Page 42 of 109 

generate at least some level of electricity. Thus, the hours reported to CAMD that the units were not 

generating at least some level of electricity can reasonably be considered as hours the units were not 

available to generate electricity, due to forced outages or planned outages for capital improvements or 

for maintenance. From this data, the commenter calculated the potential availability factor for each 

unit averaged over the 2011 to 2012 baseline period, by dividing the total hours during which some 

electricity was produced by the unit divided by the total number of possible operating hours in each 

year. 

The commenter believes that this this analysis likely overstates availability factor, because it counted 

any hours for which a measured gross load was reported to CAMD as an hour that the unit could 

generate at full power output. However, some of those hours during which measurable gross hour load 

was reported could have been during an outage or during a failed startup or otherwise were not 

reflective of a time period during which the unit could have been operated to meet electricity demand. 

Further, these calculations do not represent the level of operations that the units were capable of 

accommodating during the baseline period. Such an analysis would need to be based on the equivalent 

availability factor, which would also take into account whether the unit was limited to less than full 

power output due to derates. 

Estimates of potential availability factor calculated by the commenter are summarized in Table 1 (see 

Stamper Report comment letter). The commenter states these values (85.62% for Unit 4, 82.75% for 

Unit 5) represent the upper limit of capacity factor for Units 4 and 5 over the CY2011-12 baseline 

period. The commenter notes that these maximum potential capacity factors are lower than APS’s 

projected capacity factors (89.35%) for these units as presented in the PSD permit application for the 

project. 

APS’s highest projection of increased capacity factor that is due only to demand growth, according to 

APS’s April 2014 PSD Permit Application, is in 2021 during which the projected capacity factor for Unit 

4 is 7.23% and 3.10% higher than the potential availability factors for each Unit 4 and Unit 5, 

respectively, during the baseline period. On average between FCPP Units 4 and 5, the projected postchange capacity factor in 2021 is 5.17% higher than the potential availability factor for the combined 

Units 4 and 5 during the baseline period. This means that, at the minimum, 5.17% of the projected 

increase in capacity factor cannot be excluded from the projected actual emissions calculation because 

the units were not capable of accommodating the increased utilization during the baseline period. 

However, it is important to note that the amount of projected increase in utilization of the FCPP Units 

4 and 5 that could not have been accommodated by FCPP Units 4 and 5 during the baseline period 

could be more than 5.17%. An evaluation of the actual availability factor for each FCPP Units 4 and 5 

during the 2011 to 2012 baseline period, taking into account derates, failed starts, and forced outages, 

should have been done by EPA to determine the specific amount of increase in capacity that the units 

were capable of accommodating during the 24-month baseline period. Therefore, it is safe to say that, 

during the baseline period, FCPP Units 4 and 5 were not capable of accommodating all of the increase 

in capacity factor that APS has projected for year 2021. 
FCPP SCR Project 

Response to Comments 

Page 43 of 109 

Response 28:

The commenter contends that it was inappropriate for APS to exclude from the projected actual 

emissions calculation certain emissions that are attributed to projected growth in demand. The 

comment raises two issues -- (1) whether the projected growth in demand is related to the 

modification under review and (2) whether the existing Units 4 and 5 were capable of accommodating 

the projected growth in demand -- which are addressed separately below. 

Before addressing the specific comments on this issue, it is useful to review the context of this 

exclusion in EPA’s regulations. After a decision from the 7th Circuit Court of Appeals Wisconsin Electric 

Power Co. v. Reilly, 893 F.2d 901 (7th Cir. 1990), EPA promulgated regulations in 1992 consistent with 

the judicial opinion, which clarified aspects of NSR applicability analyses for projects at electric 

utilities.12 Among other things, the 1992 regulations were promulgated to “provide further clarification 

of the existing regulatory requirement that only those increases in emissions that actually result from 

the physical change or change in the method of operation can be considered in determining whether 

the proposed change subjects the utility to NSR requirements.” 57 FR 32314, 32315 (July 21, 1992). 

Under the currently applicable version of these regulations, pursuant to 40 CFR 52.21(b)(41)(ii)(c), a 

PSD applicant in calculating its projected actual emissions for purposes of determining PSD 

applicability: 

“[s]hall exclude, in calculating any increase in emissions that results from he [sic] particular 

project, that portion of the unit’s emissions following the project that an existing unit could 

have accommodated during the consecutive 24-month period used to establish the baseline 

actual emissions under paragraph (b)(48) of this section and that are also unrelated to the 

particular project, including any increase in utilization due to product demand growth.” 

This provision is often referred to as the “demand growth exclusion.” The question is one of 

attribution: Are the emissions increases under PSD permitting review attributable to the project under 

review. As explained in the WEPCo rule: “where increased operations are in response to independent 

factors, such as system-wide demand growth, which would have occurred and affected the unit's 

operations even in the absence of the physical or operational change, such increases do not result 

from the change and shall be excluded from the projection of future actual emissions. Thus, in 

assessing whether the proposed change will result in an increase in actual emissions, utilities need not 

include in their projection of post-change utilization that portion of the increased rate of utilization, if 

any, due to factors unrelated to the physical or operational change, such as an increase in projected 

capacity utilization due to the rate of electricity demand growth for the utility system (of which that 

source is a member) as a whole.” 57 FR 32326 (July 12, 1992). Both regulatory criteria must be met in 

order for emissions to be excluded from projected actual emissions, that the emissions (1) could have 

been legally and physically accommodated before the project and (2) are unrelated to the project. 40 

CFR 52.21(b)(41)(ii)(c).13

 

12 In addition, EPA’s PSD regulations provide that standing alone, an increase in the hours of operation or rate of production 

of a source is not a physical change or change in the method of operation, unless such a change would have been 

prohibited under certain types of enforceable permit conditions. 40 CFR 52.21(b)(2)(iii)(f). 

13 See also EPA Guidance Memo, April 20, 2010, Re: Northampton Generating Company PSD/NSR Analysis, page 3. 
FCPP SCR Project 

Response to Comments 

Page 44 of 109 

To address the commenter’s first issue, whether the projected growth in demand is related to the 

modification under review, it is important to underscore the scope of the modification under review. 

The modification is installation of SCR. See Fact Sheet, Section 3.3. SCR, an add-on control device, does 

not modify the boilers in any way, but instead causes three types of emission increases at FCPP: (1) the 

SCR catalyst causes additional SO2 in the flue gas to oxidize and form additional SAM from Units 4 and 

5, (2) the operation of the SCR and DSI systems result in parasitic power loss for the facility requiring 

more fuel (0.324% annually14) from Units 4 and 5 to produce the same amount of power to the grid, 

and (3) relatively small increases in PM10 and PM2.5 emissions from additional truck traffic and silo 

storage of the dry sorbent injection and reagent for the SCR systems. All of these increases have been 

accounted for in our emissions analysis for projected actual emissions. See Fact Sheet, Tables 2, 4 and 

5. Also, see response to Comment 32 where we added the parasitic load from the DSI system. Thus, 

our calculation of projected actual emissions includes the emissions that are attributable to the 

project. Subtracting the total baseline actual emissions from the total projected actual emissions 

resulted in significant emissions increases for SAM, PM10 and PM2.5. See Fact Sheet, Table 3. We note 

that the primary reason that there are increases of PM10 and PM2.5 is because SAM is a precursor to 

those two pollutants. As such, we have appropriately accounted for all emissions increases associated 

with the FCPP SCR Project, and any other increases in emissions than those described above are 

unrelated to the installation of the SCR. Accordingly, only SAM, PM10 and PM2.5 were subject to further 

review for PSD applicability (i.e., a netting analysis). See 40 CFR 52.21(a)(2)(iv)(a). 

Although EPA’s regulations do not prescribe the exact information an applicant for a PSD permit should 

include to support using the exclusion in 40 CFR 52.21(b)(41)(ii)(c) , we can reasonably look to EPA’s 

discussion in 40 CFR 52.21(r)(6), known as the reasonable possibility test. 40 CFR 52.21(r)(6)(i) requires 

the owner/operator of a source that is not applying for a PSD permit to document and maintain certain 

information, including the following: 

A description of the applicability test used to determine that the project is not a major 

modification for any regulated NSR pollutant, including the baseline actual emissions, the 

projected actual emissions, the amount of emissions excluded under paragraph (b)(41)(ii)(c) of 

this section and an explanation for why such amount was excluded, and any netting 

calculations, if applicable. 

As discussed in more detail in Response to Comment 29 below, the information provided by APS is a 

sufficient explanation for why the emissions were excluded on the basis of anticipated growth in 

demand that cannot be attributed to installation of SCR. In addition, the applicant also submitted 

sufficient information to justify its anticipated rate of future demand (89.35% capacity) from FCPP in 

2021 based on its system-wide 2014 Integrated Resource Plan.15

 

14 See November 25, 2014 letter from Thomas H. Livingston, FCPP to Lisa Beckham, EPA, Four Corners Power Plant SCR 

Retrofit Project – Addendum to Application for PSD Permit, at 3-4. Note that APS previously used a conservative 0.3% 

parasitic load in its calculations even though the sum of the increases from SCR parasitic load and economizer bypass was 

only 0.289%. In our revised calculations we have carried on this conservatism (i.e., in this context, a tendency to over rather 

underestimate), resulting in a 0.324% increase in fuel use.

15 See July 2, 2014 letter from David Bloomfield, FCPP to Lisa Beckham, EPA, Four Corners Power Plant SCR Retrofit

Project – Addendum to Application for PSD Permit, and November 25, 2014 letter from Thomas H. Livingston, FCPP to 

Lisa Beckham, EPA, Four Corners Power Plant SCR Retrofit Project – Addendum to Application for PSD Permit. 
FCPP SCR Project 

Response to Comments 

Page 45 of 109 

In the second issue raised, the commenter disputes whether Units 4 and 5 had the ability to 

accommodate a capacity of 89.35% based on an evaluation of two years of past operating data over 

2011 and 2012. The comment states: “Because these units are base-loaded units and not peaking 

units, it is safe to assume if the units are available, the units will generate at least some level of 

electricity.” Victoria Stamper comment letter at p. 6. The commenter, therefore, assumed that for any 

periods of non-operation during the 24-month baseline period, Units 4 and 5 were physically incapable 

of operating during those periods due to outages or maintenance, and could not have accommodated 

any additional increase in demand. The only information the commenter cited for this assumption is a 

statement from Southern California Edison, a former owner of FCPP, that operation of FCPP is 

economically favorable and that it had been run as a baseload facility. Other than this statement, the 

assumption on which the comment relies (that any periods of non-operation in 2011 and 2012 were 

attributable to only an outage or maintenance) is unsupported. 

Although outages and maintenance are a cause for periods of non-operation, there are numerous 

other considerations that go into operating specific EGUs. For example, APS indicated this includes 

considering16: 

1. Weather Normalized Forecasted Loads provided by Revenue Analysis and Forecasting; 

2. Unit Parameters and Outage schedule provided by Fossil Generation; 

3. Long Range Resource Plan provided by Resource Planning and Analysis; 

4. Forecasted gas and coal fuel prices provided by Resource Planning and Analysis; 

5. Forecasted nuclear prices provided by Nuclear Engineering; 

6. Forecasted renewable profiles from Renewable Energy; 

7. Forecasted gas and electric market prices provided by Resource Management. 

A model will then use these factors to determine the most cost efficient means of supplying energy to 

meet the forecasted load, given the available resources, in consideration of both outage limitation and 

market conditions. Given this information, we disagree with the commenter’s assertion that any past 

periods of non-operation are due solely to outages or maintenance, and could not have been 

accommodated by Units 4 and 5 during the baseline period. Only factor 2 above looks at the specific 

unit parameters and outage schedule in determining the use of a specific unit. Instead, there are a 

number of other factors that may affect when Units 4 and 5 do or do not operate. Specifically, periods 

of non-operation can also be attributed to low demand for these units. 

Further, we note that Units 4 and 5 have historically been able to achieve capacity factors greater than 

89.35%.17 For example, Unit 4 operated at greater than a 90% capacity factor in 2003, 2006 and 2008. 

Unit 5 operated at a capacity factor exceeding 90% in 2004. So, while Units 4 and 5 may not have 

operated at a capacity of 89.35% during the 24-month baseline period, nothing in our record or the 

comment indicates that these units could not have physically or legally accommodated this capacity 

during the baseline period. Similarly, there is no information in the record to indicate that Units 4 and 

5 have degraded in a manner between the years of higher capacity operation (e.g. 2003-2008) and the 

 

16 Id at 2-3.

17 Id at Table 2 showing annual capacity factors from 2000-2013. 
FCPP SCR Project 

Response to Comments 

Page 46 of 109 

baseline years of 2011-2012 that would prevent them from operating at 90% capacity factor. As 

demonstrated above, there are a number of complex factors that are used to determine when a 

particular EGU operates. The fact that these units have accommodated a capacity factor of 89.35% in 

the past demonstrates that outage and maintenance schedules are not the only factors that determine 

when Units 4 and 5 are placed in operation. Notably, if the commenter were correct that capacity was 

dictated solely by outages and maintenance, the historic use of these units would be nearly uniform. 

Instead, demand plays a significant role in how these units operate. We find the commenter’s 

reasoning too narrow and oversimplified to justify changing our determination and the commenter has 

not presented any persuasive information to demonstrate Units 4 and 5 were not physically and legally 

capable of operating at 89.35% capacity, on average, during the baseline period. 

Even if we accepted the commenters’ assertions that the maximum utilization that could have been 

accommodated by Units 4 and 5 during the baseline period is a capacity of 85.62% (Unit 4) and 82.75% 

(Unit 5), it would not alter our conclusion that the only pollutant for which PSD review is triggered is 

SAM, because the commenter’s analysis fails to consider the effect of netting. The emission 

calculations summarized in Tables 1 and 2 below illustrate the result of accepting the commenters’ 

assertion regarding what Units 4 and 5 could have previously accommodated in 2011 and 2012.18 Table 

1 presents the project-only emission increases corresponding to step 1 of the PSD applicability analysis. 

Table 1, Line A contains baseline actual emissions, which are unchanged from those presented in the 

draft permit. Line B represents annual emissions that correspond to the “could have previously 

accommodated” capacity factors asserted by the commenter (85.62% for Unit 4, 82.75% for Unit 5). 

Line C represents the amount of emissions that could have been accommodated, relative to baseline 

emissions. Line D represents projected actual emissions that include the emissions the applicant 

attributed to growth in demand (i.e., these emissions correspond to 89.35% capacity factor, the future 

projected capacity factor in 2021), as well as the increased power demand due to the parasitic load 

associated with the SCR. Line E represents the project emission increase, as the difference between 

projected actual emission rates and the baseline emission rates. Line F represents the project emission 

increase, but accounting for the amount of emissions that “could have been previously 

accommodated” per the commenter’s assertion. As seen from this table, this results in additional 

pollutants that would exceed the SER in step 1 of the applicability analysis, such as SO2 and GHGs. 

Table 2 presents netting emission calculations that correspond to step 2 of the PSD applicability 

analysis. Table 2, Line A contains the project-only emission increases calculated from Table 1 (Line F). 

Line B contains the combined contemporaneous increases and decreases, and includes emissions 

associated with the auxiliary boiler construction and Unit 1-3 shutdown. Line C represents the net 

emission rate resulting from adding Lines A and B. As seen in Line C, which includes all of the emissions 

the applicant excluded, even if we accepted the commenter’s assertion and adjusted our applicability 

analysis accordingly, it still results in only a significant net emissions increase for SAM. Thus, SAM is 

the only pollutant for which PSD is triggered. 

 

18 See spreadsheet “Response 28 Emission Calculations.xls” in the Administrative Record 
FCPP SCR Project 

Response to Comments 

Page 47 of 109 

Table 1 Summary of Emissions (tpy) from the FCPP SCR Project (accounting for commenter’s estimate of previously accommodated

emissions)

 

Emission Unit NOX SO2 PM PM10 PM2.5 CO VOC H2SO4 Lead GHGs 

(CO2e) 

A Baseline Emission Rate 24,029 8,373 644 801 550 1,444 5.79 14.10 0.115 10,058,133 

B Previously Accommodated Emission Rate1

27,004 9,411 721 902 618 1,623 6.50 15.85 0.129 11,304,034 

C Previously Accommodated Emissions (B-A) 

2,975 1,038 77 100 68 179 0.71 2 0.014 1,245,901 

D Projected Actual Emission Rate (includes growth 

in demand)2

5,701 10,018 768 1,292 948 1,727 6.92 253 0.137 12,033,176 

E Project Emission Increases (D-A) -18,328 1,645 124 490 398 283 1.13 239 0.022 1,975,043 

F Project Emission Increases, accounting for 

previously accommodated emissions (E-C) -21,303 607 47 390 331 105 0.42 237 0.008 729,142 

 Significant Emissions Rate 40 40 25 15 10 100 40 7 0.6 75,000 

Significant Emission Increase? No Yes Yes Yes Yes Yes No Yes No Yes 

1 This emission rate corresponds to the 'could have previously accommodated' capacity factors asserted by the commenter (85.62% for Unit 4, 82.75% for Unit 5). 

2 This projected actual emission rate represents emissions associated with a capacity factor of 89.35% (as projected by APS in 2021), and also includes the emissions associated with the 

parasitic load from new emission controls. 

Table 2 Summary of PSD Applicability Determination for the FCPP SCR Project (accounting for commenter’s estimate of previously

accommodated emissions)

SO2 PM PM10 PM2.5 CO H2SO4

GHGs 

(CO2e)

A Significant emissions increases from the Project 607 47 390 331 105 237.23 729,142 

B 

Combined Contemporaneous Emissions Decreases -3,110 -253 -518 -491 -623 -1.25 -4,448,122 

C Significant net emissions -2,503 -206 -128 -160 -518 235.98 -3,718,980 

Significant emission rate 40 25 15 10 100 7 75,000 

PSD Applicable? No No No No No Yes No
Shut Down of Units 1-3 is Related to the Project

Comment 29: 

(Commenters: SJCA, Stamper Report) 

The comment letter and “expert report” have also asserted that the demand growth exclusion cannot apply 

because the increase in demand is related to the FCPP SCR Project. Excerpts of the comments are provided 

below. 

The Projected Increase in Capacity Factor of Each FCPP Units 4 and 5 that Is Due to the Shutdown of FCPP 

Units 1, 2, and 3 Should Have Been Considered as Related to the Project. 

The second requirement to exclude emissions increases as solely due to demand growth is that EPA needs to 

verify that the capacity factor increases are completely unrelated to the project. The project inherently 

includes the shutdown of FCPP Units 1-3. While EPA failed to identify the shutdown of FCPP Units 1-3 in its 

description of the project at FCPP, APS actually did identify the shutdown of FCPP Units 1-3 in its description of 

the project. See April 2014 FCPP PSD Permit Application at 2.1 “Project Description.” See also EPA Fact Sheet 

for FCPP Permit at 2-3. It stands to reason that the capacity factor of FCPP Units 4 and 5 will increase with the 

shutdown of FCPP Units 1 – 3. 

The overall project at FCPP is compliance with best available retrofit technology (BART) requirements. In 2012, 

EPA promulgated BART requirements for the FCPP and also promulgated an alternative BART compliance 

option, pursuant to a request from APS. The alternative BART compliance option allows APS to choose to 

permanently shut down Units 1, 2 and 3 by January 1, 2014 and to have until July 31, 2018 to retrofit Units 4 

and 5 with post-combustion NOx controls to meet an emission limit of 0.098 lb/MMBtu at each unit based on 

a 30 boiler operating day average basis. 40 C.F.R. §49.5512(i)(3). Thus, this BART compliance option gives the 

FCPP owners the ability to delay installation of SCR at Units 4 and 5 by up to 1 year and 9 months if they 

commit to shut down Units 1, 2, and 3. 

This BART alternative was based on APS’s November 24, 2010 proposal to EPA to meet BART for NOx 

(attached as Ex. 5). 76 Fed. Reg. 10530, February 25, 2011. In the November 24, 2010 submittal to EPA, APS 

explained that it has reached an agreement to purchase Southern California Edison’s (SCE’s) ownership share 

of FCPP Units 4 and 5, and that APS had announced that if the sale closes, APS will retire FCPP Units 1-3 at 

some point in the future. Thus, APS has represented to EPA that the shutdown of Units 1-3 along with the 

installation of SCR at Units 4 and 5 are the company’s overall plans to comply with NOx BART. 

In requesting approval of the sales transaction by the Arizona Corporation Commission, APS presented the 

shutdown of Units 1-3 and the retrofitting of Units 4 and 5 (after purchase from SCE) as the most economical 

options for customers. Thus, it stands to reason that at least some of the projected capacity factor increases at 

FCPP Units 4 and 5 has to be associated with the shutdown FCPP Units 1-3, and the installation of SCR at Units 

4 and 5 along with the shutdown of Units 1-3 is all being done to comply with BART. Given all of this, it seems 

highly questionable to exclude demand-related emission increases as not due to the project. 

According to data in CAMD, FCPP Units 1, 2 and 3 produced a combined 4,084,007 gross MW-hours on 

average over 2011 to 2012. That is about 38% of the combined 10,824,394 gross MW-hours produced on 

average at FCPP Units 4 and 5 in 2011 to 2012. While FCPP Units 4 and 5 will not be able to pick up all of the 

load addressed by the operation of FCPP Units 1-3, it is reasonable to expect that Units 4 and 5 will pick up 

some of the load that had been formerly met with the operation of FCPP Units 1-3. All of these units were or 
FCPP SCR Project 

Response to Comments 

Page 49 of 109 

are base-loaded units, meaning that the units run 24-hours a day to meet the “around-the-clock” demand. 

Thus, it is reasonable to expect that Units 4 and 5 would be operated at higher capacity factors due to the 

need to in part make up for the shutdown of FCPP Units 1-3. For example, typically electrical generating units 

produce lower loads during the certain times of a day in which electricity demand is lower. During all times 

that FCPP Units 4 and 5 were not generating at maximum load, there would be some capacity for the units to 

increase generation to at least partly make up for the electricity needs not being met by FCPP Units 1-3. 

In summary, EPA cannot consider the projected increase in capacity factor of Units 4 and 5 as demand growth 

that is unrelated to project. The projected increase in capacity factor of FCPP Units 4 and 5 is likely due to the 

shutdown of baseloaded FCPP Units 1-3, which is inherently part of the project and therefore cannot be 

excluded in the projection of actual emissions increases after the project. 

Response 29:

We disagree with the commenter’s assertion that the capacity factor increase at Units 4 and 5 from 74.9% to 

89.35%, averaged between the Units, is related to the shutdown of Units 1-3. 

The exclusion now at 40 CFR 52.21(b)(41)(ii)(c) has been part of EPA’s regulations at least since the WEPCO 

rulemaking. 57 FR at 32327 (July 21, 1992). In the WEPCO rule, we stated: “EPA believes it is possible to 

distinguish between emissions increases that are related to a physical or operational change from those that 

are not.” Id. In the NSR Reform rule, in providing additional consideration of this exclusion, we stated: “in 

comparing your projected actual emissions to the unit’s baseline actual emissions, you only count emissions 

that will result from the project.” 67 FR at 80196. The project here is installation of SCR on Units 4 and 5. As 

discussed in Response 28, SCR is an add-on control device. Its installation and operation results in very minor 

emission increases from parasitic load and ancillary truck and reagent handling as shown below. Installation 

of SCR does not modify the boilers or cause an increase in their capacity or utilization. Table 3 below 

summarizes the emissions increases at Units 4 and 5 that are attributable to installation of SCR. 

Table 3 Emission Increases attributable to SCR installation

Category NOX SO2 PM PM10 PM2.5 CO VOC H2SO4 Lead GHGs 

(CO2e) 

Emission Increases from Increase 

in Fuel (375,881 MMBtu/yr, 

0.324%) 

18.42 32.36 2.48 4.17 3.06 5.58 0.02 0.82 0.000444 38,866.10 

Truck Traffic, Delivery Dry Sorbent 0 0 0.095 0.019 0.005 0 0 0 0 0 

Truck Traffic, Delivery of SCR 

reagent 

0 0 0.087 0.017 0.004 0 0 0 0 0 

Silo for Dry Sorbent Storage 0 0 0.086 0.086 0.086 0 0 0 0 0 

Silo for SCR Reagent Storage 0 0 0.214 0.214 0.214 0 0 0 0 0 

Totals 18.42 32.36 2.96 4.51 3.37 5.58 0.02 0.82 0.000444 38,866.10 

The commenters have not stated that installation of SCR itself will cause an increase in boiler utilization. 

Instead, the commenters characterize the scope of the FCPP SCR Project being considered in this permitting 

action as FCPP coming into compliance with the 2012 BART FIP. Victoria Stamper comment letter at p. 8 (“The 

overall project at FCPP is compliance with best available retrofit technology (BART) requirements.”). EPA 

disagrees. The scope of this permitting action is installation of SCR technology on Units 4 and 5. If the 2012 FIP 
FCPP SCR Project 

Response to Comments 

Page 50 of 109 

had established some other NOX emissions limit as BART that was achievable by a different technology, such 

as Low NOX burners or SNCR, it is possible that no permitting at all would have been triggered. However, 

because APS is installing SCR to meet the BART FIP NOX emissions limit, there was a significant net emissions 

increase in SAM. The fact that APS informed the Arizona Corporation Commission that retiring Units 1-3 and 

installing SCR for Units 4 and 5 was more economical than installing SCR on all 5 units (BART rather than the 

alternative) does not have any bearing on defining the scope of the FCPP SCR Project. APS and EPA have both 

referenced the BART FIP in the administrative record for this permit, but that does not define the scope of the 

FCPP SCR Project for purposes of this permitting. The scope of the project for this permitting action is 

described in Section 3.3 of the Fact Sheet as being the installation of SCR. Moreover, the comments have not 

provided any basis for defining the scope of this permitting action as anything other than installation of SCR on 

Units 4 and 5. 

Even if we were required to take into account the shutdown of Units 1-3, several factors several factors 

support our conclusion that increases in demand at Units 4 and 5 are not causally related. One reason is that 

APS forecast its increase in demand in 2021 based on a system-wide evaluation in its 2014 Integrated 

Resource Plan.19 The Plan forecasts that Arizona’s population will increase by 600,000 customers in 2029 and 

that total electricity consumption will increase by over 50%. APS states, “The annual capacity factor 

information in Table A-8 of the permit application is determined as the proportion of projected generation in 

relation to the generation possible within the same period.” APS owns additional coal fired electricity 

generation at Cholla Power Plant and Navajo Generating Station. APS also owns natural gas fired units and a 

nuclear power plant in Arizona. APS elaborated in its November 25, 2014 letter20 that its resource planning 

model determines “the most cost effective utilization of resources by unit and market heat rates.” The model 

applies to all of APS’ generating units, including its nuclear Palo Verdes facility. The model “takes into account 

the proportional nonlinear variability of unit and market hear rate with respect to energy generated or 

transacted.” Therefore, the model used by APS to project demand needed from Units 4 and 5 is derived from 

a system-wide, not FCPP specific, model. 21 The commenter has not provided any information to show that 

shutting down Units 1 – 3 would have any effect on the cost-effective utilization of Units 4 and 5. 

The comment letter states that because shutdown of Units 1-3 and retrofitting of Units 4 and 5 is the most 

economical option for consumers, “it stands to reason that at least some of the projected capacity factor 

increases at FCPP Units 4 and 5 has to be associated with the shutdown [sic] FCPP Units 1- 3, and installation 

of SCR at Units 4 and 5 along with the shutdown of Units 1 – 3 is all being done to comply with BART.“ Victoria 

Stamper comment letter at p. 9. EPA disagrees that BART compliance is relevant to defining the scope of the 

project in this PSD permitting action. The modification at issue is installation of SCR, which results in no 

increased capacity of the boilers and only triggers PSD for SAM. The statement quoted above indicates that 

shutting down Units 1 – 3 is more economical than retrofitting those units with SCR. That statement does not 

support that it will be more economical to generate electricity from Units 4 and 5 relative to APS’ entire 

system. 

 

19 See July 2, 2014 letter from David Bloomfield, FCPP to Lisa Beckham, EPA, Attachment B. 

20 Page 2-3 of November 25, 2014 letter from Thomas Livingston, APS, to Lisa Beckham, EPA. 

21 Attachments C.1(a) and (b) to APS’s 2014 Integrated Resource Plan provide detailed estimate of peak demand, separated by 

month and customer class for the period 2014-29. These estimates are calculated on a system-wide basis. 
FCPP SCR Project 

Response to Comments 

Page 51 of 109 

APS does not need to increase electricity generation at Units 4 and 5 to make up for a loss of MW from 

shutting down Units 4 and 5. The retirement of Units 1-3 represents the loss of 560 MW of generating 

capacity to APS’s portfolio. The commenter asserts that it is reasonable to assume that the increase in 

capacity factor for Units 4 and 5 from 74.7% (the capacity factor for the baseline period) to 89.35% (APS’s 

projected capacity factor) is occurring to offset the loss of Units 1-3. Victoria Stamper comment letter at p. 9. 

This contention does not consider several relevant facts. First, several companies owned an interest in the 

power produced at FCPP, as summarized below. 22 

Table 4 Summary of Four Corners Power Plant Ownership (2010)

 Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 

Capacity (MW) 170 170 220 750 750 

Company Ownership Stake (%) Ownership Stake (%) 

Arizona Public Service (APS) 100% 15% 

Southern California Edison (SCE) 0% 48% 

Public Service of New Mexico (PNM) 0% 13% 

Salt River Project (SRP) 0% 10% 

El Paso Electric Company 0% 7% 

Tucson Electric Power (TEP) 0% 7% 

Total 100% 100% 

Therefore, the demand for these units will be based, in part, on the demand needed by the individual owners. 

The commenter omits, however, that SCE was required to sell its 48% ownership interest in Units 4 and 5 in 

order to comply with California state law prohibiting importation of coal-fired electricity generation. That is, 

SCE had no future demand in the power produced at FCPP, and absent another party purchasing SCE’s stake in 

Units 4-5, a substantial portion of Unit 4 and 5 capacity would be unused since SCE would no longer demand 

its share of these units’ generated electricity. By purchasing SCE’s stake in Units 4-5, APS increased its 

electricity generating capacity in Units 4 and 5 at FCPP by 48%. APS’s purchase of SCE’s stake in Units 4-5 was 

more than sufficient to offset the retirement of Units 1-3. Specifically, the purchase increased APS’ 

generating capacity in FCPP by approximately 720 MW (48% x 1500 MW)23, while the retirement of Units 1-3 

reduced APS’s capacity by 560 MW. APS is offsetting the loss of Units 1-3 by using the existing capacity of 

Units 4 and 5 that was previously being used by SCE. Therefore, the shutdown of Units 1-3 is unrelated to the 

increase in demand for Units 4 and 5, because APS does not need to increase the operation of Units 4 and 5 

from 74.70% to 89.35% to offset the loss of generating capacity from Units 1 – 3. APS accomplished this by 

purchasing SCE’s ownership stake in Units 4 and 5.24 

To further illustrate this point, a chart of capacity factor (2010-14) for Units 1-3 and 4-5 has been included in 

Chart 1.25 Historically, there has been no consistent correlation between the operation of the units. There are 

periods of time where Units 1-3 are utilized differently than units 4-5 (such as early 2010 and portions of 2013, 

where increases in 1-3 capacity correspond to decreases in 4-5), as well as periods of time where all five units 

 

22 Per FCPP Source Specific Federal Implementation Plan for BART, Proposed Rule, Technical Support Document, page 10 of 92. 

23 By purchasing SCE’s 48% stake in Units 4-5, APS expanded its ownership stake of Units 4-5 from 15% to 63% for a total generating 

capacity of 945 MW. 

24 Per APS’s 12/31/2013 website announcement 

25 Based on AMPD gross load data contained in spreadsheet “FCPP 1-5 Gross Load (from AMPD).xlsx” 
FCPP SCR Project 

Response to Comments 

Page 52 of 109 

experience similar utilization patterns (such as from mid-2011 to the end of 2012). Most importantly, 

operating data available for Units 4-5 from January to September 2014 indicate that, following the shutdown 

of Units 1-3 on December 31, 2013, the utilization of Units 4-5 have not changed substantially, and remain 

below historical averages. 

Chart 1 Comparison of Capacity Factors

In summary, the issue here is whether the modification under review (installation of SCR) caused the growth 

in demand. The commenter has not provided any information demonstrating there is a causal relationship 

between the growth in demand at Units 4 and 5 and installation of SCR to reduce NOX emissions to comply 

with the requirements of the BART FIP. 

Annual Heat Input Calculation and Economizer Bypass

Comment 30:

(Commenters: Stamper Report) 

The comment letter and “expert report” further commented as excerpted below. 

APS and EPA have understated the increase in annual heat input that it projected is due to the installation of 

the pollution controls being installed at FCPP Units 4 and 5.APS did include projected heat input increases at 

FCPP Units 4 and 5 to reflect the parasitic load and the reduced boiler efficiency due to economizer bypass 

operations as related to the SCR systems. Specifically, APS assumed that the FCPP Units 4 and 5 would 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Jan-10 Jan-11 Jan-12 Jan-13 Jan-14

Capacity Factor (gross load), Units 1-3 vs Units 4-5

Unit 1-3 Unit 4-5
FCPP SCR Project 

Response to Comments 

Page 53 of 109 

increase heat input by 0.3% annually due to these load demands of the SCR system. APS claimed this would 

require only a heat input increase of 348,038 MMBtu/year. 

With respect to the increase in heat input necessary to deal with the boiler efficiency losses due to 

economizer bypass, APS presented an analysis based on operations during 2012 and 2013 of the hours where 

the temperature increase of the flue gas would be required due to economizer bypass and the resulting boiler 

efficiency losses. As the Economizer Bypass table demonstrates, APS’s projected heat input increase varies 

greatly from 124,937 to 38,394 MMBtu/year depending on the year. That is a significant variation, and the 

maximum projected heat input increase is three times as much as the lowest projected heat input increase. 

From this analysis of 2012 and 2013 data, APS projected an increase in MMBtu/yr of 0.147% due to the 

economizer bypass. 

It is not clear why APS used 2012 and 2013 data to estimate the percent increase in boiler heat input 

associated with the boiler efficiency losses due to economizer bypass, but then apparently applied the 0.147% 

increase to the average heat input during the 2011-2012 baseline. This is not an apples-to-apples comparison. 

Further, it does not reflect future operations of FCPP Units 4 and 5. Given that projected actual emissions are 

to be based on the maximum annual rates in the 5-10 years following the project, EPA must require that APS 

evaluate the increase in boiler heat input due to boiler efficiency losses with the economizer bypass that is 

associated with the maximum annual emissions rate post-change. 

For the purpose of the evaluation presented in this report, the average heat input increase per unit that listed 

in Table A-9 of the April 2014 PSD Permit Application was used of 75,151 MMBtu/year. Based on the data 

available in the application, it makes more sense to use APS’s average heat input increase of 

75,151 MMBtu/year to account for increased heat input due to economizer bypass, rather than apply the 

average percent increase in heat input due to economizer bypass that was based on 2012 and 2013 data to 

the 2011-2012 average heat input as APS did in their applicability analysis. However, EPA should request that 

APS provide an analysis of maximum projected increase in heat input in future years due to the economizer 

bypass as part of its projected actual emission calculation. 

Response 30: 

A description of the purpose of the economizer bypass may be useful in responding to the concerns raised by 

the commenter. APS included a description on page 2-3 of the April 2014 PSD permit application. To 

summarize, the SCR system requires the entering exhaust gas stream to be above a certain minimum 

temperature (typically between 600° and 650° F) in order to ensure proper operation. Exhaust gas from the 

boiler passes through a device called an economizer before then entering the SCR. The economizer’s purpose 

is to draw heat away from the hot boiler exhaust gases to heat water or other process streams for use 

elsewhere in the plant. Because even baseload units will operate at varying loads, there are times when the 

combination of lower load operation and the temperature-reducing effect of the economizer may cause the 

exhaust gas entering the SCR to fall below the minimum operating temperature. In order to ensure proper 

operation of the SCR, varying amounts of hot boiler exhaust gas will be bypassed around the economizer to 

ensure that the exhaust gas entering the SCR is above the minimum operating temperature. Because the 

amount of bypassed gas would have served a purpose elsewhere in the plant, this loss must be compensated 

for by slightly increased boiler operation. This increased load which is also referred to as “parasitic load”, and 

the emissions associated with it, is therefore attributable to the installation and operation of the SCR system. 
FCPP SCR Project 

Response to Comments 

Page 54 of 109 

APS estimated the annual emissions attributable to the economizer bypass by analyzing historical operating 

temperatures to estimate the associated increase in capacity factor needed to offset the parasitic load from 

economizer bypass, and then applied that increase to projected annual heat input (116,356,289 MMBtu/hr).26

Specifically, APS first examined historical operations in 2012-13 to determine what fraction of operating hours 

would require economizer bypass had an SCR system been in place. APS then calculated the amount of 

additional heat input (MMBtu/yr) that would have been needed for each unit in both 2012 and 2013 to offset 

the estimated economizer bypass. As a result of the variations in the actual operational load levels, the 

estimated additional heat duty also varied between Units 4 and 5, and between 2012 and 2013. APS then 

expressed the MMBtu/yr value estimated for each unit and each year as a percent of overall heat input. These 

values were averaged together to develop a single percentage value attributable to economizer bypass (APS 

estimated this value to be 0.147%). APS then projected this percentage, 0.147%, onto future projected heat 

rate to determine the amount of projected actual emissions attributable to the economizer bypass. 

The commenter has alleged certain deficiencies with this approach, with which we disagree. First, the 

commenter alleges that it was inappropriate for APS to use calendar year 2012-13 as a basis for determining 

the number of operating hours that would require economizer bypass, because the derived value was applied 

to the baseline period of 2011-12. We find this element of the commenter’s allegation unsupported. Although 

the commenter states this is not an ‘apples-to-apples’ comparison, the commenter does not actually provide a 

specific basis for why the comparison is inappropriate, such as providing information showing the data from 

2012-2013 was deficient or unrepresentative in some fashion. As described earlier at the beginning of this 

response, because economizer bypass is required during periods of reduced load, economizer bypass 

estimates will be higher during years with the greatest amount of reduced load operation. APS confirmed that 

that although the application otherwise relies on 2011 through 2012 operating data, the 2011 temperature 

data needed for this analysis was not representative due to a faulty thermocouple.27 In addition, 2013 data is 

more conservative because it was for a year with lower than typical load.28 We therefore consider APS’s use of 

this two-year period for calculating economizer bypass reasonable. We note that the PSD definition of 

‘projected actual emissions’ at 52.21(b)(41) indicates that historical operating data may be a source of 

information used to inform the calculation of projected actual emissions, but does not restrict the use of 

historical data in this context to the data that is available within the chosen 24-month baseline period. 

Second, the commenter alleges that this methodology does not reflect future operations, and that EPA must 

require APS to evaluate economizer bypass-related boiler losses associated with the projected, post-change, 

annual emission rate. It is unclear to us what issue or deficiency the commenter is raising. Regarding the 

allegation that this methodology does not reflect future operations, we note that the percentage of capacity 

factor developed by APS (0.147%) was not applied to the baseline period of calendar year 2011-2012 as 

asserted by the commenter, but was applied to the post-project estimate of annual heat input (116,008,265 

MMBtu/yr), which represents future operations.29 We consider the use of projected heat input to be an 

 

26 Per Table A-9 of the April 2014 PSD Permit Application 

27 See memo to the file regarding Justification for Using 2012-2013 Data for Economizer Bypass Calculations, Table A-9 of the 

Application, from Lisa Beckham, EPA, December 17, 2014. 

28 Id. 

29 See Table A-3, April 2014 PSD permit application. Line item labeled “Increased Power Demand due to New Emission Controls” is 

calculated based on projected heat input and 0.30%, which includes the 0.147% attributable to economizer bypass. 
FCPP SCR Project 

Response to Comments 

Page 55 of 109 

acceptable methodology for calculating the projected actual emissions attributable to the economizer bypass. 

It is possible that the commenter disagrees with the use of historical data in developing the percent of 

capacity factor (0.147%). However, detailed operating data is necessary to determine which periods of 

operation will trigger the need for economizer bypass. Such detailed operating data is only available for 

historical operations. Estimates of future operation are limited to estimates of annual capacity factors, which 

do not provide sufficient detail to accurately predict economizer bypass needs. Therefore, the emissions 

associated with the economizer by pass were correctly estimated. 

Increase in Annual Heat Input and SCR Parasitic Loss

Comment 31:

(Commenters: SJCA, Stamper Report) 

The comment letter and “expert report” also contend that EPA underestimated the increase in annual heat 

input due to the SCR parasitic loss as excerpted below. 

As noted in the preceding comment, APS and EPA have understated the increase in annual heat input that it 

projected is due to the installation of the pollution controls being installed at FCPP Units 4 and 5. APS assumed 

that the FCPP Units 4 and 5 would increase heat input by 0.3% annually due to these load demands of the SCR 

system (0.142% due to SCR parasitic load, 0.147% due to economizer bypass). 

The power demands of an SCR system are due to the increased pressure drop across the SCR, which is 

dependent on the catalyst configuration and also on the specifics regarding the retrofit of the SCR, the power 

necessary for soot blowing to reduce pressure drop across the SCR, and the power necessary for the ammonia 

injection system which can vary based on the source of ammonia and type of injection system. Further, an 

increase in heat input is expected to maintain MW output needs due to boiler efficiency losses associated with 

operation of the economizer bypass. 

Some of the details of how APS calculated the 0.3% increase in annual heat input are provided in Table A-9 of 

Appendix A to APS’s April 2014 PSD Permit Application. First, APS projected the heat input increase from the 

parasitic load due to the SCR. Specifically, APS indicated a 3.8 MW parasitic load due to SCR, based on Black & 

Veatch information. This is equivalent to 0.47% of the APS’s stated 810 MW gross capacity of each FCPP Units 

4 and 5. According to APS’s PSD permit application, APS only accounted for the increased fuel use due to the 

3.8 MW parasitic load “during periods when [FCPP Units 4 and 5] are operating at reduced load. When 

operating at full load, the fuel use cannot be increased; the net power output will decrease.” 

It is true that the hours a unit operates at maximum full power output, the parasitic load would result in 

reduced net power output and no additional fuel burned. But when the units are operating at less than 

maximum full power output, then the units could be operated at higher output with higher heat input to 

provide the power necessary for the SCR operation. 

APS apparently projected the number of hours per year that FCPP Units 4 and 5 would operate at reduced 

load based on the projected highest future capacity factor of 92.8% and 85.8% for FCPP Units 4 and 5, 

respectively, then reduced the 0.47% parasitic load percentage by the percent of hours out of a year that each 

FCPP Units 4 and 5 purportedly would operate at reduced load in 2021 to come up with a “parasitic load 

capacity factor” for each unit. Based on this approach, APS projected an average parasitic load of 0.142%. 
FCPP SCR Project 

Response to Comments 

Page 56 of 109 

There are several problems with APS’s methodology to projecting the increase in parasitic load due to the SCR. 

First, as stated above, for any hours lower than maximum full power operation, there would be capacity for 

the unit to be operated more, with the burning of more fuel, to provide the power necessary for the SCR 

system. APS states that could only occur during “reduced load” but APS did not define what that “reduced 

load” level is. 

Further, it appears that APS projected the hours that each unit would be at “reduced load” in 2021 taking into 

account its projected increases in capacity factor at each unit. APS’s projected increases in capacity factor in 

future years likely include an increase in the number of hours that each unit is operating at full power output. 

Although it makes sense to project future parasitic load using future projected capacity factors, it is not 

appropriate to discount the future projected parasitic load by the number of hours in the future that the units 

will be operated at maximum full output. Since applicability under the PSD program is based on a comparison 

of future projected emissions to baseline actual emissions, APS should have instead evaluated the hours 

during the 2011-2012 baseline period that the units could not have provided the SCR parasitic load needs (due 

to operation during the baseline period at maximum full power output) and excluded those hours from the 

projection of heat input necessary to address the parasitic load of the SCR in the post-project projected actual 

emissions calculations. The heat input necessary to provide the necessary 3.8 MW/hr of parasitic load above 

how the units operated during the period of baseline actual emissions must be considered as attributable to 

the SCR systems. This is best explained by going through the calculations: 

APS identifies the gross load of each FCPP Units 4 and 5 as 810 MW. See April 2014 PSD Permit Application, 

Appendix A, Table A-9. Gross load is reported on an hourly basis to EPA’s CAMD. For this analysis presented in 

this report, the hourly gross load and other emissions data for FCPP Units 4 and 5 were compiled for the 2011 

through 2012 baseline period. Contrary to APS’s stated gross load of 810 MW, the maximum gross load 

reported for Four Corners Unit 4 was 819 MW in 2012 and in fact, over the two baseline years, 3200 hours of 

gross load reported to CAMD for the unit were over 810 MW10. It is very likely that the generating capacity of 

the FCPP units has increased in recent years, because it appears that the company has completed high 

pressure turbine upgrades at both Units 4 and 5. The maximum gross load reported for FCPP Unit 5 was 811 

MW, slightly higher than APS’s stated 810 MW gross capacity. 

Because the full power gross load for Unit 4 was 819 MW in the baseline period, any gross loads lower than 

819 MW in the baseline period means that the unit could have increased generation and heat input to account 

for at least some of the parasitic load from the SCR. And any hourly gross loads lower than the difference 

between 819 MW and 3.8 MW - or 815.2 MW - in the baseline period means the unit could have increased 

generation and heat input to account for all of the parasitic load of the SCR during that hour. On average 

during the 2011 to 2012 baseline period, FCPP Unit 4 operated 688 hours per year at 815 MW or higher. This 

means that during the baseline period, the unit could have fully provided for the 3.8 MW parasitic load for all 

operating hours with the exception of 688 hours. On average during the baseline period, FCPP Unit 4 operated 

for 7,511 hours per year, so this means for 6,823 hours per year, the unit could have increased power output 

to provide for the full 3.8 MW parasitic load of the SCR. Yet, APS assumed the unit could only increase power 

output to address the SCR parasitic load for 1,195 hours per year. 
FCPP SCR Project 

Response to Comments 

Page 57 of 109 

Because the full power output of FCPP Unit 5 was 811 MW during the baseline period, any hourly gross loads 

lower than 811 MW in the baseline period means that the unit could have increased generation and heat 

input to account for at least some of the 3.8 MW parasitic load from the SCR. And any gross loads lower than 

the difference between 811 MW and 3.8 MW - or 807.2 MW - in the baseline period means the unit could 

have increased generation and heat input to account for all of the parasitic load of the SCR during that period. 

On average during the 2011 to 2012 baseline period, FCPP Unit 5 operated 520 hours per year at 807 MW or 

higher. This means that during the baseline period, the unit could have fully provided for the 3.8 MW parasitic 

load for all operating hours with the exception of 520 hours. On average during the baseline period, FCPP Unit 

4 operated for 7,259 hours per year, so this means for 6,739 hours per year, the unit could have increased 

power output to provide for the full 3.8 MW parasitic load of the SCR. Yet, APS assumed the unit could only 

increase power output to address the SCR parasitic load for 4,112 hours per year. See April 2014 PSD Permit 

Application at Table A-9. Clearly, APS has underestimated the increase in heat input due to parasitic load of 

the SCR in comparison to baseline emissions and operations. 

In projecting future actual emissions, APS has projected an increase in the load growth of the unit to a capacity 

factor of 92.85% for Unit 4 and to 85.85% for Unit 5 in the year 2021, for a Unit 4-5 average of 89.35%. See 

April 2014 PSD Permit Application, Appendix A, Table A-8. In contrast, the baseline actual emissions 

calculations were equivalent to an annual capacity factor of 74.9%. See EPA Fact Sheet at 12. This increased 

capacity factor needs to be taken into account in projecting future emissions post-project due to the SCR 

parasitic load, but one should first assume that the first 3.8 MW increase in hourly load is due to parasitic load 

of the SCR and thus needs to be considered as directly attributable to the SCR. 

To project the increase in heat input due to the parasitic load of the SCR above the parasitic load needs that 

each unit could have provided for in the baseline period, I took the following steps: 

1) Using the projected capacity factors, I calculated the gross MW-hrs needed to address the parasitic load of 

the SCRs at each FCPP Unit 4 and Unit 5 as follows: 3.8MW x 8,760 hours/yr x 2021 Projected Capacity Factor 

for Each Unit = 30,908 MW-hrs for Unit 4 and 28,578 MW-hrs for Unit 5. 

2) Next, the heat input associated with the parasitic load was calculated based on this gross load due to the 

parasitic load of the SCR at each unit and based on APS’s stated heat rate of each unit of 9,800 Btu/kW-hr. See 

April 2014 PSD Permit Application, Appendix A at Table A-8. This equates to the annual heat input necessary to 

provide the 3.8 MW parasitic load of the SCR at APS’s 2021 projected capacity factors to 302,897 MMBtu/year 

for FCPP Unit 4 and 280,062 MMBtu/hr for FCPP Unit 5. 

3) I determined the heat input associated with the average hours per year during the baseline period that the 

units could not have provided the full 3.7 MW per hour necessary to operate the SCR. I then subtracted the 

heat input associated with the SCR parasitic load that the units could not have provided during the baseline 

period, and the difference reflects the annual increase in heat input due to the parasitic load of the SCR that 

FCPP Units 4 and 5 could provide to power the SCR per the methodology used by APS. In other words, I have 

projected the future increase in heat input above the limitations on increases in hourly load that were present 

during the baseline operating conditions of each unit to reflect the heat input increase due to the parasitic 

load of the SCR at FCPP Units 4 and 5. The results of this analysis are show in Table 3 (see Stamper Report). 
FCPP SCR Project 

Response to Comments 

Page 58 of 109 

Thus, based on APS’s methodology modified to more accurately project heat input increases associated with 

the SCR systems to be installed, APS should have projected the annual heat input increases included in Table 4 

of the Stamper Report at each FCPP Units 4 and 5 with the addition of SCR due to the parasitic load and 

economizer bypass. This corrected total heat input increase of 688,275 MMBtu/year that should have been 

projected as associated with the SCRs at FCPP Units 4 and 5 is approximately twice as high as the 348,025 

MMBtu/Year projected heat input increase associated with the SCR as projected by APS. 

As a check on the increase in heat input associated with the parasitic load of the SCR systems at FCPP Units 4 

and 5 shown in Table 4 above, I used an alternative source of information. Sargent & Lundy have developed an 

SCR cost module that was used by EPA in estimating SCR costs in analyses conducted for the Cross State Air 

Pollution Rule using the Integrated Planning Module. The Sargent & Lundy documentation includes a formula 

to estimate the auxiliary power requirements of an SCR system that includes increased fan power to overcome 

the added pressure drop across the SCR catalyst and ductwork and also the power needs of the reagent supply 

system. Specifically, Sargent & Lundy’s auxiliary power formula for the parasitic load of the SCR system is as 

follows: 0.56*([Coal Factor of 1.0 for Bituminous, or 1.05 for PRB] * [Heat Rate/10000])^0.43. Applying this to 

FCPP Units 4 and 5, I calculated the percent increase in auxiliary power associated with the parasitic load of 

SCR at FCPP Units 4 and 5 as follows: 0.56 * [1.0 * (9800 Btu/kW-hr/10000)]^0.43 = 0.555%. 

This means, using the Sargent & Lundy IPM SCR Cost Module, that 0.555% of the MW-hrs generated by each 

FCPP Units 4 and 5 would need to go to the parasitic load of the SCR system at the units. 

As previously stated, APS has estimated a maximum post change capacity factor of 89.35% on average for 

Units 4 and 5. See April 2014 PSD Permit Application at 5-1. Assuming a gross capacity of each unit of 810 MW 

as stated by APS, which means each unit is projected to generate 6,339,918.6 MW-hrs per year post-post 

project, and 0.555% of this, or 35,186.5 MW-hrs per year, would have to go to the parasitic load of the SCR 

system according to the Sargent & Lundy equation. Given the 9,800 Btu/kW-hr heat rate for each unit, which 

means the heat input associated with this SCR parasitic load would be 344,828 MMBtu/yr or 689,655 

MMBtu/year for both units together. This is very similar to the calculations presented in Table 4 of the 

Stamper Report, and yet the Sargent & Lundy equation does not purport to account for boiler efficiency losses 

due to economizer bypass. Admittedly, this calculation also does not account for the 6-8% of hours per year 

that FCPP Units 4 and 5 could not provide any additional power to address the parasitic load of the SCR system 

during the baseline period (see Table 3 in the Stamper Report). 

However, it must be noted that the calculated parasitic load due to the SCR system using the Sargent & Lundy 

of 0.555% is greater than the 3.8 MW parasitic load provided by APS in Table A-9 of its April 2014 PSD permit 

application. EPA should thus request documentation from APS to verify APS’s claimed parasitic load due to 

SCR at FCPP Units 4 and 5. EPA should include such information in the administrative record for this permit 

proceeding and provide an opportunity for public comment on this analysis before making any final permitting 

decision. The PSD permit application for the FCPP project does not provide much detail on design of the SCR 

systems to be installed at FCPP Units 4 and 5, and in fact, APS provides a wide range of the pressure drop 

anticipated with the SCR system (i.e., “[d]epending on arrangement and performance requirements, draft 

losses can range from 6 to 12 inches of water gauge pressure,” April 2014 PSD Permit Application at 2-3). APS 

should be assuming a maximum parasitic load in projecting post-change emissions, and EPA should evaluate 

documentation provided by APS to verify a lower parasitic load than is commonly considered for SCR systems. 
FCPP SCR Project 

Response to Comments 

Page 59 of 109 

Response 31:

We note that the commenter’s and APS’ overall methodologies for calculating the emission increase 

attributable to SCR parasitic loss involve many similar elements. The primary factor between the two 

estimates that accounts for the discrepancy is the estimated number of hours for which SCR parasitic loss 

would result in increased boiler load vs. boiler derating.30 The commenter asserts that, based on historical 

data, Units 4 and 5 should have operated at increased boiler load for 6,823 and 6,739 hrs/yr, respectively. By 

contrast, APS’ estimate is based on 1,195 and 4,112 hrs/yr.31 The commenter asserts that, “it is not 

appropriate to discount the future projected parasitic load by the number of hours in the future that the units 

will be operated at maximum full output.” Instead the commenter claims, 

“Since applicability under the PSD program is based on a comparison of future projected emissions to 

baseline actual emissions, APS should have instead evaluated the hours during the 2011-2012 baseline 

period that the units could not have provided the SCR parasitic load needs (due to operation during the 

baseline period at maximum full power output) and excluded those hours from the projection of heat 

input necessary to address the parasitic load of the SCR in the post-project projected actual emissions 

calculations. “ 

The commenter provides no basis to support these claims. The commenter then uses this assertion to recalculate the hours at reduced load. The commenter tries to demonstrate that APS underestimated the hours 

units 4 and 5 will operate at reduced load, which in turn would demonstrate that APS underestimated the 

emissions increases associated with operating the SCR. After review of the comment, we find no basis to 

change our determination. We find it perfectly reasonable that APS based its projections of reduced load on 

the maximum projected capacity factor and projected operating loads. We can find no regulatory basis that 

demonstrates this to be in error. In addition, APS provided the following clarification32: 

“APS estimated the increased fuel use due to parasitic load of operating the SCR and the economizer 

bypass by estimating the hours of operation at reduced load. APS used the projected hourly data 

created by the RTSIM cost production model and assumed all operating hours less than 90% load were 

at reduced load. 

The selection of 90% of full load as a cut-off for low load operation was set based on the assumption 

that the APS Marketing Department would not de-rate the units if they were operating at or above this 

level.” 

The commenter also took issue with other aspects of APS’ calculation. The commenter states that based on 

information from EPA’s APMD, Units 4 and 5 have operated above the 810 MW gross capacity identified for 

 

30 As noted by the commenter and APS, periods in which the SCR parasitic load is accounted for by increased boiler load result in 

additional emissions. Periods in which the boiler is at or near full load would not result in additional emissions, as the boiler would 

instead use power it would otherwise sell to the grid to account for the SCR parasitic load. 

31 By comparison, using the commenter’s calculation methodology, but substituting APS’s estimate of increased boiler load (hrs/yr), 

results in SCR parasitic loss estimate of approximately 125,000 MMBtu/yr, which is comparable to (and lower than) APS’s estimate 

of 172,000 MMBtu/yr. 

32 See November 25, 2014 letter from Thomas H. Livingston, FCPP to Lisa Beckham, EPA, “Four Corners Power Plant SCR Retrofit 

Project – Addendum to Application for PSD Permit, at 4-5. 
FCPP SCR Project 

Response to Comments 

Page 60 of 109 

each unit in the application. The commenter then asserts that these higher values should be used for 

determining whether the units were operating at reduced load. However, the commenter elsewhere has 

confirmed that the units have not exceeded the title V potential hourly maximum heat input rates listed in 

FCPP’s title V permit. APS provided the following explanation33: 

“[T]he effect of reactive load on MW output is something that could make it appear that a unit is 

running at more or less than full load when it is actually running at full load. This is the cause for some 

instances when a unit appeared to be running higher than it was capable of. At the same actual total 

real power production (MVA) and heat input (MMBtu), it is possible to get different useful power 

production (MW) depending on the reactive load (MVAR). In other words, at the same fuel burn and 

actual turbine output, different MW’s can be reported. Usually the difference is less than 2 MW, but it 

can be as high as 15 MW. That is one reason a nominal full load MW can produce different numbers 

over the course of a year, but still actually be full load. It varies due to factors outside the unit. The 

type of load that the grid is putting on the unit affects how much of the produced power appears as 

useful MW’s.” 

This is a reasonable explanation and EPA agrees with it. 

The commenter also takes issue with APS’ estimate that the SCR parasitic load would be 3.8 MW, contending 

it is too low. The commenter used the IPM cost estimating component to calculate a SCR parasitic load of 4.5 

MW. The IPM cost estimate methodology is based upon two databases of actual SCR projects from 2004 and 

2006.34 Because it is relatively recent information, and is based on actual SCR construction projects, we 

consider the IPM cost component to be a useful resource, especially in comparison to older and more generic 

sources of information. In this instance, however, an engineering design firm specifically contracted to assist in 

the design and construction of a site-specific SCR system provided the SCR parasitic load estimate for Units 4 

and 5. The design work being performed is not part of a broader, higher level-study for purposes of initial cost 

estimation or project scoping, but is part of the effort to design the actual site-specific SCR systems for which 

construction is planned to commence in approximately 8 months. As a result, we find discrepancies between 

APS’s estimate and the IPM estimate of SCR parasitic load acceptable, and consider the estimate from APS’s 

engineering contractor to be more representative of the site-specific needs of Units 4 and 5. The commenter 

has not provided any information to demonstrate that the estimate by APS’s engineering contractor is 

incorrect. Therefore, we continue to support the calculation submitted by APS of a parasitic load of 3.8 MW 

based on increased boiler loads of 1,195 and 4,112 hrs/yr. 

 

Increases in Annual Heat Input and Operation of Sorbent Injection System

Comment 32:

(Commenters: SJCA, Stamper Report) 

 

33 Id. 

34As noted in the documentation for IPM’s cost development methodology for SCR, these databases include 2004 and 2006 industry 

cost estimates prepared for the Midwestern Ozone Group (MOG), and a proprietary in-house database maintained by engineering 

firm Sargent & Lundy (S&L). The MOG information was cross-referenced with actual 2009 projects, and escalated accordingly. The 

information in these databases was then used to develop the equations described in the IPM component, taking into account the 

pre-control NOX emission level, degree of reduction, coal type, facility size, and numerous other factors 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Appendix52A.pdf
FCPP SCR Project 

Response to Comments 

Page 61 of 109 

The comment letter and “expert report” further argue that APS did not include any increases in annual heat 

input due to operation of the sorbent injection system, as excerpted below. 

APS did not include any increases in annual heat input due to the parasitic load of the sorbent injection 

system. Some of the additional power requirements for a sorbent injection system include the power required 

by the injection system air blowers and the drying equipment for transport air. Further, there may be 

additional power needs due to increased pressure drop across the baghouse at each FCPP Unit 4 and 5. With 

the choice of sorbent being hydrated lime, the sorbent injection rate will be higher than if trona or sodium 

bicarbonate were used, potentially twice as high. It is not clear what the impacts of hydrated lime injection 

will be on pressure drop across the baghouse at FCPP Units 4 and 5, but presumably there could be some 

increase in pressure drop and a resulting increase in power needs. 

In EPA’s example DSI costs prepared for the EPA’s Final Transport Rule, EPA identified the heat rate penalty 

due to DSI at a unit with a baghouse as 0.65%. The EPA’s example was for modeled assumptions that DSI was 

being used for SO2 control, and not H2SO4 control as is the case with Four Corners Units 4 and 5. Thus, the 

example heat rate penalty with DSI may not be quite as high as shown by EPA in the example cited here. 

None-the-less, there will be some parasitic load associated with the dry sorbent injection system at FCPP 

Units 4 and 5. EPA must require APS to quantify that parasitic load and project the annual heat input increase 

due to the DSI systems to be installed at Units 4 and 5. EPA should make this information part of the 

administrative record and allow for public comment before making a final permitting decision. 

Response 32: 

We agree that the projected actual emission calculations did not include an estimate of DSI system parasitic 

loss. APS estimates the parasitic loss of the DSI systems to be 0.024% (determined by subtracting 0.303% from 

0.289%).35 We requested APS to provide additional information on this issue and we have added that 

information to the administrative record as allowed by 40 CFR 124.17(b). Below in Tables 3 through 7, we 

present our revised PSD applicability emission calculations. For this revised analysis we simply revised the 

tables originally used in the Fact Sheet (See Tables 1-5 of the Fact Sheet) and highlighted where this change 

resulted in very minor changes to our analysis. In many cases, the small increase in fuel use from the DSI 

systems did not result any statistically relevant changes to our analysis; that is, the Projected Actual Emissions 

remained the same. The revised calculations do not result in any changes to how the PSD program applies to 

the FCPP SCR Project. 

In addition, in Tables 8 through 10, we also recalculated our emissions analysis for the tribal minor NSR 

program (previously presented as Tables 11-13 of the Fact Sheet). Again, this small increase in fuel use for the 

DSI system parasitic loss did not change our determination. 

 

35 See November 25, 2014 letter from Thomas H. Livingston, FCPP to Lisa Beckham, EPA, “Four Corners Power Plant SCR Retrofit 

Project – Addendum to Application for PSD Permit, at 3-4. Note that APS previously used a conservative 0.3% parasitic load in its 

calculations even though the sum of the increases from SCR parasitic load and economizer bypass was only 0.289%. In our revised 

calculations we have carried on this conservatism resulting in a 0.324% increase in fuel use. 
Table 3 Baseline Actual Emissions for FCPP SCR Project

Emission Unit NOX SO2 PM PM10 PM2.5 CO VOC H2SO4 Lead GHGs (CO2e) 

Units 4 and 5 24,029 8,373 644 801 550 1,444 5.79 14.1 0.115 10,058,133 

Truck Traffic, Delivery Dry Sorbent 0 0 0 0 0 0 0 0 0 0 

Truck Traffic, Delivery of SCR 

reagent 

0 0 0 0 0 0 0 0 0 0 

Silo for Dry Sorbent Storage 0 0 0 0 0 0 0 0 0 0 

Silo for SCR Reagent Storage 0 0 0 0 0 0 0 0 0 0 

Total Baseline Actual Emissions 24,029 8,373 644 801 550 1,444 5.79 14.1 0.115 10,058,133

Table 4 Projected Actual Emissions for FCPP SCR Project

Emission Unit NOX SO2 PM PM10 PM2.5 CO VOC H2SO4 Lead GHGs (CO2e) 

Units 4 and 5 4,784 8405 647 1,134 843 1,449 5.81 250.7 0.115 10,096,547 

Truck Traffic, Delivery Dry Sorbent 0.0 0.0 0.095 0.019 0.005 0.0 0.0 0.0 0.0 0.0 

Truck Traffic, Delivery of SCR 

reagent 

0.0 0.0 0.087 0.017 0.004 0.0 0.0 0.0 0.0 0.0 

Silo for Dry Sorbent Storage 0.0 0.0 0.086 0.086 0.086 0.0 0.0 0.0 0.0 0.0 

Silo for SCR Reagent Storage 0.0 0.0 0.214 0.214 0.214 0.0 0.0 0.0 0.0 0.0 

Total Projected Actual Emissions 4,783 8,403 647 1,134 843 1,449 5.81 251 0.115 10,094,124

Table 5 Summary of Emissions Increases from the FCPP SCR Project

Emission Increases from the Project NOX SO2 PM PM10 PM2.5 CO VOC H2SO4 Lead GHGs (CO2e) 

Total Baseline Actual Emissions 24,029 8,373 644 801 550 1,444 5.79 14.1 0.115 10,058,126

Total Projected Actual Emissions 4,784 8,403 647 1,134 843 1,449 5.81 250.7 0.115 10,096,547

Emission Increases -19,244 30 3 333 293 5 0.02 237 0 38,421

Significant Emission Rate36 40 40 25 15 10 100 40 7 0.6 75,00037

Significant Emission Increase No No No Yes Yes No No Yes No No

 

36 See 40 CFR 52.21(b)(23) 

37 For an existing major stationary source undergoing a modification such as this, PSD permitting for GHGs will occur only when the project would also cause a net increase in 

GHG emissions of 75,000 tpy or more on a CO2e basis and greater than 0 tpy on a mass basis. See 40 CFR 52.21(b)(23) and (49)(iv); PSD and Title V Permitting Guidance for 

Greenhouse Gases (March 2011) at 13-15. 
Table 6 Emission Factors for Determining Projected Actual Emissions, Units 4 and 5

Pollutant Emission Factor Basis 

NOX 0.098 lb/MMBtu 40 CFR 49.5512(i)(3) BART FIP, 30-day rolling average 

SO2 0.1722 lb/MMBtu Combined average emission rate from baseline actual emissions 

PM 0.0132 lb/MMBtu Combined average emission rate from baseline actual emissions 

PM10 0.0222 lb/MMBtu 

92% of filterable PM BART limit (0.015 lb/MMBtu), 0.0040 lb/MMBtu 

for condensable PM38, 0.00435 lb/MMBtu proposed H2SO4 BACT limit 

PM2.5 0.0163 lb/MMBtu 

53% of filterable PM BART limit (0.015 lb/MMBtu), plus 0.0040 

lb/MMBtu for condensable PM39, plus 0.00435 lb/MMBtu 

proposed H2SO4 BACT limit 

CO 0.02969 lb/MMBtu Combined average emission rate from baseline actual emissions 

VOC 

0.000119 

lb/MMBtu Combined average emission rate from baseline actual emissions40

H2SO4 0.00435 lb/MMBtu Proposed BACT limit 

Lead 

2.36E-06 

lb/MMBtu Combined average emission rate from baseline actual emissions41

CO2e 206.8 lb/MMBtu Combined average emission rate from baseline actual emissions 

Table 7 Determining Projected Actual Emissions, Future Annual Heat Input, Units 4 and 5 Combined

Projected Heat Input, Excluding Demand Growth 

Hourly maximum heat input42 (MMBtu/hr) 14,822

Annual maximum heat input (MMBtu/yr) 129,840,720

Baseline heat input43 (MMBtu/yr) 97,258,307

Future expected maximum annual capacity factor, without Projectrelated increases 89.35%

Future expected maximum annual heat input, w/o Project-related 

increases (MMBtu/yr) 116,012,683

Project related increases in fuel use from SCR44, percentage of annual 

heat input 0.324%

Increase in annual heat input caused by Project-related increase in fuel 

(MMBtu/yr) 375,881

Heat input for determining projected actual emissions, MMBtu/yr 

(baseline heat input + Project-related increases) 97,634,188

 

38 See Table A-1.1 – Monthly Baseline Emissions – in the Application. PM10 organics assumed to be 20% of 0.02 lb/MMBtu, AP-42 

Table 1.1-5. 

39 See Table A-1.1 – Monthly Baseline Emissions – in the Application. PM2.5 organics assumed to be 20% of 0.02 lb/MMBtu, AP-42 

Table 1.1-5. 

40 The Applicant used an emission factor from the EPRI Emission Factor Handbook. This is not a readily available document and was 

not included in the Application. Nevertheless, we re-calculated the PSD applicability analysis using higher emission from AP-42 – 0.06 

lb/ton and this did not change the overall conclusion. This is expected, as the Project does not affect VOC emissions other than the 

0.3% increase in fuel use. 

41 The Applicant used an emission factor from the EPRI Emission Factor Handbook. We re-calculated the PSD applicability analysis 

using a higher emission in AP-42 – 0.000507 lb/ton – and this did not change the overall conclusion. This is expected, as the Project 

does not affect VOC emissions other than the 0.3% increase in fuel use. 

42 Both units combined, expected maximum 24-hour average, see footnote 1, Page 4-1, of the Application. 

43 Determined from the baseline actual emissions calculations using AMPD data for the January 2011 through December 2012 

period. 

44 See Table A-9 – Estimated Increased Fuel Use due to SCR Parasitic Load and Economize Bypass, Application. 
FCPP SCR Project 

Response to Comments 

Page 64 of 109 

Table 8 Actual-to-Projected Actual Emissions from the Project

Emission Increases from the

Project NOX SO2 PM PM10 PM2.5 CO VOC Lead

Total Baseline Actual Emissions 24,029 8,373 644 801 550 1,444 5.79 0.115 

Total Projected Actual Emissions 4,784 8,403 647 1,134 843 1,449 5.81 0.115 

Emission Increases -19,244 30 3 333 293 5 0.02 0 

Tribal Minor NSR Thresholds 10 10 10 5 3 10 10 0.1 

Above Thresholds? No Yes No Yes Yes No No No 

Table 9 Contemporaneous Emission Increases and Decreases

Emission Unit PM10 PM2.5 SO2

Units 1-3 -551.5 -421.8 -3,110.1 

Limited-Use Auxiliary Boiler 0.96 0.96 0.05 

Total -550.5 -420.8 -3,110.1 

Table 10 Net Emission Increases for the Project and Tribal Minor NSR Applicability

Tribal Minor NSR Applicability PM10 PM2.5 SO2

Significant emissions increases from the Project 333 293 30 

Combined contemporaneous emission decreases -550.5 -420.8 -3,110 

Net emissions increase -217.5 -127.8 -3,080 

Tribal NSR Threshold 15 10 7 

Minor NSR Applicable? No No No

Baseline Emissions of Units 4 and 5 Inflated with Illegal Emissions

Comment 33:

(Commenters: SJCA, Stamper Report) 

Excerpted comments also claimed the baseline actual emissions were inflated, as follows: 

EPA should not allow baseline actual emissions of FCPP Units 4 and 5 to be inflated with illegal emissions. 

In 2012, Earthjustice filed a complaint against APS and other owners of FCPP on behalf of environmental and 

citizen groups claiming that there had been several modifications at FCPP Units 4 and 5 beginning in or around 

2007 and continuing. The claimed modifications include upgrading and/or replacing key components of the 

boilers, turbines and generators, and replacement of the high pressure turbines. Further, in its November 24, 

2010 submittal of a BART alternative to EPA, APS noted EPA’s collection of information under Section 114 of 

the Clean Air Act and stated that it was presumably in the context of an EPA enforcement investigation. If 

 
FCPP SCR Project 

Response to Comments 

Page 65 of 109 

modifications at FCPP Units 4 and 5 should have triggered PSD as major modifications, then BACT should have 

been required at those units concurrent with the modifications. If these PSD claims are valid, that would mean 

the FCPP Units 4 and 5 baseline emissions reflect illegal emissions levels. 40 C.F.R. §52.21(b)(48)(i)(a) requires 

the baseline emission rate to be adjusted downward to exclude any non-compliant emissions. EPA must take 

this into consideration in evaluating the projected actual increase in emissions at FCPP Units 4 and 5 due to 

the FCPP Project. 

Response 33:

We do not agree that the baseline actual emissions are inflated. First, we specifically requested that APS 

confirm that the average rate for baseline actual emissions was appropriately adjusted downward to exclude 

any non-compliant emissions. APS identified opacity exceedances during the baseline period for Units 4 and 

5.45 However, those exceedance cannot be directly attributed to excess emissions of particulate matter, as the 

compliance method for PM emissions for Units 4 and 5 is annual PM testing. APS also identified an exceedance 

of the NOX emission limit for Unit 3, resulting in excess emissions of 0.048 tons of NOX.

46 However, Unit 3’s 

NOX emissions were not used in our calculations since there was not a significant emissions increase in NOX

from Units 4 and 5. As such, there were no non-compliant emissions excluded from our calculations. 

Second, we disagree with the commenter that emissions should be subtracted from the baseline actual 

emissions based on allegations of unpermitted modifications at Units 4 and 5. Allegations of such 

modifications are not a sufficient basis on which to adjust the baseline actual emissions. There has been no 

resolution of the allegations, which means that they are speculative. The fact that EPA issued a section 114 

letter to APS concerning FCPP in March 2009 does not demonstrate that there were non-compliant emissions 

in the baseline actual emissions. This letter requests information. Similarly, the fact that an environmental 

non-governmental organization filed a Complaint in the U.S. District Court is not a sufficient demonstration 

that any of the emissions were non-compliant. See Sierra Club v. Johnson, 541 F.3d 1257, 1266-1267 (11th Cir. 

2008) and Sierra Club v. EPA, 557 F.3d 401,405-06 (6th Cir. 2009) (discussing the burden of proof in title V 

petitions). The commenter hypothesizes that if there were non-compliant emissions in the baseline actual 

emissions, then a permitting agency would have required a lower emissions rate as Best Available Control 

Technology. However, whether a lower emissions rate would have been required or what that rate might have 

been is purely speculative. 

Thus, although 40 CFR 52.21(b)(48)(i)(b) provides that non-compliant emissions must be excluded from the 

calculation of baseline actual emissions (“The average rate shall be adjusted downward to exclude any noncompliant emissions that occurred while the source was operating above any emission limitation that was 

legally enforceable during the consecutive 24-month period.”), there has not been any determination that 

there are non-compliant emissions, much less what the magnitude of such emissions would be. However, 

even if we agreed with the commenter regarding the alleged violations raised by the Earthjustice complaint, 

the type of emissions limits that could result from the resolution of such allegations do not currently exist, and 

were not in existence or legally enforceable during the 24-month baseline period. As a result, the only legally 

enforceable limitation we can use as a basis for determining non-compliant emissions, or to calculate what 

quantity of emissions should be excluded, are those that were legally enforceable during the 24-month 

 

45 See July 2, 2014 letter from David C. Bloomfield, FCPP to Lisa Beckham, EPA, “Four Corners Power Plant SCR Retrofit Project – 

Addendum to Application for PSD Permit, at 2-3. 

46 Id. 
FCPP SCR Project 

Response to Comments 

Page 66 of 109 

baseline period. We listed these emission limits on Page 10 of 39 in the Fact Sheet, and noted in our analysis 

that there is no indication that Units 4 and 5 operated above these limits. As a result, we disagree with the 

commenter’s assertion that the baseline actual emission rate should be adjusted to account for emissions 

associated with the alleged violations. 

Project Causes Significant Increases in PM10, PM2,5, CO, and GHGs

Comment 34:

(Commenters: SJCA, Stamper Report) 

The commenters contend that installation of the SCR on Units 4 and 5 will cause significant emissions 

increases in pollutants other than SAM, as excerpted below. This comment generally repeats the points that 

have already been made and to which we have responded above. It also raises some new relatively minor 

issues to which we respond below. 

The project at FCPP should have been projected to result in a significant emissions increase of sulfur dioxide, 

particulate matter including PM10 and PM2.5, carbon monoxide, SAM, and greenhouse gases. 

Based on the analysis in previous comments, I have re-calculated the projected actual emissions for the 

project at Four Corners Power Plant as follows: 

(a) Since the shutdown of FCPP Units 1, 2, and 3 is inherently part of the project and since the increase 

in projected future capacity factor is likely at least in part related to the shutdown of FCPP Units 4 and 5, I 

calculated the projected actual emissions at FCPP Units 4 and 5 assuming none of APS’s projected increase in 

capacity factor could be excluded as solely due to demand growth. 

(b) Since APS and EPA have only evaluated the emission increases due to the parasitic load of the SCR 

systems to be installed at Units 4 and 5 in the projected actual emissions calculations, I calculated projected 

actual emissions from the revised parasitic load heat input increase calculated in the above section and also 

from APS’s projection of heat input increases due to economizer bypass during 2012 to 2013. See Table 4 of 

the Stamper Report. 

(c) Last, I calculated the projected actual emission increases using the corrected parasitic load heat 

input increases shown in Table 4 of the Stamper Report and added those to the heat input increase projected 

by APS as solely due to demand growth. 

Both APS and EPA appear to have projected actual emissions for FCPP Units 4 and 5 based on emission rates 

and capacity factors based on a two unit average rate, rather than unit-specific rates. Given that each emission 

unit, although the same or similar size, can have different operational characteristics, it does not make sense 

to project future emissions of each unit using average capacity factors across both units or using average 

emission rates across both units. It also is inconsistent with the PSD regulations. See 40 C.F.R. 

§52.21(a)(2)(iv)(c) (“[a] significant emissions increase of a regulated NSR pollutant is projected to occur if the 

sum of the difference between the projected actual emissions ...and the baseline actual emissions...,for each 

emissions unit, equals or exceeds the significant amount for that pollutant...),and §52.21(b)(41) (Projected 

actual emissions means the maximum annual rate, in tons per year, at which an existing emissions unit is 
FCPP SCR Project 

Response to Comments 

Page 67 of 109 

projected to emit....[emphasis added]). For the calculation of projected future actual emissions assuming all of 

APS’s projected increase in heat input is related to the FCPP project, APS only provided the heat input 

projections in terms of both units combined. So for the purpose of these calculations, I used the same 

calculations of projected heat input and the same average emission factors as used by APS. 

It must be noted that APS’s projection of future heat input of FCPP Units 4 and 5 together does not seem to 

make sense with the purported average 89.35% capacity factor. See April 2014 PSD Permit Application, Table 

A-8. An electrical generating unit’s capacity factor is commonly determined by the projected MW-hrs to be 

generated divided by the maximum possible MW-hrs that could be generated had the unit operated 

continuously at maximum capacity. Thus, if the gross generating capacity of Units 4 and 5 each are 810 MW as 

stated by APS, an average 89.35% capacity factor should mean each unit produces on average 6,339,918.6 

MW-hrs post project. And with the heat rate provided by APS of 9,800 Btu/kWhr26, the heat input to achieve 

this annual capacity factor would be 62,131,202.3 MMBtu per unit or 124,262,404.6 MMBtu/yr for both units 

in total. Yet, APS only projected an annual heat input for both units at 89.35% capacity factor of 116,008,264 

MMBtu/hr. See April 2014 PSD Permit Application, Table A-8. 

Upon closer evaluation, it appears that APS applied the 89.35% capacity factor to its “maximum 24-hour total 

heat input for Units 4 and 5”27 of 14,822 MMBtu/hr (or 7,411MMBtu/hr per unit multiplied by two). This is 

not a commonly accepted interpretation of capacity factor. In fact, APS has indicated that its projections of 

future capacity factors are based on the “proportion of projected generation in relation to the generation 

possible within the same period.” See 7/2/2014 Letter from APS to EPA Region 9 (Docket ID EAP-R09-OAR2014-0545-0004) at 4. Moreover, in a calculation of capacity factor, one uses the maximum possible 

generation rate per hour, not the 24-hour average rate. As discussed in Section I.A.1. above, the FCPP units 4 

and 5 are allowed to operate at higher hourly heat input capacities and have in fact operated at higher hourly 

heat input capacities than 7,411 MMBtu/hr. 

Thus, APS’s projection of annual heat input in Table A-8 does not appear to be reflective of an 89.35% capacity 

factor. Instead, it is more reflective of a capacity factor of 83.4% (assuming 810 MW gross generating capacity 

and a heat rate of 9,800 Btu/kWh). EPA must request further details from APS to demonstrate that the 

projected heat input increase at FCPP Units 4 and 5 as due to demand growth (but which at least a portion of 

is likely associated with the project and/or could not have been accommodated during the baseline period) 

truly reflects APS’s projected future average capacity factor for Units 4 and 5 of 89.35%. EPA should make such 

a demonstration part of the administrative record and allow for public comment on such demonstration prior 

to making a final permitting decision. 

(a) Projected actual increase in emissions based on the increase in capacity factor of FCPP Units 4 and 5 that 

APS claimed is unrelated to the project. 

For the purpose of these projected actual calculations, I used APS’s projected average annual heat input 

increases and APS’s average emission rates for Units 4 and 5 combined to project future emissions which APS 

claimed to be unrelated to the project. As discussed above, this heat input increase is likely attributable to the 

shutdown of FCPP Units 1, 2, and 3 which is inherently related to the project and/or the units were not 

capable of accommodating the increase in demand during the baseline. The emission factors I used in this 
FCPP SCR Project 

Response to Comments 

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projection of future actual emissions are the same as used by APS, and are listed in Table 4 of EPA’s Fact Sheet 

(at p. 15). 

As Table 5 (see Stamper Report) shows, the increased heat input associated with APS’s projected heat input 

increases that it claims are all due to demand growth would result in significant net emissions increases of 

particulate matter, PM10, PM2.5, sulfur dioxide (SO2), carbon monoxide (CO), and greenhouse gases (CO2e) 

without even including the increased emissions due to the economizer bypass and parasitic load of the SCR 

and DSI systems. The emission increase projected for greenhouse gases (CO2e) is 26 times the PSD significance 

level of 75,000 tpy. Thus, if at least 4% of the projected heat input increase estimated due to demand is also 

due to the shutdown of Units 1-3 and/or Units 4 and 5 were not capable of accommodating the increased 

demand during the baseline period, then the project would be significant for greenhouse gases without even 

considering the emissions due to the parasitic load of the SCR. The emission increase projected for SO2 is 40 

times the PSD significance level of 40 tpy, and thus if at least 2.5% of APS’s projected heat input for future 

demand growth is also due to the shutdown of FCPP Unit 1-3 and/or Units 4 and 5 were not capable of 

accommodating the increased demand during the baseline period, the project would be significant for SO2. 

Therefore, it is imperative that EPA request further analysis and documentation to evaluate whether any of 

APS’s projected future increase in heat input at Units 4 and 5 can be lawfully discounted as solely due to 

demand growth and not at all due to the FCPP Project. EPA should make this demonstration part of the 

administrative record and allow for public comment on such demonstration prior to making a final permitting 

decision. As discussed in earlier comments, it does not appear that Units 4 and 5 were capable of 

accommodating all of this increase in demand during the baseline period. Based on my analysis presented in 

Table 2 of the Stamper Report, the capacity factor that the units were capable of accommodating during the 

baseline period was, on average between Units 4 and 5, 5.17% lower than the projected average capacity 

factor of 89.35%. EPA must evaluate these issues further and request documentation to verify whether the 

units were capable of accommodating the increased capacity factor during the baseline and to determine how 

much of the projected increase is due to the shutdown of FCPP Units 1-3. EPA should make such 

documentation available to the public for review in a new comment period before finalizing the permit for the 

FCPP project. 

(b) Projected actual emission increase based on revised increase in annual heat input due to parasitic load of 

SCR and economizer bypass. 

In Table 6 (see Stamper Report), I have provided my calculations of whether the SCR project impacts alone 

would cause a significant emission increase, based on a comparison of revised projected actual emissions that 

take into account the parasitic load from the revised parasitic load heat input increase calculated in an earlier 

comment and also from APS’s projection of heat input increases due to economizer bypass during 2012 to 

2013. For this analysis, I used the heat input due to SCR parasitic load that I calculated as discussed in an 

earlier comment, added to the average heat input due to economizer bypass calculated by APS for 2012 to 

2013. See Table 4 in the Stamper Report. For the purpose of this analysis which only reflects whether the 

increase in emissions just due to the SCR systems to be installed at FCPP Units 4-5 would be significant, I 

added the projected increase in heat input from Table 4 in the Stamper Report (i.e., 688,275 MMBtu/yr) to the 

baseline (pre-project) heat input for Units 4 and 5 (i.e., 97,258,307 MMBtu/yr) for a total of 97,946,582 

MMBtu/yr. The emission factors I used in this projection of future actual emissions are the same as used by 

APS, and are listed in Table 4 of EPA’s Fact Sheet (at p. 15). 
FCPP SCR Project 

Response to Comments 

Page 69 of 109 

As Table 6 in the Stamper Report shows, a corrected and more accurate assessment of the increase in heat 

input just due to the SCR system parasitic load and economizer bypass shows that, even if APS is justified in 

excluded all demand growth emission increases, the emission increases due to the SCR system would be 

significant for SO2, as well as PM10, PM2.5, and H2SO4. And this projection understates the projected actual 

increases due to power needs of the proposed controls because it does not include any increased heat input 

due to the parasitic load of the sorbent injection system. 

(c) Projected actual increase in emissions based on revised heat input increases due to SCR power needs and 

assuming APS’s demand growth claims cannot be lawfully excluded. 

If EPA finds that the demand growth projected by APS is entirely related to the FCPP project and/or that FCPP 

Units 4 and 5 were not capable of accommodating the increased demand during the baseline period, then the 

projected demand growth increase must be added to the heat input increases due to the power needs of the 

SCR systems in projecting whether there will be a significant emissions increase as a result of the FCPP Project. 

The results of this analysis are provided in Table 7 (see Stamper Report). 

Based on all of the above analyses, the SCR installation at FCPP Units 4 and 5 should have been projected to 

result in significant emission increases for, at the minimum, SO2, PM10, PM2.5 and SAM (per Table 6 in the 

Stamper Report). Further, if all or even if a portion of the increased heat input due to demand growth is 

related to the FCPP Project and/or the units were not capable of accommodating the increase in demand 

during the baseline period, the FCPP project should have been projected to result in a significant net emissions 

increase of PM, CO, CO2e, SO2, PM10, PM2.5 and SAM (per Table 7 in the Stamper Report). EPA and APS only 

projected significant emission increases of PM10, PM2.5 and SAM, and that determination appears to be in 

error. 

The commenter requests that EPA revise its PSD analysis and reissue its PSD analysis for public comment prior 

to reissuance if a permit is granted. If a project results in a significant emission increase for any PSD pollutant, 

then an evaluation of whether the project would result in a significant net emissions increase must be done – 

i.e., Step 2 NSR. The FCPP Project should have been considered as significant for, at the minimum, SO2, PM10, 

PM2.5, H2SO4, PM, CO, and CO2e 

Response 34: 

Much of this comment has been previously addressed in our previous responses. 

First, the commenter recalculated the projected actual emissions by (1) assuming none of the increase in 

projected actual emissions were due solely to demand growth and (2) increasing the assumed parasitic load of 

the SCR systems and economizer bypass. However, we disagree with either adjustment. In Responses 28 – 31, 

we specifically address why we disagree with the need to make these revisions to the calculations for 

projected actual emissions. 

Second, the only new issue raised in this comment is whether it is impermissible for EPA as the permitting 

agency to rely on the combined average emissions of Units 4 and 5 instead of evaluating each unit individually. 

EPA continues to find that it is permissible to rely on a combined average for determining projected actual 
FCPP SCR Project 

Response to Comments 

Page 70 of 109 

emissions for the FCPP SCR Project, but we also provided in our Supplemental Emissions Analysis (prepared by 

EPA and referenced in the Fact Sheet) a calculation of projected actual emissions using each unit individually 

as suggested by the commenter. See Tables 2 and 14 of Supplemental Emissions Analysis. Significantly, the 

difference in the calculation method had no effect on which pollutants triggered PSD review. Using each unit 

individually as suggested by the commenters, the FCPP SCR Project continued to trigger PSD only for SAM. We 

also note that the commenter contends that APS only provided the projected operation of Units 4 and 5 as 

combined averages. However, this is not true as seen in Table A-8 of the April 2014 PSD Application. 

Third, we disagree with the commenter’s assertions regarding how an EGU’s capacity factor is commonly 

determined. The commenter asserts APS should have used the projected MW-hrs to be generated divided by 

the maximum possible MW-hrs that could be generated had the unit operated continuously at maximum 

capacity. While utilities do express a unit’s capacity factor in terms of MW-hr generation for certain purposes, 

there is no regulatory requirement in the PSD program for the capacity factor to be expressly reported in 

terms of generation, and the commenter has not provided a basis for why this is the case. Capacity factors 

reported in terms of heat input are also relied on by facilities for certain purposes, particularly in 

environmental reporting contexts, where a direct correlation between fuel burned and emissions can be 

made. All of the calculations for the PSD applicability determination were based on heat input to the boilers. 

We do not see a rational basis for switching to MW-output. It is unclear why the commenter is asserting this 

different method is more appropriate, but appears to again assert that the maximum hourly potential values 

should have been used in our calculations instead of the heat input rate for the total fuel that is projected for 

future operations. As we thoroughly explain in response to Comment 27, we disagree with this assumption 

and disagree that a new demonstration is needed to determine PSD applicability. 

Fourth, as explained in Responses 28 and 29, the increase in demand growth represents emissions that APS 

could have accommodated and is unrelated to installation of the SCR or the shutdown of Units 1-3. As such, 

revised calculations based on the commenter’s assertions are not necessary. 

In summary, we disagree with the commenter’s conclusion that revisions to the analysis conducted by APS 

and EPA are needed to account for the assertions made by the commenter. We note that even if we did agree 

with the commenter’s calculations of emissions from Units 4 and 5, as summarized in Table 7 of the Stamper 

Report, they still would not affect the overall determination that only SAM emissions are subject to PSD 

review, because the shutdown of Units 1-3 provide a substantial amount of creditable emission decreases of 

SO2, PM10, PM2.5, PM, CO, and CO2e. As seen in Tables 1 and 2 of this document, the emission decreases are 

sufficient to ensure a significant net emission increase is only trigger for SAM. See also Responses 35 and 36 

below. 

Emissions from Units 1-3 Cannot Be Creditable Decreases

Comment 35:

(Commenters: SJCA, Stamper Report) 

The comment letter reiterates the claim that there are illegal emissions from Units 1-3 that cannot be credited 

as emission decreases as excerpted below. 
FCPP SCR Project 

Response to Comments 

Page 71 of 109 

In evaluating creditable emission decreases for netting out any of the significant projected emission increases 

of the FCPP Project, EPA must determine whether the emission reductions from the shutdown of FCPP Units 1, 

2, and 3 are fully creditable. 

If a project results in a significant emission increase for any PSD pollutant, then an evaluation of whether the 

project would result in a significant net emissions increase must be done – i.e., Step 2 NSR. As shown above in 

Tables 6 and 7 above, the FCPP Project should have been considered as significant for, at the minimum, SO2, 

PM10, PM2.5, and H2SO4, and also likely for PM, CO, and CO2e. The next step in determining PSD applicability 

is to determine what emission increases and decreases are creditable. 

EPA is proposing to allow APS to take credit for the shutdown of FCPP Units 1-3 for its projected significant 

increases of PM10 and PM2.5. See EPA Fact Sheet at 20. But EPA has not ensured that the emission reductions 

meet all of the requirements necessary to be creditable. First, EPA cannot credit emission decreases if an 

emissions unit was illegally emitting. In its November 24, 2010 submittal of a BART alternative to EPA, APS 

noted EPA’s collection of information under Section 114 of the Clean Air Act, and stated that it was 

presumably in the context of an EPA enforcement investigation. See November 24, 2010 Letter from APS to 

EPA at 3 (Ex. 5). If EPA has knowledge that any of the Units 1, 2, or 3 should have obtained a PSD permit and 

met BACT for past modifications, then it must not allow FCPP to net out of PSD review with illegal emissions. 

Response 35:

As described in Comment 33, the allegations raised in the complaint by Earthjustice regarding PSD violations 

at Units 4-5 were also made in regards to Units 1-3. Similar to Comment 33, the commenter asserts that 

emissions levels above the emission limit that would be the result of an enforcement action resolving these 

allegations are illegal (again, either as a retroactive BACT limit or consent decree limit that would be lower 

than current emission limits). As noted in our response to Comment 33, allegations of violations raised by the 

Earthjustice Complaint are speculative until proven, and the type of emissions limits that could result from the 

resolution of such allegations do not currently exist, and were not in existence or legally enforceable during 

the 24-month period used to establish the amount of creditable emission decrease from Units 1-3. Thus, those 

allegations do not provide a basis for adjusting the emissions calculations in this permit action. Per Table A-1.4 

of the 2014 PSD permit application, this period corresponded to calendar year 2011-12, and our analysis does 

not indicate that Units 1-3 operated above the legally enforceable limits in effect during that period. Fact 

Sheet at 18-19. As a result, we disagree with the commenter’s assertion that the creditable emission decrease 

from the Units 1-3 shutdown should be adjusted to account for emissions associated with the speculative 

alleged violations. 

Comment 36:

(Commenters: SJCA, Stamper Report) 

The comment letter also states that the emission decreases from Units 1-3 are not creditable as excerpted 

below. 

EPA cannot give credit for the shutdown of FCPP Units 1-3 because it is required by the BART FIP as a Regional 

Haze control strategy. The definition of net emissions increase includes the following limitation, among many, 

for determining creditable emission decreases for netting: 
FCPP SCR Project 

Response to Comments 

Page 72 of 109 

A decrease in actual emissions is creditable only to the extent that: 

(a) The old level of actual emissions or the old level of allowable emissions, whichever is lower, 

exceeds the new level of actual emissions. 

40 C.F.R. §52.21(b)(3)(vi)(a). 

Allowable emissions is, in turn, defined in pertinent part as: 

...the emissions rate of a stationary source calculated using the maximum rated capacity of the 

source (unless the source is subject to federally enforceable limits which restrict the operating 

rate, or hours of operation, or both) and the most stringent of the following: 

... 

(ii) The applicable State Implementation Plan emissions limitation, including those with a future 

compliance date. . . . 

40 C.F.R. §52.21(b)(16)(ii). 

The requirement to permanently shutdown FCPP Units 1-3 by January 1, 2014 was promulgated by EPA as a 

BART alternative as part of the BART determination for the FCPP. 40 C.F.R. §49.5512(i)(3); 77 Fed.Reg 51648 

(8/24/12). This rulemaking became effective 10/23/12. APS was required to notify EPA if it chose to follow this 

BART alternative by December 31, 2013. 40 C.F.R. §49.5512(i)(4). APS notified EPA that it was going to follow 

this option to shut down APS Units 1-3 in a December 30, 2013 letter (Docket ID EPA-R09-OAR-2014-0545-

0009). APS did in fact shut down units 1-3 on or before January 1, 2014. Thus, the allowable emissions of FCPP 

Units 1-3 are zero pursuant to EPA’s BART FIP for Four Corners Power Plant, which required the units to 

permanently shut down by January 1, 2014. 

EPA has acknowledged the shutdown of FCPP Units 1-3 is enforceable under the FIP, yet in evaluating whether 

the requirements of 40 C.F.R. §52.21(b)(3)(vi)(a) were met by the netting transaction, EPA ignored the fact 

that the FCPP Units 1-3’s allowable emissions (and allowable emissions by definition includes the 

requirements of an implementation plan, including those with a future compliance date) require the 

shutdown of FCPP Units 1-3 by January 1, 2014. Thus, because the allowable emissions of FCPP Units 1-3 are 

zero, there are no creditable emissions reductions from the shutdown of these units. 

In summary, none of the emission reductions from the shutdown of FCPP Units 1-3 should be considered as 

creditable emission decreases in the determination of net emission increase from the FCPP project, due to the 

fact that EPA’s regional haze FIP required the shutdown of Units 1-3 by January 1, 2014 based on APS selecting 

that compliance option which it did by letter dated December 30, 2013. Because the FIP requirements do not 

allow FCPP Units 1-3 to operate after January 1, 2014, this means there are zero allowable emissions for FCPP 

Units 1-3 and no reductions that can be considered creditable emissions reductions for netting pursuant to 40 

C.F.R. §52.21(b)(3)(vi)(a) and §52.21(b)(16)(ii). 
FCPP SCR Project 

Response to Comments 

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If EPA disagrees with this, then that means there is no enforceable requirement for the Units 1-3 to shut 

down. Therefore, netting credit for the shutdown of FCPP Units 1-3 is not creditable pursuant to 40 C.F.R. 

§52.21(b)(3)(vi)(b). 

Response 36:

We disagree with the commenter. The 2012 BART FIP did not require any reductions in emissions from FCPP 

other than for NOX. The shutdown of Units 1-3 was optional. So while the shutdown of Units 1-3 is now 

enforceable under the FIP, based on APS’ notification to EPA that APS selected this option, the shutdown was 

not required by the FIP. We do not interpret the FIP as requiring the shutdowns of Units 1-3. In general we 

find this comment confusing. To the extent the commenter is asserting that because the shutdown of Units 1 

– 3 is enforceable as part of the FIP, the decreases are not surplus and cannot be used for netting, we 

disagree. The only pollutant subject to BART (and regulated in the BART FIP) was NOx. Any other pollutant 

decreases were not part of the BART FIP and are available for netting. 

To the extent the comment is based on an interpretation of EPA’s regulations, it is also incorrect. To begin, for 

purposes of evaluating creditable emissions decreases, the contemporaneous period is five years before the 

date of the modification. 40 CFR 52.21(b)(3)(ii). EPA appropriately determined that we could take into account 

increases and decreases that occurred within five years before 2018, or 2013. When APS shutdown Units 1 – 

3, the “old” level of actual or allowable emissions were the emissions occurring before the Units were 

shutdown. The “new” level of actual emissions was zero. The commenter’s assertion, therefore, does not 

account for the significance of the words “old” and “new” in the §52.21(b)(3)(vi) definition of creditable 

emission decrease: 

A decrease in actual emissions is creditable only to the extent that: 

(a) The old level of actual emissions or the old level of allowable emissions, whichever is lower, 

exceeds the new level of actual emissions; 

(b) It is enforceable as a practical matter at and after the time that actual construction on the 

particular change begins. 

(c) It has approximately the same qualitative significance for public health and welfare as that 

attributed to the increase from the particular change; 

40 CFR 52.21(b)(3)(vi) 

For example, for the creditable PM emission decrease from the Unit 1-3 shutdown, the old level of actual 

emissions was calculated as 648.4 tpy47, and the old level of allowable emissions is approximately 1,099 tpy.48

The new level of actual PM emissions is zero. Since the old level of actual emissions (i.e., 648.4 tpy) is lower 

than the old level of allowable emissions (i.e., 1,099 tpy), the regulation requires us to use the actual 

emissions decrease. The amount by which that emissions decrease exceeds the new level of actual emissions, 

which is zero, is the creditable emissions decrease (i.e., 648.4 tpy). Per paragraph (b), this emission decrease is 

 

47 Per Table A-1.4, 2014 PSD permit application, this is based on actual emissions for the 24-month period from January 2011 to 

December 2012. 

48 Please note that the PM limit is a lb/MMBtu limit, and not a tpy limit. The tpy PM limit listed above is based on the 0.050 

lb/MMBtu PM limit and the combined annual heat duty of Units 1-3, and was presented to provide a direct comparison to the actual 

tpy emissions over that period.
FCPP SCR Project 

Response to Comments 

Page 74 of 109 

enforceable as a practical matter due to the BART FIP requirement to shutdown Units 1-3. The commenter has 

not raised any issues regarding the paragraph (c) requirement for qualitative significance. 

Table 11 Units 1-3, PM Emissions (tpy)

CY2011-12 

(Old levels) 

CY2014-Present 

(New levels) 

Allowable 1,099 0 

Actual 648.4 0 

The commenter’s assertion that the allowable emissions from Units 1-3 is zero, and that therefore the 

emission decrease from Units 1-3 should be zero, ignores the distinction between old and new emission levels. 

Starting on January 1, 2014 and going forward, the allowable emission level from Units 1-3 is zero. This level of 

allowable emissions, however, does not reflect the ‘old’ level of allowable emissions that was in effect during 

calendar year 2011-12 chosen for calculating baseline actual emissions. An implicit part of the commenter’s 

assertion, therefore, is that an allowable emission limit with a future compliance date should be retroactively 

applied to periods of time prior to the compliance date for the purposes of calculating creditable decreases. 

We disagree. Since the requirement to shutdown Units 1-3 did not take effect until January 1, 2014, we 

disagree that this level of allowable emissions should be used as the ‘old’ level of allowable emissions for the 

2011-12 time period used for calculating baseline actual emissions. And, the BART FIP did not set an allowable 

emission limit for any pollutant other than NOX. 

Contemporaneous Emissions Increases at Units 4 and 5

Comment 37:

(Commenter: Stamper Report) 

The comments also stated that EPA did not properly account for emissions increases, as excerpted below. 

EPA did not account for contemporaneous increases from Units 4 and 5 in its netting analysis. 

In determining whether there are creditable and contemporaneous emission increases to be included in the 

netting analysis, EPA only evaluated the increase from the auxiliary boiler added in 2012. See EPA Fact Sheet 

at 16. EPA failed to evaluate whether there had been any other emission increases at Units 4 and 5 that were 

contemporaneous and otherwise creditable. 

In 2012, Earthjustice filed a complaint against APS and other owners of FCPP on behalf of environmental and 

citizen groups claiming that there had been several modifications at FCPP Units 4 and 5 beginning in or around 

2007 and continuing. The claimed modifications include upgrading and/or replacing key components of the 

boilers, turbines and generators, and replacement of the high pressure turbines. Further, in its November 24, 

2010 submittal of a BART alternative to EPA, APS noted EPA’s collection of information under Section 114 of 

the Clean Air Act, and stated that it was presumably in the context of an EPA enforcement investigation. Thus, 

EPA presumably has information on these various projects at FCPP Units 4 and 5 (or could request such 

information from APS) to evaluate which of these projects were contemporaneous with the current proposed 

project and, for those contemporaneous projects, to determine what are the creditable emissions increases 

associated with the contemporaneous physical and/or operational changes at FCPP Units 4 – 5. In accordance 

with the definition of net emissions increase, EPA must evaluate all of the contemporaneous emission 
FCPP SCR Project 

Response to Comments 

Page 75 of 109 

increases that are creditable in determining the overall net emissions increase from the project. 40 C.F.R. 

§52.21(b)(3)(i)(b). 

It must be noted that the physical or operational changes do not need to be found to be major modifications 

in order for EPA to evaluate the projects as contemporaneous emission increases. The rule requires 

consideration of any emission increases or decreases that are contemporaneous and otherwise creditable. 

EPA does not need to wait for resolution of the claims brought by Earthjustice. 

APS has indicated that construction on the SCR system must start by mid-2015 to meet the SCR BART 

compliance deadline in July 2018. See April 2014 PSD Permit Application at 2-8. Thus the contemporaneous 

timeframe for determining net emissions increase began in 2010. 40 C.F.R. §52.21(b)(3)(ii)(a). According to 

documentation on capital expenditures for Four Corners Units 4 and 5 filed with the California Public Utilities 

Commission by Southern California Edison (at that time, an owner in part of FCPP Units 4 and 5) as part of its 

2012 rate case, several capital projects were identified that are the types of projects EPA has commonly found 

to be non-routine modifications. Further, within the contemporaneous timeframe, several capital projects 

were outlined for FCPP Unit 5 during the 2014 outage. 

EPA must evaluate emissions increases due to the physical changes or changes in the method of operation 

that occurred during these outages and any other such outages that fall within the contemporaneous 

timeframe. EPA should make such an evaluation part of the administrative record and allow for public 

comment on the evaluation prior to making a final permit decision. It must further be noted that, in evaluating 

any emission increases from contemporaneous physical or operational changes at FCPP Units 4 and 5 such as 

from a turbine replacement, EPA’s regulations require that emission increases be based on the actual-topotential methodology. See definition of “actual emissions” at 40 C.F.R. §52.21(b)(21)(iv). 

In summary, EPA must fully evaluate and document all contemporaneous and creditable emission increases at 

FCPP Units 4 and 5 in evaluating the net emissions increase from the project at FCPP. Until EPA collects 

information on all contemporaneous emission increases at FCPP Units 4 and 5 and provides the details of the 

creditable emission increases associated with such increases to the public for review, EPA’s analysis of net 

emissions increase cannot be considered complete for the FCPP Project. 

Response 37:

We disagree. As we described in Comment 33 there has not been any determination that there are noncompliant emissions much less what the magnitude of those emissions would be. Additional evaluation of 

these alleged modifications is not necessary to determine the net emissions increases from the FCPP SCR 

Project. The alleged modifications raised by the commenter are in relation to Units 4 and 5, emission units 

being modified by the current project. Secondly, regarding the capital expenditures and outages for Units 4 

and 5 referenced by the commenter, we disagree that further analysis is required. Any increases that are 

purported to have occurred are purely speculative at this time. 

Emissions increases occurring at the emission units involved in the project prior to the start of construction 

would be part of the emission unit’s operating history and would be reflected in the 5-year period that the 
FCPP SCR Project 

Response to Comments 

Page 76 of 109 

source uses for determining baseline actual emissions for each modified emission unit.49 In the case of the 

FCPP SCR Project, APS used the highest 24-month average of emissions during the baseline period. As a result, 

prior emission increases at Units 4 and 5 are reflected in baseline actual emissions. Carving out pieces of those 

emissions, and including such emission increases again as contemporaneous increases in the netting analysis 

would therefore double-count the emissions increase. Or, you would subtract those increases from the 

baseline actual emissions, but then add them in again for the net emissions increase analysis. We see no basis 

in the PSD regulations for this type of calculation. 

Summary of PSD Applicability 

Comment 38:

(Commenters: SJCA, Stamper Report) 

The comment letter repeats many of its prior comments in the following excerpt. 

Evaluation of whether the project should have been projected to result in a significant net emissions increase 

of pollutants aside from H2SO4. 

Based on the discussion above that none of the emission decreases from the shutdown of FCPP Units 1-3 

should be considered creditable, the FCPP Project cannot net out of PSD review for any of the significant 

projected emission increases. If EPA only considers the increased heat input due to the SCR installation at 

FCPP Units 4 and 5 in evaluating net emissions increase, the FCPP Project should have been projected to result 

in a significant emission increase and a significant net emission increases for, at the minimum, SO2, PM10, 

PM2.5 and SAM (per Table 6 in the Stamper Report). If all or even if a portion of the increased heat input due 

to demand growth is related to the FCPP Project and/or the units were not capable of accommodating the 

increase in demand during the baseline period, the FCPP Project should have been projected to result in a 

significant emission increase and a significant net emissions increase of PM, CO, CO2e, SO2, PM10, PM2.5 and 

SAM (per Table 7 in the Stamper Report). 

This analysis of net emissions increase is not complete, because it does not include the emissions associated 

with the truck traffic for sorbent and SCR reagent, nor does it account for all contemporaneous emission 

increases at the FCPP. But this partially complete review shows that without creditable emission reductions 

due to the shutdowns of FCPP Units 1-3, the FCPP Project should have triggered PSD applicability for 

numerous regulated NSR pollutants as a major modification. 

As stated above, EPA must evaluate and document all contemporaneous emission increases at FCPP Units 4 

and 5 before a complete evaluation of the net emissions increase of the FCPP Project can be accomplished. 

 

49 For the purposes of this response, the ‘legality’ of the alleged 2007 modifications is a separate issue addressed in a previous 

comment. This response addresses the handling and disposition of legal previous emission increases that occurred at units being 

modified by the current project. If the alleged modifications are illegal, their emission increases would be addressed in a different 

manner than emission increases from legal modifications. As described in a previous response, however, it would still not involve 

accounting for them as contemporaneous increases in the netting analysis (i.e., illegal emissions from the project units would be 

excluded from baseline actual emissions). 
FCPP SCR Project 

Response to Comments 

Page 77 of 109 

Response 38:

Since the excerpt of the comment above repeats many prior comments that have already been addressed, we 

incorporate our prior responses to the comments. As EPA has stated above, we disagree with the assumptions 

upon which Table 7 of the Victoria Stamper comment letter is based. Specifically, we disagree with the 

commenter’s exclusion of creditable emissions decreases from the shutdown of Units 1- 3, and with the 

comments concerning the appropriate heat rate input to use in calculating projected actual emissions, the 

demand growth exclusion, the parasitic load for the SCR and the economizer bypass. 

The comment also claims that our analysis of the significant net emissions increases from the FCPP SCR Project 

is incomplete because we did not include the emissions associated with the truck traffic for sorbent and SCR 

reagent. We disagree. Table 2 of the Fact Sheet clearly includes the emissions from truck traffic for sorbent 

and SCR reagent delivery in projected actual emissions for the FCPP SCR Project. 

Finally, we present revised calculations, in light of all comments reviewed related to the emissions analysis. 

Our only change, which is minor, is to include the parasitic load of the DSI systems for the FCPP SCR Project. 

These calculations do not affect our determination that only SAM emissions are subject to PSD or tribal minor 

NSR review. 

Tables 3-10 in Response 32 above provide our revised emissions calculations. Our only change was to use 

0.324% instead of 0.3% to account for projected related increases in fuel use from SCR and DSI. 

Auxiliary Boiler

Comment 39: 

(Commenters: SJCA, Stamper Report) 

The commenter noted the following: 

With respect to the auxiliary boiler that was constructed in 2012, a review of the Title V permit for the 

auxiliary boiler shows that, although the boiler is called a “limited use auxiliary boiler” which purportedly 

means it operates at less than 10% capacity factor or less than 876 hours per year, the permit does not seem 

to clearly and definitively limit the operating hours of the unit. Although there are descriptions in the 

statement of basis that discuss the unit will operate at less than 876 hours per year, the permit must clearly 

limit hours of operation as an enforceable permit condition in order for EPA to consider limited hours in 

determining potential to emit of the auxiliary boiler. 

Response 39:

We disagree. Condition 37 of the draft permit limits the auxiliary boiler hours of operation to 876 hours/yr. 

However, as noted in comments from APS, EPA finalized changes to MACT subpart DDDDD which revised the 

definition of limited use boiler from units that have “a federally enforceable limit of no more than 876 hours 

per year of operation” to “a federally enforceable average annual capacity factor of no more than 10 percent.” 

We have revised Condition 37 from a limit on hours of operation to a limit on capacity factor, as well as the 

associated monitoring and recordkeeping requirements. These conditions are federally enforceable, and limit 

the PTE of the auxiliary boiler to levels that assure it complies with the Boiler MACT definition of limited use 

auxiliary boiler.
FCPP SCR Project 

Response to Comments 

Page 78 of 109 

Comment 40:

(Commenters: SJCA, Stamper Report) 

The comment letter also raised issues concerning our evaluation of whether the project should have triggered 

applicability to the tribal minor NSR rule for any pollutants, as excerpted below. 

In addition to PSD applicability, the FCPP Project could also be subject to EPA’s Tribal Minor New Source 

Review (NSR) regulations at 40 C.F.R. §§49.151 – 49.161. The Tribal Minor NSR rule would only apply to those 

pollutants which do not trigger PSD for a regulated NSR pollutant. 40 C.F.R. §49.153(a)(1)(ii). For modifications 

to existing stationary sources such as the FCPP Project, applicability to the Tribal Minor NSR program is based 

on a similar applicability test as the PSD regulations Step 2, but the emission thresholds for triggering 

applicability are smaller. Specifically, for a modification to an existing major source that does not qualify as a 

major modification under PSD regulations, such modification would be subject to the Tribal NSR rules “if the 

net emissions increase from the actual-to-projected actual test” equals or exceeds the minor NSR thresholds 

listed in Table 1 of 40 C.F.R.§49.153. See 40 C.F.R. §49.153(a)(1)(ii)(A). 

EPA found that the FCPP Project was not subject to PSD for all pollutants with the exception of SAM. EPA Fact 

Sheet at 20. That means the FCPP Project is considered a minor modification for all pollutants except SAM, 

which required EPA to evaluate tribal NSR applicability for all NSR regulated pollutants except SAM. Under the 

Tribal NSR program, the next step for evaluating applicability is to determine “if the net emissions increase 

from the actual-to-projected actual test” equals or exceeds the minor NSR thresholds. See 40 C.F.R. 

§49.153(a)(1)(ii)(A) and Table 1. However, EPA did not determine the net emissions increase from the actualto-projected actual test for the FCPP Project. Instead, EPA presented the results from the actual-to-projected 

actual emissions analysis done for Step 1 PSD applicability in Table 11, but compared those changes to the 

tribal minor NSR thresholds. See Table 11 of EPA Fact Sheet at 36. For those pollutants for which EPA found 

the actual-to-future actual emissions were above the tribal minor NSR thresholds which EPA found were SO2, 

PM10 and PM2.5, EPA then purportedly evaluated the net emissions increase for those three pollutants. See 

Table 13 of EPA Fact Sheet at 36. This is not the correct applicability test under the Tribal Minor NSR rule. EPA 

should have instead determined the net emissions increase for all regulated NSR pollutants except SAM and 

compared the net emissions increase to the emission thresholds of the Tribal NSR rule. 

EPA applied the two-step applicability test of the PSD rules to its applicability determination under the Tribal 

NSR rule. The two-step test of the PSD rules is outlined in 40 C.F.R.§52.21(a)(2)(iv) and also in the definition of 

“major modification” at 40 C.F.R. §52.21(b)(2)(i), and specifically provides that a modification is a major 

modification if it results in a significant emission increase and a significant net emissions increase. Yet, the 

language of the Tribal Minor NSR rule does not read the in same manner as the PSD rules, nor does it refer to 

the applicability tests spelled out in 40 C.F.R.§52.21(a)(2)(iv). Instead, it simply states that EPA must determine 

the net emissions increase with the emission increase from the physical or operational change (i.e., the 

starting point for determining net emissions increase, pursuant to 40 C.F.R. §52.2(b)(3)(i)(a)) being based on 

the actual-to-projected actual test. In other words, there is only one step to determine if a modification is 

subject to the Tribal Minor NSR Rule, and that is based on whether the project would result in a significant net 

emissions increase greater than the significance levels of the Tribal Minor NSR Rule. Therefore, EPA should 

have evaluated the net emissions increase for all pollutants for which it found the FCPP project was not a 

major modification to determine Tribal Minor NSR applicability. 
FCPP SCR Project 

Response to Comments 

Page 79 of 109 

As discussed in previous comments, there are significant deficiencies in EPA’s analysis of net emissions 

increase for the FCPP Project in its PSD applicability analysis that EPA carried over into its analyses of net 

emissions increase for SO2, PM10 and PM2.5 for the Tribal Minor NSR applicability. Those deficiencies include 

the following: 

1) EPA cannot give credit for emissions reductions for any emissions the FCPP Units 1-3 were illegally 

emitting. 

2) EPA cannot give credit for the shutdown of FCPP Units 1-3 because the units allowable emissions are 

zero due to the BART FIP. 

3) If EPA disagrees that the BART FIP constitute enforceable limits of the applicable implementation plan 

that limit allowable emissions of FCPP Units 1-3 to zero, then no emission reduction credit for the 

shutdown can be allowed because the requirement to shutdown Units 1-3 is not enforceable as a 

practical matter. 

4) EPA failed to evaluate and include all contemporaneous emission increases at the Four Corners Units 4 

and 5. 

5) EPA did not include the potential to emit of the auxiliary boiler installed in 2012 because EPA relied on 

a purported limitation on operating hours that is not specified as an enforceable limitation in the 

applicable permit. 

EPA should refer to earlier comments for more details on those deficiencies. EPA must follow the 

requirements and associated definitions of the term “net emissions increase” in the PSD regulations to 

determine whether the minor modifications at FCPP will result in a net emissions increase over the See 40 

C.F.R.§49.152(b) (“the definitions of §52.21 of this chapter apply to the extent that they are used in this 

program” and unless otherwise defined in §49.152(d)). Thus, EPA must fully evaluate the net emissions 

increase of the FCPP Project for all pollutants that it determines are not subject to PSD applicability as a major 

modification, and such an analysis must be made available for public review and comment. Until EPA conducts 

such an analysis, its evaluation of applicability to the Tribal Minor NSR program is incomplete.

Response 40:

As noted by the commenter, we agree that for modifications at major sources the Tribal Minor NSR rule does 

not read the in same manner as the PSD rules, and does not literally prescribe the two-step, actual-toprojected actual applicability test as specified in 52.21(a)(2)(iv). Some background regarding the tribal minor 

NSR rule may be informative in responding to this comment. The tribal minor NSR rule50 primarily affects 

minor sources on tribal lands, many of which had been previously unregulated. As a result, many affected 

sources had not kept track of actual emissions, making the use of major NSR applicability tests (i.e., calculation 

of the ‘actual-to-projected actual’ or the ‘actual-to-potential’ emission increases) problematic. As a result, EPA 

proposed the use of an allowable-to-allowable-based emission test because, among other reasons, it would be 

a relatively simple test that would not rely on the existence of past actual emissions. Commenters on the 

 

50 Final rule published July 1, 2011. 76 FR 38748. 
FCPP SCR Project 

Response to Comments 

Page 80 of 109 

proposed rule noted that this allowable-to-allowable test is inconsistent with the major NSR applicability tests, 

is less stringent than the major NSR applicability tests, and that it would not capture those sources that escape 

major NSR review.51 

In the final rule, EPA retained the use of the allowable-to-allowable applicability test for minor sources, 

primarily in order to facilitate and ease the implementation of the tribal minor NSR rule for minor sources on 

tribal lands that had, to date, little experience with air regulations. EPA did not, however, finalize the use of 

this less stringent applicability test for modifications at major sources because the rationale for using an 

allowable-to-allowable test does not apply to existing major sources, which have been regulated, have 

experience with air regulations, and have been tracking past actual emissions. As a result, EPA retained the 

use of the major NSR applicability test for modifications at major sources. In the final rule, EPA specifically 

noted that “we are finalizing that the applicability of the minor NSR program to minor modifications at major 

sources be based on the actual-to-projected actual test used in the applicable major NSR program.”52 

The commenter asserts that, for modifications at existing major sources, the tribal minor NSR applicability test 

is substantially different than that required by the PSD applicability test.53 Specifically, the commenter asserts 

that the tribal minor NSR rule involves a single step, in which the net emission change, which includes projectonly emission increases and contemporaneous increases and decreases, is required. The commenter’s 

interpretation of the tribal minor NSR applicability test for modifications at existing major sources would be 

the equivalent of proceeding directly to step 2 of the PSD applicability test, in which a netting analysis is 

performed and the net emissions change is calculated. By eliminating step 1, the commenter’s interpretation 

would actually make the tribal minor NSR applicability test more onerous than the PSD applicability test, as the 

PSD applicability test only requires evaluation of the net emissions increase when the project itself causes a 

significant emissions increase under step 1. This is contrary to EPA’s stated intent, as noted above, which is to 

use the applicability test from the relevant major NSR program. We therefore disagree with the commenter’s 

assertion that calculation of the net emissions change is required for all regulated NSR pollutants not subject 

to PSD. After review of this comment we have concluded that our analysis provided in Tables 11-13 of the Fact 

Sheet, which only reviews the net emissions increase for pollutants with emission increases over the tribal 

minor NSR thresholds under step 1, is consistent with the tribal minor NSR rule, and no further analysis is 

required.54 While no pollutants triggered review under the tribal minor NSR rule, the increase in annual 

allowable emissions from the addition of new emission units (auxiliary boiler, additional truck traffic, and 

storage silos) require inclusion of these emissions units in an NSR permit. See 40 CFR 49.153(a)(2). Typically, 

this would only require an administrative amendment to the NSR permit. However, we chose to include these 

changes in this action. 

 

51 76 FR 38756 

52 76 FR 38757 

53 As described in the PSD rules, applicability for a project is determined by first calculating project-only emission increases, and 

comparing those emission increases to PSD significant emission rates (SER). For those pollutants that equal or exceed a PSD SER, the 

second step involves a netting analysis in which contemporaneous emission increases and decreases are calculated. Those 

pollutants whose project-only (step 1) emission increases are below PSD SERs are not subject to PSD. 

54 Moreover, we note that the commenter only alleges that our Tribal minor NSR applicability analysis is incomplete, not inaccurate. 

Applying the commenter’s interpretation of the Tribal minor NSR applicability test would not result in any changes to our 

applicability analysis, and unlike in previous comments regarding PSD applicability, the commenter, notably, does not make that 

assertion here. 
FCPP SCR Project 

Response to Comments 

Page 81 of 109 

SCR Project is Subject to PSD for Pollutants Other than SAM

Comment 41:

(Commenters: SJCA, Stamper Report) 

The commenter repeats points that have already been addressed in the following excerpt: 

The only pollutant that EPA has proposed to find the FCPP Project to be subject to PSD permitting 

requirements for is sulfuric acid mist or SAM. See Fact Sheet at 20. EPA determined the net emissions 

increases of SAM at the FCPP would be 233.9 tpy. See EPA Fact Sheet at 20. This analysis included deficiencies 

such as excluding demand growth heat input increases and credit for the shutdown of FCPP Units 1-3, among 

other deficiencies discussed above. Table 8 (see Stamper Report) provides the more complete future actual 

emissions of SAM for FCPP Units 4 and 5 at both EPA’s proposed SAM limit of 0.00435 lb/MMBtu and its 

proposed SAM BACT “Demonstration Limit” of 0.0025 lb/MMBtu, based on the maximum heat input projected 

by APS for 2021 (no demand growth heat input excluded). 

These projections show quite significant increases in sulfuric acid mist emissions at FCPP Units 4 and 5, not just 

greater than the 7 tpy significance level but greater than the 100 tpy major source emissions threshold even at 

EPA’s lower BACT “Demonstration” Limit for SAM. 

Of all of the various PSD requirements that should apply to this major modification of SAM, EPA only applied a 

BACT determination and emission limit for sulfuric acid mist pursuant to 40 C.F.R. §52.21(j). The PSD 

requirements not addressed by EPA’s draft permit include: the requirement for a visible emissions BACT limit 

pursuant to 40 C.F.R. §52.21(b)(4), a demonstration that the increase in SAM and resulting increase in PM10 

and PM2.5 will not cause or contribute to a violation of the NAAQS or any PSD increment pursuant to 40 C.F.R.

§52.21(k), and/or the requirement to provide an ambient air analysis along with the additional impacts 

analyses pursuant to 40 C.F.R. §52.21(o) as a result of the emissions increase in SAM and other emissions 

increases associated with the project. These requirements are discussed in detail below. 

Response 41:

These comments are addressed in greater detail in other responses. See EPA’s response to Comments 27-38, 

and 45-46. In summary, the EPA disagrees that the FCPP SCR Project triggers review for any pollutant other 

than SAM. 

SAM Emission Limit Does Not Reflect BACT

Comment 42: 

(Commenters: SJCA, Stamper Report) 

The comment letter does not agree that EPA’s proposed SAM emission limit for FCPP units 4 and 5 is BACT, as 

excerpted below. 

EPA has proposed a BACT limit for SAM of 0.00435 lb/MMBtu that will apply at Unit 4 and at Unit 5 for at least 

the first 909 days after initial startup of each SCR system. See Condition 20 of EPA’s Proposed Permit. 

Condition 21 of EPA’s proposed permit requires a lower SAM limit of 0.0025 lb/MMBtu that will apply within 

910 days of initial startup or 739 days after the initial performance test, whichever comes first. However, it is 
FCPP SCR Project 

Response to Comments 

Page 82 of 109 

not assured that this lower limit will ever apply, because Condition 31 of the Proposed Permit allows APS to 

submit a demonstration study to essentially propose an alternative SAM BACT limit that APS finds is 

achievable, and Condition 32 allows APS to, subsequent to EPA’s review of the demonstration study, revise the 

permit accordingly to set an “achievable limit.” 

EPA’s proposed BACT determination is based on the operation of a hydrated lime injection system, along with 

the existing controls at each unit including the baghouse and wet scrubber. See EPA Fact Sheet at 33. 

EPA must impose a SAM BACT limit that is no higher than the 0.0025 lb/MMBtu SAM emission rate it has 

found to be achievable for the FCPP Units 4 and 5. 

APS proposed a SAM BACT limit of 0.00435 lb/MMBtu, but EPA has proposed to find that FCPP Units 4 and 5 

could achieve a lower BACT limit of 0.0025 lb/MMBtu. See EPA Fact Sheet at 33. However, rather than 

imposing a BACT limit of 0.0025 lb/MMBtu for FCPP Units 4 and 5, EPA has proposed to impose 0.0025 

lb/MMBtu as a “demonstration limit.” Id. There is no regulatory basis for a demonstration limit in the PSD 

regulations. Instead, the definition of BACT is an emissions limitation “...based on the maximum degree of 

reduction for each pollutant subject to regulation under Act which would be emitted from any proposed major 

stationary source or major modification which the Administrator, on a case-by-case basis, taking into account 

energy, environmental, and economic impacts and other costs, determines is achievable for such source or 

modification....” 40 C.F.R. §52.21(b)(12). 

EPA has found a SAM limit of 0.0025 lb/MMBtu to be achievable at FCPP Units 4 and 5 based on a review of 

the types of information that are typically reviewed in a BACT determination – i.e., a review of SAM BACT 

limits for similar sources in the RACT/BACT/LAER Clearinghouse, permits and performance test reports, and 

control technology vendors. In fact, EPA was provided a vendor guarantee for applications similar to Four 

Corners of SAM emissions no higher than 0.0015 lb/MMBtu. EPA’s proposed finding that 0.0025 lb/MMBtu is 

an achievable BACT limit is 67% higher than the vendor guarantee rate, which would provide more than ample 

margin of compliance. Based on the controls EPA has proposed to meet SAM BACT, EPA has demonstrated 

that a SAM limit of 0.0025 lb/MMBtu or lower is achievable. 

Thus, EPA has no justification for proposing a higher SAM limit to apply for 2.5 years after installation of the 

SCR systems, or to apply for even longer if APS submits documentation to request a SAM limit higher than 

0.0025 lb/MMBtu pursuant to Condition 31 of the proposed permit. 

The PSD regulations require a permit to be issued prior to construction or modification and for such permit to 

include BACT emission limitations. 40 C.F.R. §§52.21(a)(2) and (j). The permit that EPA has proposed for FCPP 

does not impose the emission limit that EPA has found to be achievable with hydrated lime injection and the 

existing scrubber and baghouse controls. By proposing a permit with the ability to set a SAM demonstration 

limit at some later point in time, EPA is essentially issuing this PSD permit without a BACT limit for SAM, 

because it does not require compliance with the SAM limit EPA has found to be the achievable for at least 

2.5 years after installation of the SCR and maybe longer. 

Permitting authorities have to make decisions on BACT limits for new and modified sources prior to 

construction/modification and thus there is the possibility that the BACT limits the permitting authorities find 
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to be achievable may not be achievable due to the circumstances of that particular source. In such cases, the 

permit applicant, after finding that a BACT limit is not achievable despite best efforts in attempting to meet 

the limit, can request a revision to the BACT limit in the PSD permit, and EPA can then evaluate the request 

and decide to revise the BACT emission limit pursuant to public notice and comment. EPA has issued guidance 

for such a scenario in which EPA finds that a BACT determination is inappropriate in a 1987 memo referred to 

as the “Ogden Memo.” Those criteria were succinctly summarized in a recent EPA guidance statement as 

follows: 

The Ogden Memo lays out three criteria – all of which must be met – in determining whether a BACT limit can 

be revised consistent with federal PSD requirements: 

(1) The source was constructed in conformity with the permit (see 40 CFR 52.21(r)(1)); 

(2) The permitted BACT levels are inappropriate as a result of errors, faulty data, or incorrect assumptions 

contained in the permit application; and 

(3) The source investigated all available options to reduce emissions and demonstrated that compliance 

cannot be achieved. 

March 3, 2014 letter from Kate Kelly, EPA Region 10 to Stuart Clark, Washington Department of Ecology, at 1 

(Ex. 15). 

The BACT requirements of the PSD program were intended to be technology-forcing requirements. To be 

technology-forcing, EPA has set a top-down, 5 step BACT determination process to assure that the terms of 

the definition of BACT are met – that is, that BACT require the maximum degree of reduction in emissions that 

the Administrator determines is achievable for the new or modified source. By imposing the SAM limit that 

EPA has found to be achievable for FCPP Units 4 and 5, the PSD permit will motivate APS to operate the 

hydrated lime injection system in a manner to meet EPA’s BACT limit. The efficacy of dry sorbent injection 

systems for SAM control is based on the normalized stoichiometric ratio of sorbent, in this case hydrated lime, 

to flue gas volume. Generally, the higher the sorbent injection rate, the greater removal of SAM. However, the 

use of more sorbent means more expense due to the cost of the sorbent and the power to run the system and 

overcome any increased pressure drop across the baghouse. So the incentive to operate the dry sorbent 

injection system to the best of its abilities will not be there if EPA allows a less stringent SAM emission limit to 

be met for at least the first 2.5 years. 

Further, the EPA guidance on revising BACT and EAB decisions regarding BACT make clear that the burden 

needs to be on the source owner to demonstrate that other factors warrant a less stringent BACT emission 

limit than what a permitting authority found is achievable. 

Thus for all of these reasons, EPA must not impose a SAM emission limit as BACT that is any less stringent than 

the 0.0025 lb/MMBtu limit that it found to be achievable with hydrated lime injection and the existing wet 

scrubber and baghouse. In fact, lower SAM rates are achievable at FCPP Units 4 and 5 as discussed below. 

Response 42:

The EPA disagrees that the permit does not reflect BACT or that the use of a demonstration limit is not 

appropriate in this case. The commenter incorrectly asserts that the EPA concluded that 0.0025 lb/MMBtu is 

achievable for the FCPP when using DSI, baghouse, and wet scrubber. While the EPA concluded that the 
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addition of DSI in conjunction with the existing wet FGD and baghouse represented BACT, we specifically 

stated that: 

“[D]etermining the achievable SAM emission limit for the DSI systems with the existing controls 

is not as straightforward. We are not aware of a BACT determination that is the same as this 

case – retrofit at a facility using DSI and a baghouse. While there are two determinations for the 

selected control train (DSI, baghouse, and wet FGD) both of those projects were cancelled. As 

such, we must look at site-specific factors and similar facilities in making our determination.” 

Fact Sheet at 31. The EPA then described several site-specific factors, similar facilities, and vendor information 

that needed to be considered and concluded: “In this case we believe the site-specific factors and emission 

limits for similar facilities create significant uncertainty in the achievable emission limit.” Fact Sheet at 33. 

However, EPA did state in the Fact Sheet that we determined that the combination of BACT controls could 

achieve a lower SAM limit than the 0.00435 lb/MMBtu proposed as BACT by the Applicant. Fact Sheet at 33. 

As such, we are revising the final permit to set the initial upper demonstration limit at 0.0040 lb/MMBtu. This 

emission limit represents the next BACT limit (excluding cancelled projects) listed in Table 8 to the Fact Sheet, 

which summarizes SAM emissions limits established in other permits for similar, pulverized coal (PC) boiler, 

coal-fired EGUs, after 0.0025 lb/MMBtu. Accordingly, we are finalizing an emissions limit of 0.0040 lb/MMBtu 

as BACT for the combination of controls selected for this facility. 

In response to the commenter’s assertion that the EPA lacks the authority to set a demonstration limit to 

apply during the first two years of compliance, we disagree. EPA determined that there was significant 

uncertainty in the achievable limit at FCPP and explained a number of site-specific circumstances for this 

facility that differentiated it from other similarly permitted facilities. Accordingly, EPA determined that it 

would be appropriate to set a slightly higher demonstration BACT limit for two years to allow time to see if the 

control chain selected as BACT for FCPP could actually achieve the limit of 0.0025 lb/MMBtu selected as the 

long-term BACT limit, and the commenter does not address EPA’s concerns that were the basis of EPA’s 

analysis. Without the flexibility to set a demonstration limit the EPA would be forced to set a higher emissions 

limit, likely 0.0040 lb/MMBtu, which is more certain to be achievable. EPA disagrees that the Ogden memo 

referenced by the commenter should be used to set BACT limits that a reviewing authority is unsure are 

achievable. The memo states, “The BACT guidance described in this memorandum is applicable only if EPA 

finds that the BACT determination in the original permit is inappropriate.” EPA does not interpret this memo 

to guide how to make appropriate BACT determinations. The EAB has previously upheld setting emissions 

limits as we have done here when there is uncertainty over the exact emissions limit that is achievable. In Re 

Prairie State Generating Station, 13 EAD 1, 83-85 (EAB 2006)(the EAB stated: “To deal with its uncertainty 

regarding the appropriate achievable limit, IEPA established the initial limit of 0.035 lb/MMBtu but required 

this limit to be adjusted downward based on subsequent tests of Prairie State’s actual performance.”) 

While the commenter is concerned that the source will not have an incentive to operate the DSI system in an 

optimum manner, we also disagree. In order to revise the final BACT limit above 0.0025 lb/MMBtu the 

applicant must submit a demonstration study to EPA that demonstrates the applicant designed and operated 

the DSI system to achieve 0.0025 lb/MMBtu. Any revision to the limit above 0.0025 lb/MMBtu will require a 

permit revision subject to public notice and comment. The permit is designed to put a significant burden on 
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Response to Comments 

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the applicant in order to obtain a higher BACT limit. We consider these measures to be a significant enough 

hurdle to encourage the applicant to make a concerted effort to design and operate the DSI during the 

demonstration period in an optimum manner. 

The commenter’s reference to a lower BACT limit being achievable is addressed below in EPA’s response to 

Comment 43. 

Lower SAM Emission Limit is Achievable

Comment 43:

The comment letter also stated that FCPP could achieve a lower SAM emission rate than 0.0025 lb/MMBtu at 

FCPP Units 4 and 5, as excerpted below. 

As EPA found with the vendor guarantee it received from SBS TechnologyTM, lower SAM emission rates than 

0.0025 lb/MMBtu are achievable with dry sorbent technology. Yet, EPA has proposed an optimization period 

for the sorbent injection controls, with Condition 31 of the Proposed Permit that seems to imply that there 

may be concerns with FCPP Units 4 and 5’s abilities to meet PM limits or control opacity with the injection of 

hydrated lime to meet BACT for SAM. If quantity of sorbent used and associated impacts on particulate and 

opacity are the primary concerns, the first and best way to lower SAM emissions is to prevent SAM emissions. 

EPA should have thus required the use of a low SO2-to-SO3 conversion catalyst in the SCR systems as part of 

the SAM BACT determination, along with dry sorbent injection. 

Low SO2-to-SO3 conversion catalysts are widely available for SCRs. For example, the CX Series type catalyst 

developed by Babcock-Hitachi has achieved SO2-to-SO3 conversion rates as low as 0.1%. 

In estimating SAM emissions for San Juan Units 1-4 after installation of SCR, EPA assumed a 0.5% SO2 to SO3 

conversion catalyst. Such low conversion catalysts are commercially available to reduce SAM formation after 

installation of SCR. According to EPA, “[i]n a paper presented to the Proceedings of the 2006 Environmental 

Controls Conference, written by Hitachi Power Systems America, American Electric Power, and BabcockHitachi, the authors state that conversion rates as low as 0.1% have been achieved. EPA stated that it was 

being conservative in assuming a 0.5% conversion rate in determining the increase in SO4 emissions for San 

Juan Units 1-4. 

There are several examples of installed SCR systems designed for 80-90% NOx control and use of a low SO2-toSO3 conversion catalyst (i.e., less than 0.5%). 

One such example is the Seminole Generating Station, which consists of two 650 MW units burning eastern 

bituminous coal. The Seminole SCR systems were designed for 90% NOx reduction and low SO2 conversion 

(<0.5%), and required to meet an outlet NOx rate of 0.04 lb/MMBtu. Performance testing at Seminole 

indicated the SCR systems significantly outperformed their NOx removal guarantees of 90.3%, from 0.413 

lb/MMBtu to 0.04 lb/MMBtu. Ammonia slip, guaranteed at 2 ppm, was measured at 0.2 ppm. The SO2 

oxidation was guaranteed at 0.5% and measured at less than 0.1% across the entire SCR system. The system 

pressure drop was less than 5 inches of water, well under the guaranteed value. 
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Morgantown Units 1 and 2 are 642 MW boilers that burn high sulfur (3%) eastern bituminous coal. An SCR was 

installed in 2007-2008, designed to remove 92.5% of the NOx from an inlet NOx of 0.6 lb/MMBtu at maximum 

load to an outlet of 0.045 lb/MMBtu and an SO2 oxidation rate of 0.5% and 2 ppm ammonia slip. 

The Cope Generating Station burns bituminous coal. The SCR was designed to reduce the NOx from an outlet 

of 0.32 lb/MMBtu to 0.032 lb/MMBtu, based on 90% NOx reduction. The guaranteed SO2 oxidation was 1% at 

688 F. Although the SCR was only guaranteed a 1% SO2 to SO3 oxidation rate, performance tests 

demonstrated NOx removal at 91.6% with an average SO2 to SO3 oxidation rate of 0.3%. 

APS assumed a 1% SO-to-SO3 conversion rate across the planned 3+1 SCR catalyst design. See April 2014 PSD 

Permit Application at 4-15. Clearly, there are lower oxidation catalysts and the available documentation 

indicates that high levels of NOx removal can be met with these catalysts. EPA even found a vender that 

claimed a catalyst conversion of 0.1%. EPA Fact Sheet at 23. 

Moreover, for the EPA’s NOx BART determination for Four Corners Power Plant, EPA assumed an SO2-to-SO3 

conversion rate of no more than 0.6%. This was based on information regarding the FCPP from Hitachi Power 

Systems America, in which Hitachi guaranteed a total 0.5% conversion of SO2 to SO3 over 3 layers of CX series 

catalyst, or 0.167% per catalyst layer. EPA assumed 0.6% SO2 to SO3 conversion to reflect the average 

conversion from 3 and 4 layers of catalyst, because after an initial 16,000 hours, an additional layer of catalyst 

will be used. And Hitachi stated this conversion rate could be guaranteed while controlling NOx by 80-90%. 

Based on a comparison of current NOx rates of approximate 0.5 lb/MMBtu to the 0.098 lb/MMBtu NOx BART 

limit of EPA’s FIP, the SCR systems at FCPP Units 4 and 5 will have to achieve about 80% control to comply with 

EPA’s FIP limit. Because EPA’s NOx BART modeling was based on assumed emission rates of sulfuric acid mist 

which in turn were based on no more than 0.6% conversion of SO2-to-SO3 across the SCR system, EPA must 

impose use of a low SO2-to-SO3 conversion catalyst of no more than 0.6% across the SCR systems in the PSD 

permit for FCPP Units 4 and 5 along with hydrated lime injection as part of the SAM BACT requirements. 

With a required 0.6% maximum SO2-to-SO3 conversion catalyst and a dry sorbent injection system, FCPP Units 

4 and 5 should be able to readily meet EPA’s 0.0025 lb/MMBtu BACT limit. 

Response 43: 

The EPA disagrees that the achievable BACT limit should consider the use of a 0.6% conversion catalyst, and 

therefore, not require an initial demonstration limit. The commenter is referred to the EPA’s Fact Sheet and 

response to Comment 24, which detail how the EPA fully considered a lower SO2 to SO3 conversion catalyst in 

the BACT analysis. The EPA’s determination was not based on the technical feasibility of lower conversion 

catalyst, but on economic and environmental impacts. These issues were discussed in EPA’s Fact Sheet and the 

comment has not indicated how that discussion is incorrect. 

EPA’s BACT determination must consider the ability of the emissions unit to achieve BACT at all times under 

numerous operating conditions. The commenter’s information regarding the achieved conversion rates at 

other sources, does not alleviate our concerns related to other factors affecting SAM emissions from the FCPP, 

discussed in detail in the Fact Sheet, and not addressed by the commenter. Fact Sheet at 31-33. The EPA 

acknowledges there are many factors that indicate that a limit lower than the 0.00435 lb/MMBtu proposed by 

the Applicant is achievable at FCPP. But, there are also factors that indicate a BACT limit higher than 0.0025 
FCPP SCR Project 

Response to Comments 

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lb/MMBtu may be more appropriate for this facility. On the whole, the combination of factors that could 

cause emissions to be higher or lower does not provide sufficient evidence that 0.0025 lb/MMBtu is 

achievable at FCPP at this time. EPA must either allow for an initial demonstration period with a slightly higher 

BACT period in order to provide time to determine whether 0.0025 lb/MMBtu is in fact achievable for the 

combination of controls at this particular facility or set a higher BACT limit that would apply for the life of the 

permit. The use of an initial demonstration period has the ability to result in more overall emission reductions 

than if EPA sets a higher limit and does not allow for a demonstration period. 

Visible Emission Standard

Comment 44:

(Commenters: SJCA, Stamper Report) 

The comment letter states that EPA must impose a visible emissions limit reflective of BACT as part of the SAM 

BACT determination, as excerpted below. 

Sulfuric acid mist emitted from a stack creates visible emissions and thus can impact opacity. During 

combustion of coal, the majority of the sulfur in the coal (95-97%) reacts to form SO2 and the remainder 

forms SO3. SCR systems also can generate more SO2 through the oxidation of SO2 to SO3 across the SCR 

catalyst, as has been discussed above. Sulfuric acid mist then forms in two ways: 1) There is a reaction 

between water vapor and SO2 forming liquid droplets. 2) Sulfuric acid vapor in the gas phase may form 

sulfuric acid mist when the gas stream temperature is lowered below the dew point of H2SO4. These droplets 

and mists are particulate matter and the droplet diameter can be quite fine, below 2.5 microns. These 

droplets can negatively impact opacity. The plume from sulfuric acid mist is typically a blue or brown-orange 

plume. 

BACT is defined to mean an emissions limitation “(including a visible emission standard)” based on the 

maximum degree of reduction for each pollutant the Administrator finds is achievable considering the various 

factors that go into a BACT determination. 40 C.F.R. §52.21(b)(12). While EPA has proposed a BACT emission 

limit for SAM, EPA has not proposed any corresponding visible emission limit reflective of BACT. Given that 

sulfuric acid mist emitted from the stack can contribute to opacity, it is imperative that EPA set an opacity limit 

reflective of BACT for FCPP Units 4 and 5. Not only is an opacity BACT limit required, but will serve the 

important purpose of assuring proper operation of the DSI system. With the use of continuous opacity 

monitoring systems (COMS) as the compliance method, an opacity BACT limit can provide for virtually 

instantaneous information as to whether the dry sorbent injection system and baghouse are being operated in 

a manner consistent with good air pollution control practices for sulfuric acid mist control. 

The existing opacity limits for FCPP Units 4 and 5 (in 40 C.F.R.§49.5512(d)(4) and (h)(2)) of 20% with one six 

minute period per hour of up to 27% and with exemptions for startup and shutdown do not reflect BACT. First, 

BACT is required to be met on a continuous basis and thus no exemptions are allowed from BACT limits. 

Second, opacity limits of 10% have commonly been required to meet BACT for coal-fired EGUs with 

baghouses. EPA required a 10% opacity limit as BACT for the proposed Desert Rock power plant, which was 

planned for northwestern New Mexico, would burn similar coal to FCPP and be equipped with similar controls 

including DSI and baghouse. Other examples of 10% or lower opacity BACT limits include the MidAmerican 
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Response to Comments 

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Walter Scott, Jr., Unit 3 in Council Bluffs, Iowa, which is subject to an opacity limit of 10 percent, and the Plum 

Point facility in Osceola, Arkansas, which is subject to a BACT limit of 10 percent opacity. 

In summary, the proposed PSD permit for FCPP Units 4 and 5 is deficient because EPA has not proposed a 

visible emission limit that is reflective of BACT for FCPP Units 4 and 5. EPA must determine an appropriate 

visible emissions BACT limit, and make its determination available for public review and comment. 

Response 44:

We interpret the commenter’s reference to a “visible emissions BACT limit” to be the same as requesting an 

opacity limit. EPA is not aware of any visible emissions limit other than an opacity limit and the commenter 

appears to use the two terms interchangeably. We disagree that an opacity limit is required as BACT in 

conjunction with the SAM BACT emission limit. The definition of BACT cited by the commenter does not 

require the establishment of an opacity limit as BACT. It simply indicates that such a standard can be 

established as BACT even though it is not a numerical emission limit. As noted by the commenter, EPA and 

state/local permitting authorities have established opacity standards as part of certain BACT limits. However, 

the permits cited by the commenter, for example, establish opacity standards in conjunction with PM10 BACT 

limits, and the commenter has not identified any PSD permit issued with BACT limits that include opacity limits 

for SAM emissions. There is an established relationship between particulate emissions and opacity.55 Although 

opacity is not considered a surrogate for measuring particulate matter emissions, an opacity BACT limit can 

provide a greater assurance of compliance with particulate matter BACT limits. 

EPA promulgated a FIP for FCPP in 2007. 87 FR 25698, 25701 (May 7, 2007).The FIP included an opacity limit of 

20% on Units 4 and 5 to provide greater assurance of compliance with the emissions limit for PM and we 

retained both the opacity limit and emissions limit in the BART FIP in 2012.56 Thus, to the extent the 

commenter is concerned about FCPP’s compliance with its PM emissions limits rather than BACT for SAM, 

there is already an opacity limit in place and enforceable for FCPP. A more thorough discussion of our opacity 

limit is contained in the 2007 Regional Haze BART FIP.57

We agree that SAM can form PM2.5 emissions. We have accounted for this conversion in our emission 

calculations, in which we express a fraction of SAM as PM2.5. As discussed in our Fact Sheet, this project does 

not trigger PSD review for PM10 or PM2.5, and does not require the establishment of a particulate matter BACT 

limit. Because a particulate matter BACT limit is not being established, we do not consider it necessary to 

establish an opacity standard as BACT in conjunction with particulate matter emissions, as was done in the 

permits cited by the commenter and as we did in our 2007 FIP for purposes other than BACT. 

There is no relationship between direct SAM emissions and opacity. Direct SAM emissions are a visibility 

concern to the extent that they can form PM2.5 emissions, as noted by the commenter. As we discussed in 

our Fact Sheet: 

 

55 Page 7-16, Introduction to Visibility, William C. Malm, National Park Service, Air Resources Division, May 1999 

56

 “EPA is determining the 20 percent opacity limit that we promulgated in our 2007 FIP for FCPP as being adequate to ensure 

continuous compliance with the PM BART limit or 0.015lb/MMBtu” 77 FR at 51637 (Aug. 24, 2012). 

57 See EPA Docket Item No. EPA-R09-OAR-2010-0683-0234, Four Corners Power Plant Final Rulemaking – Response to Comments, 

Section 8.2 “Comments on the Proposed BART determination for PM.”
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Fine plume problems are expected to occur when SAM vapor or aerosol concentrations leaving 

the ESP or the wet FGD exceed the equivalent of 2 ppmv. These concentrations have the 

potential to form aerosols in the plume that will have an adverse effect on plume visibility and 

appearance [fn53] – which could then lead to adverse health effects. In this case, the 

Applicant’s proposed SAM emission rate of 0.00435 lb/MMBtu is equivalent to 1.5 ppmv, and 

our proposed limit is equivalent to 0.86 ppmv. Given that the Project’s emissions will be well 

below 2.0 ppmv with either proposed limit, we have concluded there will not be adverse visible 

plume effects.... 

EPA Fact Sheet at 34 

As a result, we consider the 0.0040 lb/MMBtu SAM BACT demonstration limit being finalized in the permit to 

be sufficiently stringent to prevent opacity issues resulting from SAM conversion to PM2.5, and do not consider 

establishment of a separate opacity standard to provide additional environmental benefit. We note that the 

commenter has challenged our statement regarding adverse visible plume effects in a later comment (see 

comment 47). As discussed in further detail in our response to that comment, the information raised by the 

commenter is not relevant to SAM emissions, and does not actually raise any issues regarding our use of the 2 

ppmv sulfuric acid concentration. 

Finally, we disagree with the commenter’s assertion that establishing a 10% opacity limit as BACT for SAM will 

provide additional assurance of proper operation of the DSI system. As noted by the commenter, the current 

title V permit and the BART FIPs require Units 4 and 5 to comply with a 20% opacity limit. Since we do not 

expect any increase in visible emissions as a result of the FCPP SCR Project, a lower opacity limit is not 

necessary as the permit already contains sufficient monitoring of the DSI system. Further, EPA considered and 

rejected lowering the opacity limit to 10% during promulgation of the 2012 BART FIP. EPA rejected comments 

that a 10% opacity limit would provide greater assurance that Units 4 and 5 would be meeting the PM 

emissions limit of 0.015 lb/MMBtu. Among other reasons, EPA noted that several national rules for coal-fired 

EGUs had considered but rejected a 10% opacity standard.58 77 FR at 51637. As a result, the source is already 

required by the conditions of the 2007 FIP, 2012 FIP and existing title V permit to collect continuous opacity 

data via a continuous opacity monitoring system (COMS) in order to demonstrate compliance with the existing 

opacity limit. Because the COMS is already in place, a more stringent 10% opacity limit will not result in 

additional opacity data collection. In addition, this PSD permit requires monitoring of the operation of the DSI 

system itself, which we consider to provide a better assurance of good operational DSI practice than the use of 

opacity monitoring as a surrogate which is a combination of PM emissions and not just direct SAM emissions. 

Specifically, the final PSD permit requires the permittee to monitor DSI lime/reagent injection rates during the 

initial performance test and establishes the rate observed during the performance test as an operating 

 

58 “Specifically, EPA’s [sic] revised the New Source Performance Standard for large electric generating units at 40 CFR Part 60, 

Subpart Da, to lower the PM emissions limit for new units to 0.09 lb/MMBtu for gross energy output or 0.097 lb/MMBtu for net 

energy output. For existing units that reconstruct or modify, Subpart Da establishes an emissions limit of 0.015 lb/MMBtu. For both 

standards, EPA retained a 20 percent opacity standard as being sufficient to ensure compliance with either the 0.090 (0.097) 

lb/MMBtu or 0.015 lb/MMBtu PM emission limit. EPA’s MATS rule, which was finalized just a few months ago, also retained a 20 

percent opacity standard as being sufficient to ensure compliance with the PM emission limit that will be required for electric 

generating units subject to that rule.” 77 FR at 51637 (Aug. 24, 2012).
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Response to Comments 

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restriction. This prevents the facility from injecting excessive amounts of reagent to ensure compliance with 

SAM limits. 

Ambient Air Impact Analysis

Comment 45:

(Commenter: Stamper Report) 

The commenter contends that the EPA must perform or require an ambient impact analysis as a result of the 

FCPP project, as excerpted below. 

EPA stated in the FCPP PSD Permit Fact Sheet that: “[t]he FCPP SCR Project does not trigger the PSD program 

for any pollutant with a NAAQS or PSD increment. Therefore, this analysis is not required for this permitting 

action.” However, as discussed above, sulfuric acid mist is particulate matter. It is condensable particulate 

matter, often in the 2.5 diameter size or smaller when emitted from a coal-fired boiler. 

In a Fact Sheet issued with its March 16, 2012 proposed clarifying amendments to the definition of “Regulated 

NSR Pollutant” regarding condensable particulate matter (77 Fed.Reg. 15656), EPA states: 

Condensable particulate matter is not directly measured as a solid or liquid at the stack. Instead 

gaseous emissions such as sulfuric acid mist, ammonium sulfate, and certain metal vapors 

condense upon cooling and dilution in the ambient air to form solid or liquid particles following 

discharge from the stack. 

. . . 

Condensable particulate matter emissions contribute to monitored levels of PM2.5 and PM10. 

EPA Fact Sheet, Implementation of the New Source Review (NSR) Program for Particulate Matter Less than 2.5 

Micrometers (PM2.5): Amendment to the Definition of “Regulated NSR Pollutant” Concerning Condensable 

Particulate Matter (Ex. 27) [emphasis added]. 

The final revised definition of “regulated NSR pollutant” reads in pertinent part: 

Regulated NSR pollutant...means the following: 

(i) Any pollutant for which a national ambient air quality standard has been promulgated. This 

includes, but is not limited to, the following: 

(a) PM2.5 emissions and PM10 emissions shall include gaseous emissions from a source 

or activity, which condense to form particulate matter at ambient temperatures. On or after 

January 1, 2011, such condensable particulate matter shall be accounted for in applicability 

determinations and in establishing emission limitations for PM2.5 and PM10 in PSD permits. . . . 

40 C.F.R. §52.21(b)(50)(i)(a). 

It must be noted that the source impact analysis of the PSD regulations are not limited to only those pollutants 

for which the modification is considered major. While the BACT requirements are written to apply only “for 
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Response to Comments 

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each regulated NSR pollutant for which it would result in a significant net emissions increase” (see 40 C.F.R. 

§52.21(j)(3)), the source impact analysis is not written with such limitations: 

(k) Source impact analysis—(1) Required demonstration. The owner or operator of the 

proposed source or modification shall demonstrate that allowable emission increases from the 

proposed source or modification, in conjunction with all other applicable emissions increases or 

reductions (including secondary emissions), would not cause or contribute to air pollution in 

violation of: 

(i) Any national ambient air quality standard in any air quality control region; or 

(ii) Any applicable maximum allowable increase over the baseline concentration in any area. 

40 C.F.R §52.21(k). 

Thus, EPA must require an analysis of the allowable emissions increases from the FCPP Units 4 and 5 project 

on the PM10 and PM2.5 NAAQS and PSD increments pursuant to 40 C.F.R. §52.2(k). 

Response 45: 

We disagree with the commenter’s assertion that an ambient air quality impact analysis is required in this case 

for PM10 and PM2.5. 

First, we disagree with the commenter’s assertion that “the source impact analysis of the PSD regulations are 

not limited to only those pollutants for which the modification is considered major.” Under 52.21(m)(1)(i)(b) 

of EPA’s regulation, a permit application need only contain an analysis of ambient air quality for each pollutant 

for which a modification “would result in a significant net emission increase.” The commenter is correct that 

the text of §52.21(k) itself does not contain language that explicitly limits the required demonstration to those 

pollutants that trigger PSD review (i.e., for which the modification is major). However, the reason that an 

ambient air quality analysis is not required for pollutants emitted below the significant emission rates in 

52.21(b)(23) is because the significance levels represent a level of increase that EPA has determined to have a 

de minimis impact on air quality. A showing that a modification increases the rate of emissions of a particular 

pollutant by less than the levels in 52.21(b)(23) is thus sufficient to demonstrate that the modification will not 

cause or contribute to a violation of the NAAQS or increment for that pollutant. Furthermore, consistent with 

52.21(m)(1)(I) the preamble to the 1980 PSD final rule states in multiple instances that the requirements of 

the PSD program only apply to pollutants that are subject to PSD (i.e., pollutants whose net emission increases 

are greater than the de minimis amounts).59,60 As discussed in our Fact Sheet, this project does not result in a 

 

59 “Once a source applicant has determined that proposed construction falls under PSD based on the above size and location tests, It 

must then assess whether the pollutants the project would emit are or are [not] subject to PSD. [...] PSD review applies to all 

significant emissions increases of regulated air pollutants. Specific numerical cutoffs which define what emissions increases are 

‘significant’ have been spelled out in the regulations. These pollutant specific cutoffs can exempt a source from PSD review for a 

particular pollutant, except where the proposed construction would adversely impact a Class I area” 45 CFR 52677 

60 “C. Pollutant Applicability. [...] The Administrator agrees that requiring review for a net emissions increase in any pollutant subject 

to regulation under the Act is consistent with the Alabama Power decision. Consequently, EPA is promulgating a final rule that 

requires PSD preconstruction review for net emissions increases in greater than de minimis amounts at a major stationary source 

for any pollutant subject to regulation under the Act emitted by the source, regardless of whether the source is major for the 

pollutant.” 45 CFR 52699 
FCPP SCR Project 

Response to Comments 

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significant net emissions increase in PM10 or PM2.5 emissions. In fact, the project causes a net emissions 

decrease in PM10 and PM2.5 emissions. 

In addition, as described previously in response to Comment 44, we agree that SAM can form particulate 

matter, such as PM2.5. However, we disagree with the commenter’s characterization that “sulfuric acid mist is 

particulate matter”, which implies that the pollutants are interchangeable. We have accounted for this 

conversion in our emission calculations, in which we express a fraction of SAM as PM10 and PM2.5.

61 To the 

extent that PSD review is triggered for particulate matter, it is based on the quantity of particulate matter 

emissions, and not the quantity of SAM emissions. 

Although there are no NAAQS or increment for SAM concentrations that can be considered by EPA in the 

context of making the demonstration required under 52.21(k), EPA has conducted an air quality analysis for 

SAM consistent with section 52.21(m)(1)(i)(b). See the response to comment 11. 

Comment 46:

(Commenter: Stamper Report) 

The commenter also contends that an ambient air quality analysis is required, as follows: 

In addition, an ambient air quality analysis should be required under the additional impacts requirements of 

the PSD rules. This provision requires the following analysis be done as part of the PSD permit issuance: 

(o) Additional impact analyses. (1) The owner or operator shall provide an analysis of the 

impairment to visibility, soils and vegetation that would occur as a result of the source or 

modification and general commercial, residential, industrial and other growth associated with 

the source or modification. The owner or operator need not provide an analysis of the impact 

on vegetation having no significant commercial or recreational value. 

(2) The owner or operator shall provide an analysis of the air quality impact projected for the 

area as a result of general commercial, residential, industrial and other growth associated with 

the source or modification. 

40 C.F.R. §52.21(o). 

As shown above, 40 C.F.R. §52.21(o)(2) requires an analysis of the air quality impacts of the modification in 

conjunction with the industrial or other growth associated with the modification. EPA has stated that a source 

impact analysis would potentially be required for increases of PM emissions, even though there is no NAAQS 

for PM: 

While there are no air quality standards (NAAQS or increments) associated with ‘‘particulate 

matter emissions,’’ section 165(e)(3)(B) of the CAA requires an analysis of the ambient air 

quality, climate, meteorology, terrain, soils and vegetation, and visibility ‘‘for each pollutant 

regulated under this Act’’ that will be emitted by the proposed PSD project. This requirement, 

 

61 We note that the commenter has not raised any issues with our calculation methodology. 
FCPP SCR Project 

Response to Comments 

Page 93 of 109 

referred to as the ‘‘Additional Impact Analysis’’ at 40 CFR 51.166(o) and 40 CFR 52.21(o), could 

potentially require certain analyses with regard to ‘‘particulate matter emissions’’ as part of the 

PSD preconstruction review process. 

77 Fed.Reg. 65113 (October 25, 2012). 

Along the same lines as EPA’s statements quoted above regarding PM emissions, although there is no NAAQS 

for sulfuric acid mist, SAM is a component of PM10 and PM2.5 for which there are NAAQS and PSD 

increments. EPA has stated that sulfuric acid mist and other condensable particulate matter contribute to 

monitored concentrations of PM10 and PM2.5. Therefore, EPA must require an ambient air analysis for PM10 

and PM2.5 under 40 C.F.R. §52.21(o) and also under 40 C.F.R. §52.21(k). 

There are other increases in PM10 and PM2.5 which must be considered in such modeling. Those include: 

· Truck traffic due to the delivery of reagent for the dry sorbent injection system and due to the delivery 

of urea pellets, 29% aqueous ammonia, or anhydrous ammonia. 

· A new pneumatic dry sorbent truck unloading system and silo. 

· A new pneumatic urea pellet truck unloading system or a new ammonia truck unloading station and 

storage tank will be installed. 

April 2014 PSD Permit Application at 2-1. 

Response 46: 

For the reasons discussed in the previous response to comment (Comment 45), we disagree that ambient air 

quality analyses are needed for PM10 and PM2.5. Those reasons similarly apply to the commenters arguments 

based on 52.21(o) of the regulations. Because there is no significant net emissions increase in PM10 and PM2.5

from the project, any impact on air quality from PM10 or PM2.5 emissions is considered de minimis. EPA may 

reasonably concluded from this premise that PM10 and PM2.5 emissions will not have an adverse impact on 

soils, vegetation, and visibility. Further, as identified in our 52.21(o) analysis in the Fact Sheet, the 19,000 tpy 

decrease in NOX emissions will offset any potential impacts on visibility, soils, or vegetation. See Fact Sheet, at 

Section 8. Modeling is unnecessary to reach this conclusion. The commenter has not provided information to 

demonstrate that any analysis other than an ambient air quality analysis is needed in this instance to assess 

impacts on soils, vegetation, and visibility. We note our analysis include the emission increases in PM10 and 

PM2.5 identified by the commenter. 

EPA’s Fact Sheet also discussed the FCPP SCR Project’s impacts on growth, and determined that there will not 

be increases in air pollution impacts due to growth associated with this project. See Fact Sheet, Section 8. 

Particulate Matter and Visibility Impact Analysis

Comment 47:

(Commenter: Stamper Report) 

The commenter also states that the PSD permit triggers a visibility impact analysis, as excerpted below. 
FCPP SCR Project 

Response to Comments 

Page 94 of 109 

Particulate matter and plume visibility modeling performed for the March 2014 Draft EIS indicate possible 

NAAQS exceedances and extreme visibility impacts. EPA should perform particulate matter modeling, and 

reconsider its finding that the Four Corners Project will not adversely impact visibility. 

Modeling of PM10 and PM2.5 impacts was conducted for the March 2014 Draft Environmental Impact 

Statement for the Four Corners Power Plant and Navajo Mine Energy Project. That modeling showed a total 

24-hour average PM2.5 NAAQS concentration of 33.33 μg/m3 which is quite close to the 24-hour average 

PM2.5 NAAQS of 35 μg/m3. In comments submitted on the DEIS by the Western Environmental Law Center, 

several deficiencies were found in that modeling that would likely underestimate PM2.5 concentrations. Thus, 

it is imperative that EPA require a PM2.5 NAAQS modeling analysis, as well as a PM10 modeling analysis, that 

complies with EPA’s modeling guidelines for the FCPP Project to evaluate whether the FCPP Plant as modified 

will cause or contribute to a violation of the NAAQS. 

40 C.F.R. §52.21(o) requires additional impacts analyses to be conducted as part of the PSD Permit for Four 

Corners Power Plant. That analysis includes an analysis of the impairment to visibility in the vicinity of the 

source. This requirement is separate from the requirement to evaluate impacts on air quality related values 

(AQRVs) including visibility in Class I areas. 

EPA found that the Four Corners Project would not adversely impact visibility. See EPA Fact Sheet at 1. EPA 

based this conclusion on the following claim: 

Fine plume problems are expected to occur when SAM vapor or aerosol concentrations leaving 

the ESP or the wet FGD exceed the equivalent of 2 ppmv. These concentrations have the 

potential to form aerosols in the plume that will have an adverse effect on plume visibility and 

appearance [fn53] – which could then lead to adverse health effects. In this case, the 

Applicant’s proposed SAM emission rate of 0.00435 lb/MMBtu is equivalent to 1.5 ppmv, and 

our proposed limit is equivalent to 0.86 ppmv. Given that the Project’s emissions will be well 

below 2.0 ppmv with either proposed limit, we have concluded there will not be adverse visible 

plume effects.... 

EPA Fact Sheet at 34. 

Plume visibility modeling was done for the March 2014 Draft Environmental Impact Statement for the Four 

Corners Power Plant and Navajo Mine Energy Project. As discussed in a report attached to the Western 

Environmental Law Center’s June 27, 2014 comments on the Draft EIS, “plumes from Units #4 and #5 are likely 

to be visible at nearly every vista. The plume visibility modeling in the Draft EIS even reports that many vistas 

are likely to experience even more extreme visibility impacts compared to those which occur under current 

emissions.” A limit on ammonia slip was suggested to help minimize the predicted degradation in visibility. 

Clearly, the modeling analysis of visibility impacts done for the EIS shows the opposite of EPA’s finding. EPA 

must consider this modeling in making any determinations on visibility impacts from the FCPP Project. 
FCPP SCR Project 

Response to Comments 

Page 95 of 109 

Response 47:

We disagree with this comment. The dispersion modeling performed for the March 2014 Draft EIS included 

the total source-wide potential emissions of PM10 and PM2.5. The scope of the Draft EIS particulate matter 

modeling is much larger than the scope of this permitting action, which is the preconstruction review of SCR 

installation on Units 4 and 5 and its associated emission increases. 

The Draft EIS results are therefore not an accurate representation of the air quality impact of this permitting 

action. The particulate matter results in the Draft EIS do not provide useful information regarding whether or 

not permitting the construction and operation of an SCR on units 4 and 5 will cause or contribute to a NAAQS 

violation. As noted in our response to Comment 45, this project does not require PSD dispersion modeling for 

particulate matter, and there will be a net decrease in PM10 and PM2.5 emissions relative to pre-project 

emission rates. We also note that this action is not subject to NEPA, as discussed above in several responses. 

Similarly, the plume visibility modeling performed for the March 2014 Draft EIS modeled the total source-wide 

potential emissions of NOX, SO2, and particulate matter. Again, the scope of the Draft EIS modeling is therefore 

much larger than the scope of this permitting action, which involves only a significant net emissions increase 

of SAM. As a result, we do not consider the Draft EIS plume visibility modeling results to provide useful 

information regarding whether or not emissions increases that result from installing SCR on units 4 and 5 will 

result in adverse visibility impacts. As noted by the commenter, we indicated in our Fact Sheet that adverse 

effects on visibility can be expected with SAM exhaust concentrations above 2.0 ppmv. Both the SAM BACT 

limit and demonstration limit ensure SAM exhaust concentrations will be below this level, and the commenter 

has not raised any specific concerns regarding this issue. 

Comment 48: 

(Commenter: Stamper Report) 

EPA must consider ammonia slip limits in the FCPP PSD permit to minimize adverse visibility impacts. This 

modeling analysis also shows the importance of EPA imposing a visible emissions limit with COMS as the 

compliance method. An opacity limit reflective of BACT and compliance by continuous monitoring will be the 

best method to ensure proper operation of the DSI system to minimize SAM emissions so that visibility is not 

degraded by the FCPP Project. 

Response 48:

As noted in response to Comment 44, we disagree that an ammonia slip and/or opacity standard is needed in 

the FCPP PSD permit to minimize adverse visibility impacts. FCPP has an existing 20% opacity standard, 

measured using a COMS, and FCPP must continue to meet this standard after the installation of the FCPP SCR 

Project. We again emphasize that the FCPP SCR Project, will improve visibility through significant reductions in 

NOX emissions based on installation and operation of SCR. In addition, the SAM BACT limits in the final permit 

are not expected to cause in any increase in visible emissions from the stack.

Reference in Permit to Part D of the Act

Comment 49:

(Commenter: APS) 
FCPP SCR Project 

Response to Comments 

Page 96 of 109 

The cover page states that the permit is being issued “pursuant to the provisions of the Clean Air Act (CAA) in 

Subchapter I, parts C and D ...." Part D governs major NSR permits for nonattainment pollutants. Since Four 

Corners is located in an area designated as "in attainment" or “unclassifiable" for all criteria pollutants, this 

permit is a Part C, PSD permit and is not being issued under Part D. APS requests that EPA remove the 

reference to Part D of section 110(a) from the permit. 

Response 49:

The EPA agrees with this comment, and has revised the final permit accordingly. Part D of the Clean Air Act 

refers to requirements for nonattainment areas and this permit does not address nonattainment area 

requirements. 

Emission Unit Identifiers

Comment 50:

(Commenter: APS) 

The equipment list on page 2 of the permit identifies the emission units, construction date, description, and 

control equipment authorized by the permit. Included in the equipment list are identifiers for the emission 

units (e.g., EU4 and EU5). The emission unit identifiers in the proposed PSD permit are inconsistent with the 

existing Title V permit. APS suggests using the following emission unit identifiers: 

1. B4 - Electric Steam Generating Unit #4 

2. B5 - Electric Steam Generating Unit #5 

3. EU60 - Truck Traffic for Sorbent Delivery 

4. EU61 -Truck Travel for SCR Reagent Delivery 

5. EU1 - Pneumatic Delivery System and Storage Silo for Hydrated Lime 

6. EU2 - Pneumatic Delivery System and Storage Silo for SCR Reagent 

7. AUX A-01 - 220 MMBtu/hr Natural Gas-Fired Boiler 

Response 50:

The EPA agrees with the suggested revisions in order to the make the emission unit identifiers consistent with 

the title V permit, and has revised the final permit accordingly. 

Startup, Shutdown, and Malfunction

Comment 51:

(Commenter: APS) 

The comment letter contains the following discussion: 

EPA explains in Condition 4.c that “[c]compliance with the malfunction notification requirements in 

Condition 4 shall not excuse or otherwise constitute a defense to any violation of this permit or any law or 

regulation such malfunction may cause." EPA presumably included this condition as a result of the Agency's 

recently published supplemental proposal to amend provisions applying to excess emissions during periods of 

startup, shutdown, and malfunction (SSM SIP Call). Without opining as to the appropriateness or validity of 

EPA's revised interpretation of the CAA set forth in the SSM SIP Call, APS believes EPA must account for 
FCPP SCR Project 

Response to Comments 

Page 97 of 109 

emissions from malfunction events through either the establishment of alternative numerical emission 

limitations applicable to such emissions or appropriate work practice standards. 

A malfunction is defined as “a sudden and unavoidable breakdown of process or control equipment." By 

definition, such events could not have been foreseen, avoided, or planned for. Moreover, they are “beyond 

the reasonable control of the operator" and will occur despite careful and prudent planning by the operator, 

and regardless of the fact that the operator maintained and operated the pollution control equipment in a 

manner consistent with good practice for minimizing emissions. See EPA's Policy on Excess Emissions during 

Malfunctions, Startup, and Shutdown (Aug. 11, 1999) [hereinafter “SSM Policy"]. Accordingly, it is necessary 

that EPA somehow account for malfunctions, either by establishing an alternative emission rate or work 

practice standards applicable during those periods when emission limitations cannot be met as a result of 

malfunctions. No purpose is served by establishing an emission limitation under circumstances where 

specified emission reductions cannot be achieved due to circumstances entirely out of the operator's control, 

despite its best efforts to comply. The Act defines “emission limitation" (used in§ 110, §165, and elsewhere) 

and “emission standard" (used in § 111) to mean: 

a requirement established by the State or the Administrator which limits the quantity, rate, or 

concentration of emissions of air pollutants on a continuous basis, including any requirement 

relating to the operation or maintenance of a source to assure continuous emission reduction, 

and any design, equipment, work practice or operational standard promulgated under this 

chapter. 

CAA § 302(k) (emphasis added). 

Thus, the CAA clearly authorizes permitting agencies to impose work practices standards, which are “emission 

limitations" under the Act. Provided APS can satisfy its burden of proof by demonstrating that it has met all of 

the conditions necessary to assert an affirmative defense for exceeding an applicable emission limitation due 

to a malfunction, work practice standards (or alternative numerical emission limitations) should apply during 

such period. These work practice standards would require APS to do the following: 

· Repair the equipment giving rise to the malfunction in as expeditious manner as practicable after 

learning that the applicable emission limitations are being exceeded; 

· Minimize, to the maximum extent practicable, the amount and duration of the excess emissions 

(including any bypass) during the malfunction event; 

· Take all reasonable steps to minimize the impact of the excess emissions on ambient air quality; 

· Keep, to the extent practicable, all emission monitoring systems in operation; 

· Document APS's actions in response to the excess emissions by contemporaneous records; and 

· Properly and promptly notify EPA of the excess emissions and malfunction event. 

Response 51:

EPA disagrees with the comment. The comment contends that EPA is required to establish either an 

alternative numerical emissions limit or work practice standard for SAM emissions during a malfunction event. 

However, the FCPP PSD Permit establishes a BACT emission limit for SAM that applies at all times, including 

during a malfunction event. BACT, by definition, is an emissions limitation that applies on a continuous basis. 

EPA has long recognized that the BACT requirement continues to apply during periods of startup, shutdown, 

and malfunction. Courts have likewise recognized exemptions for such events are not permissible in other 
FCPP SCR Project 

Response to Comments 

Page 98 of 109 

contexts under the Clean Air Act. See, e.g., Sierra Club v. EPA, 551 F.3d at 1027-28 (striking down an 

exemption for malfunctions in a MACT standard). In a rulemaking following the court’s decision in Sierra Club,

EPA promulgated a rule providing an affirmative defense with regard to imposing civil penalties for excess 

emissions during malfunctions. 76 FR at 15613. The affirmative defense provision was also challenged and 

struck down. NRDC v. EPA, 749 F. 3d at 1063. 

EPA acknowledges that malfunctions are not foreseeable in their nature, timing or effect on emissions levels 

and plant operators cannot predict if or when a malfunction will occur. However, as recently stated in a brief 

filed with the United States Court of Appeals for the District of Columbia, “EPA can use its enforcement 

discretion to address exceedances of emission limits that maybe caused by such uncertain, unpredictable 

events, on a case-by-case basis.” United States Sugar Corporation v. United States Environmental Protection 

Agency, USCA Case #11-1108, Document #1521657, filed Nov. 10, 2014 at p. 52 (rejecting arguments that EPA 

was required to include alternative numerical or work practice standards for malfunction events in a boiler 

MACT rule). 

The comment letter requests EPA to set an alternative numerical emission limit or work practice standards 

that would apply during malfunctions instead of the SAM BACT emission limit. However, the comment has not 

identified any statutory or regulatory language that implies EPA must include such alternatives into the SAM 

BACT emissions limit that otherwise applies during such events. EPA has declined to include such alternatives 

for malfunction events in MACT rules. See 79 Fed. Reg. 60274-75. 

EPA has noted that excess emissions from malfunctions are not inherently different than such emissions 

resulting from “acts of God” or worker malfeasance. Yet, we do not provide alternative numerical emissions 

limits or work practice standards for these events. See, Brief filed in United States Sugar Corporation, at p. 42-

43). Rather than address a range of hypothetical situations in this permitting action, EPA intends to follow the 

reasoning of the D. C. Circuit in Weyerhasuer Co. v. Costle, 590 F.2d 1011, 1058 (D. C. Cir. 1978)(stating: “[a] 

line must be drawn as to what is treated in the general rule [e.g., setting a BACT standard] and what is handled 

case-by-case, and we believe it appropriate to defer when EPA, in the interest of preserving an enforcement 

system based on straightforward numbers” draws that line); see Brief in United States Sugar Corporation, at p. 

46. For the reasons discussed above, EPA is declining to include any alternative numerical or work practice 

standards into the FCPP PSD permit to account for malfunctions. Excess emissions from malfunctions can be 

addressed on a case-by-case basis. See Brief in United States Sugar Corporation at p. 48 (stating “The issue in 

not whether EPA may deal with malfunctions in one form or another in establishing MACT standards, it is 

whether EPA is required under 42 U.S.C. §7412 to factor emissions occurring during malfunctions into its 

emissions standards, be they numerical standards or alternative work practices. EPA’s view that nothing in 

the statue contains such a requirement is a permissible reading of the statute and, under Chevron, should 

therefore be upheld.”) In responding to this comment, we see no difference in the requirement to be in 

continuous compliance with a MACT standard and a BACT emissions limit. Accordingly, the reasoning EPA set 

forth in the litigation referenced above and in the recent proposal on the Cement Kiln MACT, applies equally 

here. 

Submission of Semi-Annual Reports

Comment 52:

(Commenter: APS) 
FCPP SCR Project 

Response to Comments 

Page 99 of 109 

Condition 14.b states that the permittee shall report all excess emissions and any other noncompliance with 

the permit conditions to EPA for each six-month reporting period from January 1 to June 30 and July 1 to 

December 31. In addition, the proposed PSD Permit requires the report be postmarked by the 30th day 

following the end of each six-month reporting period. 

APS requests that EPA extend the reporting period deadline from 30 days to 45 days following the end of the 

six-month reporting period in order to stay consistent with Title V permit condition III.C.1- Reporting 

Requirements. This will allow APS to submit both reports to EPA and Navajo Nation with one submittal instead 

of submitting separate reports at different reporting periods. 

Response 52:

The EPA has made the commenter’s suggested revision to the final permit to allow the reporting requirements 

to be consistent with the title V permit. 

Maintenance Log Requirements for Trucks

Comment 53:

(Commenter: APS) 

Condition 14.f states that the permittee shall maintain logs describing the maintenance activities for the 

emission units listed in the equipment list. APS is seeking clarity on the application of this permit condition. 

APS believes that the maintenance log requirement regarding truck traffic for sorbent and SCR reagent 

deliveries only applies to the roads the trucks are driving on and not to the actual trucks. APS requests that 

EPA clarify Condition 14.f to clearly state the maintenance log requirements only apply to roads located within 

the plant site boundary. 

Response 53:

The commenter’s assertion is correct, the log requirements only apply to roads (not to the trucks) located 

within the plant site boundary. No revision to the permit was made in response to this comment. 

Shakedown Period

Comment 54:

(Commenter: APS) 

Condition 15 defines the shakedown period as the period between initial startup and initial performance 

testing, and further provides that the shakedown period shall not exceed 90 days. This period is inconsistent 

with typical shakedown periods in EPA's rules (e.g., under the NSPS rules) of 180 days, as well as the 180-day 

deadline for conducting an initial performance test under Condition 24 of the draft permit. Further, 90 days is 

an insufficient amount of time to coordinate stack testing for tuning of the SCRs. Accordingly, APS requests 

that EPA revise Condition 15 to allow for a shakedown period not to exceed 180 days, instead of 90 days. 

Response 54:

The shakedown period in the proposed permit is consistent with other PSD permits issued by EPA Region 9.

However, the EPA agrees that 180 days for shakedown is appropriate in this case, particularly given the 
FCPP SCR Project 

Response to Comments 

Page 100 of 109 

standard 180 days for initial testing. Further, the EPA’s PSD regulations even reference a shakedown period of 

180 days. The final permit has been revised, as request by the commenter. 

Submittal of Demonstration Study

Comment 55:

(Commenter: APS) 

Condition 21 sets forth the effective dates for complying with the lower sulfuric acid mist emission rate of 

0.0025 lb/MMBtu with the intent of a 2-year demonstration period. This is further supported in the Fact Sheet 

which makes it clear EPA intended to provide APS with a 2-year demonstration period, Fact Sheet at 33, and 

this explains why the lower limitation in Condition 21 would become effective (unless the demonstration 

study shows otherwise) "within 910 days of initial startup of the SCR systems or 730 days after the initial 

performance tests in Condition 23, whichever comes first" (a period of 730 days is equivalent two years; a 

period of 910 days is equivalent to 2 years plus 180 days for shakedown). 

However, Condition 32 requires that the "demonstration study in Condition 31 shall be submitted at least 60 

days prior to the limit in Condition 21 becoming effective." This results in a demonstration period that is at 

least 60 days shorter than 2 years, since the study must be submitted at least 60 days before the period 

expires; practically, the demonstration period would be even shorter than that, since it would inevitably take 

APS some time to prepare the report it would have to submit to EPA 60 days before the end of the two-year 

demonstration period. 

Accordingly, APS requests that EPA add at least 90 days to the demonstration periods in Condition 21, such 

that the lower emission limitation would take effect "within 1,000 days of initial startup of the SCR systems or 

820 days after the initial performance tests in Condition 23, whichever comes first," to account for the time 

required to prepare and submit a demonstration study to EPA. 

Response 55:

The EPA agrees with the commenter that it was our intent for the demonstration period to be two years, and 

the proposed permit did not adequately reflect that intent. The final permit has been revised, consistent with 

the commenter’s suggestion, to allow the demonstration period to be a full two years and then allow time to 

prepare the demonstration report. 

Measuring Volumetric Flow

Comment 56:

(Commenter: APS) 

Condition 27 requires volumetric flow measurement at the fabric filter inlet and hydrated lime injection rates 

for the purpose of calculating a proportional lime injection rate. A volumetric flow meter at the fabric filter 

inlet would be problematic. The high ash loading would make it difficult to keep the flow meter operating, and 

the measurements would be unreliable. Since the whole purpose of flow measurement is to establish and 

maintain a ratio, any flow measurement should be sufficient. We propose using the stack flow measurement 

to establish the ratio. This measurement undergoes quality assurance checks and is already used for 
FCPP SCR Project 

Response to Comments 

Page 101 of 109 

compliance and has proven to be reliable. It would serve exactly the same purpose as a flow measurement 

ahead of the fabric filter. Neither location is subject to bypass, so both would measure the full flow. 

APS recommends replacing the language in Condition 27 with the following statement, "The permittee shall 

maintain and operate the volumetric flow meter located in the stack in accordance with 40 CFR Part 75." 

Condition 28 requires "a mass flow meter on the injection lines between the sorbent storage silos and the 

injection points" for hydrated lime. While it would likely be located there, we would prefer to leave the 

specific location of the flow meter to the equipment vendor. We have not bid the equipment for DSI reagent 

injection yet, and while most vendors prefer mass flow measurement, some may prefer volumetric flow 

measurement, which is converted to mass flow with density. Volumetric flow is easier to measure under 

varying conditions, but requires density for conversion to mass flow. Density can vary over time. Mass flow is a 

direct measurement, but requires weighing a moving material at varying speeds. Load cells used for mass 

measurement can go out of calibration or provide false values due to build-up in the system. We would rely on 

the system vendor to decide which works best with their system. We propose changing the wording to require 

mass flow determination using the vendor recommended method. 

APS recommends replacing the language in Condition 28 with the following statement, "The permittee shall 

determine the mass flow rate in accordance with manufacturer's specifications for the injection rate of 

hydrated lime from the lime silo into the flue gas duct work prior to the baghouse." 

Response 56:

EPA agrees with the commenter that the mass flow rate can be determined through a volumetric or mass flow 

meter, assuming sorbent density information is available. The final permit has been revised as suggested by 

the commenter. In addition, we have added a requirement to record the density of the sorbent, as injected, 

on a monthly basis. 

Missing Data Requirements

Comment 57: 

(Commenter: APS) 

The Monitoring and Testing Requirements section does not address time periods where data is not available. 

APS does not believe that missing data provisions should be in the permit; however other EPA rules, (e.g., 

Mercury and Air Toxics Standards) explicitly state that data substitution does not apply. 

APS recommends that EPA add language stating the "the owner or operator of an affected unit is not required 

to substitute for missing data." 

Response 57:

EPA understands the commenter’s concern, but has not made any revisions to the permit as a result of this 

comment. EPA believes this issue is more appropriately addressed through the Compliance Assurance 

Monitoring (CAM) Plan under 40 CFR part 64 that will eventually be submitted for approval and incorporated 

into the title V permit. 
FCPP SCR Project 

Response to Comments 

Page 102 of 109 

Submittal of Design Report

Comment 58:

(Commenter: APS) 

Condition 30 requires the permittee to submit to EPA for review and approval a Design Report for the dry 

sorbent injection system. It further states that the Design Report shall specify the type of hydrated lime to be 

used, the location of the reagent injection points, and other design parameters based on maximum emission 

reduction effectiveness, good engineering judgment, vendor standards, available data, and boiler operations. 

EPA will respond within 60 days of receipt of the Design Report with comments. If EPA does not respond 

within 60 days, then the Design Report is automatically approved. 

APS will design the dry sorbent injection system in accordance with the specifications mentioned above and 

ensure compliance with the emission limits. In addition, the proposed permit allows for a shakedown period 

to conduct contractual and operational testing and tuning. Lastly, there is a demonstration study that ensures 

the lower emission limit can be met. APS believes submission of a Design Report before the installation of the 

dry sorbent injection system is unnecessary because the permit has conditions ensuring the emission 

standards are being met. More importantly, review and approval of the Design Report by EPA will set back the 

installation by at least 2 months. The schedule for installation of the SCR and dry sorbent injection systems 

does not allow for an additional 60-day review period by EPA. 

APS recommends that EPA revise this condition by removing the requirement to submit the Design Report and 

the requirement for EPA to review and approve the Design Report within 60 days. 

Response 58:

The EPA has revised the permit to address the Applicant’s concern. EPA is concerned that without an initial 

review of the Design Report the final demonstration study submitted to EPA, if necessary, may not fully 

address all considerations for making an adequate demonstration. Requiring pre-review of APS’s plan would 

ensure both parties are in agreement on the necessary actions to make the demonstration. The EPA has 

revised the final permit to make the Design Report optional. If submitted, it needs to be submitted within the 

first 240 days of initial startup, and can be revised and resubmitted at a later date if necessary. 

PM Performance Testing

Comment 59:

(Commenter: APS) 

Condition 31.c requires filterable particulate matter performance testing be performed during the 

demonstration study at the same time sulfuric acid mist is being tested. 

Since Four Corners Units 4 and 5 have baghouses and, as EPA notes, "the outlet emissions from a baghouse 

are generally uniform" regardless of input, Fact Sheet at 28, there is no need for filterable PM tests to be 

included in the Demonstration Study. Accordingly, APS requests that EPA delete Condition 31.c. 

Notwithstanding the previous comment, APS would like to have the flexibility to use Method 5, Method 5B, 

Method 5 as described in Subpart UUUUU, Table 5, or any other alternative tests or methods that are 
FCPP SCR Project 

Response to Comments 

Page 103 of 109 

requested by APS and approved by EPA. This will provide flexibility to perform the particulate matter tests for 

the demonstration study and comply with quarterly performance testing requirements in the MATS rule. APS 

believes there is no reason to conduct two different filterable PM test methods. Further, the additional 

flexibility will allow for the possibility of operating the wet flue gas desulfurization system with or without 

reheating the stack. APS recommends that EPA revise this condition to require "performance tests for 

filterable PM using the applicable PM test method." 

Response 59:

In review of this comment, EPA continues to conclude that PM testing is necessary to verify continued 

compliance with other PM emission standards applicable to FCPP, such as under the BART FIP, while 

demonstrating the achievable SAM BACT limit during the demonstration period. While emissions from a 

baghouse are generally expected to be uniform, PM emissions data provided in the application do not always 

demonstrate this conclusion for the FCPP. As such, no revisions have been made to the permit. 

EPA agrees that additional flexibility in the particular PM test method is warranted and has revised the final 

PSD permit to allow use of other EPA approved test methods for PM. 

Auxiliary Boiler Operating Limit

Comment 60:

(Commenter: APS) 

Condition 37 sets hours of operation limit of 876 on the auxiliary boiler ensuring the boiler capacity factor is 

less or equal to 10 percent. Conditions 40 and 44 are associated with monitoring and recordkeeping 

requirements for the hours of operation work practice standard. 

On September 7, 2012, APS submitted a minor permit modification to Title V Permit #NN-ROP-07 for 

installation and operation of a "limited use" auxiliary boiler. In order to meet the definition of a "limited use 

boiler" in 40 CFR 63, Subpart DDDDD "NESHAP for Major Sources: Industrial, Commercial, and Institutional 

Boilers and Process Heaters," APS took an operating limit of 876 hours of operation per year to ensure the 

boiler operates at less than or equal to a 10 percent capacity factor. The definition reads: 

Limited-use boiler or process heater means any boiler or process heater that burns any amount 

of solid, liquid, or gaseous fuels, has a rated capacity of greater than 10 MMBtu per hour heat 

input, and has a federally enforceable limit of no more than 876 hours per year of operation. 

However, shortly after the issuance of the minor permit modification, EPA finalized, on January 31, 2013, 

changes to 40 CFR 63, Subpart DDDDD, which included a more flexible definition for a limited use boiler: 

Limited use boiler or process heater means any boiler or process heater that burns any amount 

of solid, liquid, or gaseous fuels and has a federally enforceable average annual capacity factor 

of no more than 10 percent. 

EPA justified the change to the definition in the preamble of the rule by stating that many affected units 

operate on standby mode or low loads for periods longer than the proposed definition for limited use units, 
FCPP SCR Project 

Response to Comments 

Page 104 of 109 

which limited operation to 876 hours per year. The capacity-factor approach, allows more flexibility on unit 

operations without increasing emissions or harm to human health and the environment. For example, units 

operating at 10 percent load for 8,760 hours per year would emit the same amount of emissions as units 

operating at full load for 876 hours per year. Further, it is technically infeasible to schedule stack testing for 

these limited use units since these units serve as back-up energy sources and their operating schedules can be 

intermittent and unpredictable. The limited use subcategory was adjusted to be based on units with a 

federally enforceable operating limit of less than or equal to 10 percent of an average annual capacity factor. 

On August 12, 2014, APS submitted a minor permit modification to Title V Permit #NNROP- 05-07 revising the 

operating limit on the auxiliary boiler to incorporate this new definition. 

NNEPA intends to incorporate this change into the upcoming Title V permit and requests that EPA make the 

same change in the proposed permit, Condition 37, so that it does not conflict with the corresponding 

condition in the Title V permit. 

APS also requests that the hours of operation limit of 876 be replaced with a 10 percent capacity factor limit. 

Commenter adds that the subsequent monitoring and recordkeeping requirements should include heat input. 

Response 60:

The EPA agrees with the commenters, and has made the requested change to the operating limit for the 

auxiliary boiler by adding an annual heat input limit. 

Correct to Emission Unit References

Comment 61:

(Commenter: NNEPA) 

Commenter requests that EPA change "EU9" in Conditions 37, 40 and 44 to "EU10," assuming references in all 

three Conditions pertain to the auxiliary boiler. Condition 37 clearly refers to the auxiliary boiler and the 

monitoring and recordkeeping requirements in Conditions 40 and 44 appear to apply to auxiliary boiler EU10 

rather than storage silo EU9. 

Response 61:

The EPA agrees with the commenter; however, the emissions unit identifiers have been revised consistent 

with our response to Comment 50 to have the emissions unit identifier match the title V permit. 

Baseline Period for Units 1-3

Comment 62:

On page 18 of the Fact Sheet, EPA made the following statement regarding the baseline for netting: 

For the purposes of determining contemporaneous emission decreases, baseline actual 

emissions for an existing electric utility steam generating unit is the average rate, in tons per 

year, at which the unit actually emitted the pollutant during any consecutive 24-month period 

selected by the owner or operator within the 5-year period immediately preceding when the 

owner or operation [sic] begins actual construction of the project – in July 2015. 40 CFR 

52.21(b)(48)(i). 
FCPP SCR Project 

Response to Comments 

Page 105 of 109 

APS clarifies that "the project" that creates a netting credit in this case is the shutdown of Units 1, 2, and 3, 

not the proposed project that is the subject of the PSD permit (the SCR project). The shutdown occurred on or 

about December 31, 2013. Accordingly, in the netting calculation, the baseline for the reductions from the 

shutdown of Units 1-3 is any 24-month period in the 5-year period preceding the shutdown, not the SCR 

project. That is, the baseline for the shutdown of Units 1, 2, and 3 may be drawn from the January 1, 2009 to 

December 31, 2013, not, as the Fact Sheet suggests, July 2010 to June 2015. 

It is well-established that the contemporaneous period for netting under the PSD rules is five years, and that 

this requires the source to account in the netting calculus for reductions and increases that happened during 

that period (i.e., five years before the proposed project). Under an interpretation that would limit the baseline 

period for such contemporaneous increases and decreases to five years before the proposed project, the 

contemporaneous period for the reductions and increases themselves would be effectively reduced to three 

years. 

Moreover, the D.C. Circuit's decision upholding the baseline provisions of the 2002 NSR rules. See New York v. 

EPA, 413 F.3d 3, 26-27 (D.C. Cir. 2005). In New York, certain petitioners challenged the ten-year lookback for 

the baseline for non-EGUs on several grounds; including that by applying this lookback both to the proposed 

project and the reductions for netting, EPA in effect was allowing reductions dating as far back as fifteen years 

before the proposed project to be used in the netting calculus. As the Court explained: 

For example, to determine whether a change made in 2005 will trigger NSR, a source may use 

baseline emissions from 1995 and 1996 to calculate the emissions increase caused by the 2005 

change; it may then choose an offsetting change made in 2000 and use baseline emissions from 

1990 to 1991 to calculate the emissions decrease caused by the 2000 change in order to 

determine whether that decrease offsets the increase caused by the 2005 change. 

The court went on to agree with EPA that this was permissible under the statute and upheld the rule. Thus, 

there is no question that at the time the 2002 NSR rules were promulgated, EPA, the petitioners, and the court 

understood the baseline for netting reductions was a 5-year or 10-year lookback (for EGUs and non-EGUs, 

respectively) from the date of the reductions themselves, and the court upheld that provision. 

APS requests that EPA correct the baseline period for netting statement on page 18 of the Fact Sheet to reflect 

the fact that the project that creates a netting credit in this case is the shutdown of Units 1, 2, and 3, not the 

SCR project. 

Response 62:

The EPA agrees with the commenter regarding the “project” referenced in 40 CFR 52.21(b)(48)(i). The correct 

look back period for Units 1-3 should have been identified as January 2009 through December 2013. We note 

that this does not change the calculation of baseline actual emissions for these units, as the chosen period was 

within this range. We note that we do not generally produce a revised Fact Sheet, but rely on the information 

presented in the Response to Comments document to represent our final determination. 

Type of Coal at FCPP

Comment 63:
FCPP SCR Project 

Response to Comments 

Page 106 of 109 

(Commenter: Vincent H. Yazzie. Commenter includes several attachments, which are a part of the 

administrative record for this permit action.) 

The reason why sulfuric acid is high at FCCP is because the plant was designed to have a higher capacity than 

1,500 MW, because the coal at FCPP is actually bituminous instead of sub-bituminous. See EPA-R09-OAR2010-0683-0056(1).PDF, Determination of Four Corners Coal Ranking, March 11, 2008, by Alan Papp, which is 

attached to the comment. “It has long been assumed that the coal burned at Four Corner is subbituminous. 

Only recently, with coal classification affecting emissions standards, have we made a serious effort to 

determine the true classification of coal from the Navajo Mine. Previously, it made little difference what name 

the coal went by. We just accepted BHP’s statement that the coal was subbituminous. When we tried to verify 

that in light of the new mercury and NOx BART rules, we discovered that Navajo Mine coal was actually 

predominantly bituminous, only occasional slipping into the subbituminous category. Further investigation 

uncovered the fact that BHP had been wrongly applying the ASTM formula. They had been entering data as 

decimal fraction, when ASTM intended it to be entered as whole percentage numbers (for example, 22.3% ash 

should be entered as 22.3, not 0.223).” (Another report, the “Biser report,” on this subject is also attached to 

the comment.) 

Response 63:

We disagree that the increase in SAM emissions is due to the FCPP being designed to have a higher capacity 

than 1,500 MW because of the type of coal used. The emission increases associated with the SCR Project are 

based on projected actual emissions of the FCPP over the next ten years. The projected emissions are based 

on annual heat input (116,012,683 MMBtu/yr) and not the type of coal being used. The integrity of EPA’s SAM 

BACT emission limit, which is on a pound per MMBtu basis, is not compromised by variations in coal being 

burned at a particular time. APS must comply with the limit established in this permit as BACT regardless of 

the type of coal being burned. EPA also notes that the FIP promulgated in 2007 set a stringent emission limit 

for SO2, which is also enforceable by EPA and citizens regardless of the sulfur content of the coal being 

combusted. 72 Fed. Reg. 25705. 

Leaks from Baghouse at FCPP

Comment 64:

(Commenter: Vincent H. Yazzie) 

My mother suffered an acute respiratory distress at the North Security Gate of the Navajo Mine on May 7, 

2014 around 4:30 pm. I was at the North Security Gate, Navajo Mine to obtain documents on the storing of 

coal ash in the Navajo Mine pits. The environmental assessment said the documents were available at the 

Navajo Mine. I was not successful in getting the documents right away, but now I am being given the run 

around by Norman Benally's request that I write a letter. Attached is a photo of the North Security Gate of the 

Navajo Mine. Also attached is the National Weather Service weather conditions for the Farmington, New 

Mexico area. The wind was blowing around 16 mph and gusting up to 26 mph around 16:53 pm on May 7, 

2014. I was inside the trailer talking with security while my mother was being exposed to some coal emissions 

from Four Corners Power Plant. FGD emissions from the exhaust stacks are too high and the wind would blow 

the emissions to the south of the car. My Mom was inside the car while I was inside the security trailer. See 

attached google earth image. The only emissions that could have disabled my mother is if there are leaks from 

the unit 4 and 5 combustion pipe FGD or the baghouses. The baghouses would remove the ash, but still 
FCPP SCR Project 

Response to Comments 

Page 107 of 109 

contain Sulfur Dioxide and NOx. Sulfur dioxide can cause asthma symptoms in 5 minutes. Any leaks from the 

baghouses would also move from the NW to the SE and would travel to the North Security guard station. 

One would say leaks are impossible, but the attached image shows a corroded roof on the North Security 

guard trailer. Aluminum usually does not corrode. Aluminum does corrode when exposed to nitrogen or 

ammonia. This shows there is also a nitrogen leak which is related to NOx and high temperatures from the 

burning of excess fuel. This also says the leaks have compromised the EPA monitoring emissions. The EPA 

monitoring emissions do not portray the correct measurements. EPA needs to monitor emissions as it leaves 

the furnace. Any leaks would give a wrong reading on the NOx measuring devices. Design of the SCR would not 

be engineered correctly and would be inadequate to handle the extra NOx. Also there would be more 

ammonia produced. Leaks have to be found and emissions measured at the furnace. 

My mother still has acute bronchitis with no fever. She has lived many years in the desert and dust storms. 

Dust storms did not cause her bronchitis, but exposure to sulfur dioxide via leaks. I only suffered slight lung 

problems as I went straight from the trailer to the car. I did smell cigarette smoke or cigar smoke when 

walking between the car and the North Security guard trailer. I only experienced a slight irritation. The trailer 

shielded me from the smog. 

FCCP can exceed a capacity of 1,500 MW. The plant was designed for higher burning bituminous coal. If SCR is 

causing additional sulfur dioxide emissions it is because FCPP is illegally releasing sulfur dioxide and trying to 

blame it on SCR. The only emissions that could have disabled my mother is if there are leaks from the unit 4 

and 5 combustion pipe FGD or the baghouses. 

Response 64:

The EPA recognizes that the commenter is concerned about leaks from the baghouse at FCPP. However, this 

issue appears to be outside the scope of this particular permitting action related to the installation of SCR at 

FCPP. We note that the high temperature and volumetric flow rate of the baghouse make the likelihood of 

measureable leaks low. A leak in the baghouse would result in significant damage to the rest of the baghouse 

caused by the stress of the high temperature and pressure at the location of the leak. A leak from FCPP’s 

baghouse is significantly different that heat loss leaks from your home, where the inside temperature and 

pressure are not that different from the outside. Conditions inside the baghouse are several hundred degrees 

warmer than outside temperatures. Small leaks would need to be repaired as soon as practicable to avoid long 

term damage to the baghouse. The existing FIP for FCPP requires: “At all times, including periods of startup, 

shutdown, and malfunction, the owner or operator shall, to the extent practicable, maintain and operate the 

Plant including associated air pollution control equipment in a manner consistent with good air pollution 

control practices for minimizing emissions.” 40 CFR 49.5512(g). 

APS Basis for Needing a Permit

Comment 65:

(Commenter: Vincent H. Yazzie) 

A comment letter contained the following discussion: 

APS and FCPP has lied about why they need a permit. The increased sulfur dioxide emissions are actually from 

the higher burning bituminous coal and not from SCR. Increased sulfur dioxide emissions will harm cultural 
FCPP SCR Project 

Response to Comments 

Page 108 of 109 

resources as APS and FCPP has not come clean on where these sulfur emissions come from. APS has lied to get 

this permit. APS has lied about its power plant capacity as FCPP can exceed its 1,500 MW rating. Every time 

FCPP exceeds its power plant rating, it is pumping out illegal emissions. 

Response 65:

EPA does not have any documentation nor has the commenter provided documentation that APS has lied 

about why a permit is needed for the SCR project. Further, there is no net emissions increase in sulfur dioxide 

associated with the FCPP SCR Project. On the other hand, the correlation between installation of SCR and 

increases in SAM emissions is well documented and known to be caused by the SCR catalyst.62 This was 

described in Section 5.2.1.1 our Fact Sheet. Monitoring data for FCPP is available to the public through EPA 

Clean Air Markets Program Data. This data does not show Units 4 and 5 at the FCPP exceeding the maximum 

heat input of each unit. 

Southern California Edison Interest in FCPP

Comment 66:

(Commenter: Vincent H. Yazzie) 

A commenter asserts that SCE still has an interest in FCPP in violation of the FIP, as follows: 

“The Federal Implementation Policy (FIP) initially required APS to notify EPA of its choice by July 1, 2013. In 

May 2013, the Arizona Corporation Commission proposed to consider retail competition in the electrical 

generation market. As a result of the uncertainty introduced by this proposal, APS requested and was granted 

an extension of the EPA deadline to December 31, 2013. Southern California Edison is required to divest its 

ownership share of FCPP due to requirements of California Senate Bill 1368 addressing greenhouse gas 

emissions. On December 30, 2013, APS acquired Southern California Edison's share of Units 4 and 5 (720 MW) 

and shut down Units 1, 2, and 3 in compliance with the first of the options provided by EPA. The increase in 

APS's ownership of Units 4 and 5 replaced the generation capacity lost in the shutdown of APS-owned Units 1, 

2, and 3. Units 4 and 5 would continue to operate for the duration of the lease agreement to 2041, with the 

installation and operation of SCR equipment on both units by July 31, 2018.” Draft EIS, Volume I, Executive 

Summary, page iii. 

Southern California Edison (SCE) did not divest itself of FCPP. “As part of APS's acquisition of SCE's interest in 

Units 4 and 5, APS and SCE agreed, via a "Transmission Termination Agreement," that upon closing of the 

acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") 

between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for 

SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request 

to FERC related to this termination, which resulted in an FERC order denying rate recovery of $40 million that 

APS agreed to pay SCE associated with the termination. APS and SCE negotiated an alternate arrangement 

under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to thirdparties, including 300 MW to APS's marketing and trading group. However, this alternative arrangement was 

not approved by FERC. In late March 2014, APS and SCE filed requests for rehearing with FERC. We are unable 

to predict the timing or outcome of these requests. Although APS and SCE continue to evaluate potential 

paths forward, it is possible that the terms of the Transmission Termination Agreement may again control. As 

we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission 

 

62 See, Sulfuric Acid Mist: Regulation Uncertainties, Ecology Law Currents, Matthew Thurlow, 2012. 
FCPP SCR Project 

Response to Comments 

Page 109 of 109 

Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that 

agreement. If APS and SCE were unable to determine a resolution through negotiation, the Transmission 

Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the 

outcome of this matter if it proceeds to arbitration.” Form 10-Q, Pinnacle West Capital Corporation, Arizona 

Public Service, May 2, 2014, page 15, 16 

http://www.sec.gov/Archives/edgar/data/764622/000110465914033796/a14-8980_110q.htm

“Following the issuance of the September 13 Order, on December 18, 2013, APS submitted a filing requesting 

that the Commission revise the effective date of the cancellation of the Transmission Service Agreement with 

SoCal Edison from the date on which SoCal Edison transferred its ownership interests in the Four Corners 

Power Plant to APS to the date on which the Transmission Service Agreement terminates by its own terms. On 

January 3, 2014, the Commission accepted APS's revised effective date of the cancellation of the agreement, 

and required APS to file a notice of cancellation under section 205 with the Commission when the agreement 

terminate by its own terms.” “The Commission orders: SoCal Edison's request for rehearing is hereby denied, 

as discussed in the body of this order.” 147 FERC 61,017, Arizona Public Service Docket No. ER13-1402-002, 

issued April 7, 2014 http://www.ferc.gov/CalendarFiles/20140407111759-ER13-1402-002.pdf. "APS requests 

that the Commission revise the effective date of the cancellation of the Transmission Agreement granted in 

the September Order, from the date on which SoCal Edison transfers its ownership interests in the Four 

Corners Power Plant to APS, to the date on which the Transmission Agreement will terminate by its own 

terms." Office of Market Regulation, Arizona Public Service Docket No. ER13- 1402-003 (20140103-

3016(29026615).pdf), page 1. "When the Transmission Agreement terminates by its own terms, APS must file 

a notice of cancellation under section 205 with the Commission." Office of Market Regulation, Arizona Public 

Service Docket No. ER13-1402-003 (20140103-3016(29026615).pdf), page 2, Footnote 3. SCE still has an 

interest in FCPP in violation of the FIP. 

Response 66:

The commenter misunderstands the terms of EPA’s BART FIP for FCPP found at 40 CFR 49.5512. The FIP does 

not contain any requirements related to SCE or its interest in FCPP. EPA’s BART FIP only established 

requirements related to air pollutant emissions from the FCPP. These emission limits apply to FCPP regardless 

of who currently owns the FCPP or who will own it at any point in the future. 

3. Final Revised PSD Permit No. NN 14-01 and Tribal Minor NSR Permit No. T002-NN

After careful review of the comments submitted and consideration of the views expressed by the 

commenters, the pertinent Federal statutes and regulations, and additional material relevant to the applicant 

and contained in our administrative record, Region 9 is issuing a decision pursuant to 40 CFR 52.21 and 40 CFR 

49.151-161 to issue a final permit to the FCPP for the SCR Project. Region 9’s consideration of the comments 

received during the July-September 2014 public comment period resulted in several changes to the Final 

Permit. For the purpose of clarity, we have created an unofficial redline/strikeout version of the final permit 

that shows the changes made to the permit since proposal. In addition to the changes described in our 

responses we also made several typographical changes which can be seen in the unofficial reline/strikeout 

version.