Complete Response to Comments for NM Regional Haze/Visibility Transport FIP 

Docket No. EPA-R06-OAR-2010-0846 

8/5/2011 
Table of Contents 

A. Comments on the Costs of the NOx BART Determination .......................................... 1

1. General Cost Comments ............................................................................................ 1

2. Comments on Specific Cost Line Items ................................................................... 13

3. Concerns over Possible Electricity Rate Increases .................................................. 41

4. Comments that Opined on our Reliance on the EPA Air Pollution Control Cost 

Manual ...................................................................................................................................... 42

B. Comments on our Proposed NOx BART Emission Limits......................................... 48

C. Comments on our Proposed SO2 Emission Limit ....................................................... 66

D. Comments on our Proposed H2SO4 and Ammonia Emission Limits and other 

Pollutants....................................................................................................................................... 67

E. Comments on the Emission Limit Compliance Schedule ........................................... 69

F. Comments on the Conversion of the SJGS to a Coal-to-Liquids Plant with Carbon 

Capture as a Means of Satisfying BART ...................................................................................... 77

G. Comments on Health and Ecosystem Benefits, and other Pollutants ......................... 78

H. Miscellaneous Comments ........................................................................................... 79

I. Comments in Favor of our Proposal ............................................................................. 84

J. Comments Arguing our Proposal Would Hurt the Economy and/or Raise Electricity 

Rates .............................................................................................................................................. 85

K. Comments Arguing our Proposal Would Help the Economy ..................................... 86

L. Comments Requesting an Extension to the Public Comment Period .......................... 87

M. Comments Requesting we Defer Action in Favor of a New Mexico SIP Submittal . 87

N. Comments Generally Against our Proposal ................................................................ 89

O. Comments on Legal Issues ......................................................................................... 89

1. EPA’s Authority....................................................................................................... 89

2. BART Requirements .............................................................................................. 100

3. Executive Orders Comments ................................................................................. 104

4. Other General Legal Comments ............................................................................ 105

P. Modeling Comments ................................................................................................. 107

Q. Comments Not Relevant to the Proposal .................................................................. 142
A. Comments on the Costs of the NOx BART Determination 

1. General Cost Comments 

Comment: The National Park Service (NPS) presented information in support of their 

opinion that PNM’s contractor Black & Veatch has over estimated the cost of installing SCR on 

the units of the SJGS. They state the Black & Veatch 10/22/10 Cost Analysis escalated the 

original May 2007 costs to September 2010 using data for certain materials and equipment from 

the U.S. Bureau of Labor Statistics, confirmed by Black & Veatch's corporate escalation tool. 

While escalation to current dollars is a reasonable adjustment, it does not affect the outcome of a 

cost effectiveness analysis because the cost effectiveness of other analyses used to establish the 

acceptable cost range should also be adjusted for escalation. Black & Veatch's calculations do 

not consider the weakening of labor markets that has occurred since they set up their 

spreadsheets in 2007. According to Black & Veatch, in the pre-2004 period, its estimating 

department found that construction indirects were typically 50% to 60% of installation labor 

costs. In the post-2005 period, they reported construction indirects rose to a range of 90% to 

120% of installation labor costs due to tightening in labor markets. However, in the 2010 revised 

cost estimate, Black & Veatch did not adjust the construction indirects to reflect the loosening of 

the labor market. The tightening of the labor markets has now reversed, skilled labor is 

underutilized, and per diem is not being paid at all, or only paid for a portion of the labor force. 

The NPS state that real-world, utility industry-generated evidence that PNM has 

overestimated its SCR costs can be found in a June 2009 article in "Power" magazine1

: "One 

more current data set is the historic capital costs reported by AEP averaged over several years 

and dozens of completed projects. For example, AEP reports that their historic average capital 

costs for SCR systems are $162/kW for 85% to 93% NOx removal..." 

"...historical data finds the installed cost of an SCR system of the 700MW-class as 

approximately $125/kW over 22 units with a maximum reported cost of $221/kW in 2004 

dollars. This data was reported prior to the dramatic increase in commodity prices of 14% per 

year average experienced from 2004 to 2006 (from the FGD survey results). Applying those 

annual increases to the 2004 estimates for three years (from the date of the survey to the end of 

2007) produces an average SCR system installed cost of$185/kW..." (or $184/kW in 2009 $). 

"Overall, costs were reported to be in the $100 to $200/kW range for the majority of the 

systems, with only three reported installations exceeding $200/kW." 

Five industry studies conducted between 2002 and 2007 have reported the installed unit 

capital cost of SCRs, or the costs actually incurred by owners, expressed in dollars per kilowatt. 

 1

 June 13, 2009 "Power" magazine article "Air Quality Compliance: Latest Costs for S02 and NOx Removal 

(effective coal clean-up has a higher-but known-price tag)" by Robert Peltier. 

http://www.masterresource.org/2009/06/air-quality-compliance-Iatest-costs-for-so2-and-nox-removal-effectivecoal-clean-up-has-a-higher-but-known-price-tag/
2 

These actual costs are lower than estimated by PNM for SJGS. The first study evaluated the 

installed costs of more than 20 SCR retrofits from 1999 to 2001. The installed capital cost 

ranged from $106 to $211/kW, converted to 2009 dollars.2

 Costs are escalated through using the 

2009 CEPCI (because the final 2010 CEPCI is not yet available). The second survey of 40 

installations at 24 stations reported a cost range of $75 to $240/kW, converted to 2009 dollars.3 

The third study, by the Electric Utility Cost Group, surveyed 72 units totaling 41 GW, or 39% of 

installed SCR systems in the U.S. This study reported a cost range of $118/kW to $261/kW, 

converted to 2007 dollars.4 A fourth study, presented in a course at PowerGen 2005, reported an 

upper bound range of $178/kW to $201/kW, converted to 2009 dollars.5

 A fifth summary study, 

focused on recent applications that become operational in 2006 or were scheduled to start up in 

2007 or 2008, reported costs in excess of $200/kW on a routine basis, with the highest 

application slated for startup in 2009 at $300/kW.6

 Other recent estimates suggest that the SJGS 

SCR capital costs may be overestimated. Wisconsin Electric estimated the cost to retrofit SCR 

on Oak Creek Units 5-8 to be $175/kW15 for a cold-side SCR.7

 This cost was certified in July 

2008 for construction by the Wisconsin Public Services Commission.8

 Wisconsin Power and 

Light estimated the cost to retrofit SCR on the 430-MW Edgewater Unit 5 to be $324/kW in 

January 2008.9 Similarly, American Electric Power (AEP) estimated that the average capital 

cost to install SCRs to remove 85-93% of the NOx from many of its units was $162/kW.10 The 

NPS also references a graph constructed by EPA region 8 of SCR costs and states that it 

confirms that SCR capital costs typically range from $73 - $243/kW. A graphic illustration of a 

"real-world" retrofit was presented by Burns & McDonnell at the 2010 Power Plant 

 2

 Bill Hoskins, Uniqueness of SCR Retrofits Translates into Broad Cost Variations, Power Engineering, May 2003. 

Ex. 2. The reported range of $80 to $160/kW was converted to 2009 dollars ($106 - $211/kW) using the ratio of 

CEPCI in 2009 to 2002: 521.9/395.6. 

3

 J. Edward Cichanowicz, Why are SCR Costs Still Rising?, Power, April 2004, Ex. 3; Jerry Burkett, Readers Talk 

Back, Power, August 2004, Ex. 4. The reported range of $56/kW - $185/kW was converted to 2009 dollars ($75 

$240/kw) using the ratio ofCEPCI for 2009 to 1999 (521.9/.390.6) for lower end of the range and 2009 to 2003 

(521.9/401.7) for upper end of range, based on Figure 3. 

4

 M. Marano, Estimating SCR Installation Costs, Power, January/February 2006. Ex. 5. The reported range of$I00- 

$221/kW was converted to 2009 dollars ($117 - $260/kW) using the ratio of CEPCI for 2009 to 2004: 521.9/444.2. 

http://findarticles.com/p/articles/mi_qa5392/is_200602/ai_n21409717/print?tag=artBody;col1 5

 PowerGen 2005, Selective Catalytic Reduction: From Planning to Operation, Competitive Power College, by 

Babcock Power, Inc. and LG&E Energy, December 2005, Ex. 6. The reported range of $160 - $180/kW) was 

converted to 2009 dollars ($178 - $20 I/kW) using the ratio of CEPCI for 2009 to 2005 (521.9/468.2). 

6

 J. Edward Cichanowicz, Current Capital Cost and Cost-Effectiveness of Power Plant Emissions Control 

Technologies, June 2007, pp. 28-29, Figure 7-1 (Ex. 1). 

7

 Wisconsin Electric Power Company's Application to Install Wet Flue Gas Desulfurization and Selective Catalytic 

Reduction Facilities and Associated Equipment on Oak Creek Power Plant Units 5, 6, 7 & 8 for Control of Sulfur 

Dioxide and Nitrogen Oxide Emissions, Appendix C, Emission Reduction Study, Volume I, Addendum August 20, 

2007. Unit cost ~ ($190,500,000/1,135,000 kW) (521.9/499.6) = $175 kW. 

8

 Certificate and Order, Application to Install Wet Flue Gas Desulfurization and Selective Catalytic Reduction 

Facilities and Associated Equipment on Oak Creek Power Plant Units 5, 6, 7 & 8 for Control of Sulfur Dioxide and 

Nitrogen Oxide Emissions, Case 6630-CE-299, July 10,2008. Available here: 

http://www.weenergies.comlhome/OCPP_approvalPSCWOrder.pdf. 9

 Wisconsin Power & Light Co., Certificate of Authority Application, Edgewater Generating Station Unit 5 NOx 

Reduction Project, Project Description and Justification, November 2008, PSC Ref#: 105618, p. II. The unit cost 

was calculated from the total project cost minus escalation divided by gross generating capacity or: ($153,944,000 

$14,695,000)/430 MW = $323.8/kW. 

10 AEP, 2008 Fact Book, 43rd Financial Conference, Phoenix, AZ, pdf 103. Available here: 

http://www.aep.com/investors/presentldocuments/2008EEI-Fact-Book.pdf. 
3 

MegaSymposium (provided by the NPS in an appendix). Despite the limited space and other 

obstacles, the SCR installation cost $224/kW.11 It should also be noted that the Boswell #3 

retrofit was designed to meet 0.05 Ib/MMBtu annual average and a 0.07 Ib/MMBtu 30-day 

rolling average. Burns & McDonnell reported that performance tests showed that, "Average 

NOx emissions at the outlet of the SCR reactor were 0.029 Ib/MMBtu, which is below the design 

emission rate for the SCR system (0.05 Ib/MMBtu)." The overall range for these industry 

studies is $50/kW to $400/kW.12 The upper end of this range is for highly complex retrofits with 

severe space constraints, such as Belews Creek, reported to cost $383/kW,13 or Cinergy's Gibson 

Units 2-4. Gibson, a highly complex, space-constrained retrofit in which the SCR was built 230 

feet above the power station using the largest crane in the world,14 cost $236/kW in 2009 

dollars.15 PNM has presented no valid information to show why its cost estimates should 

exceed all available industry data. 

The U.S. Forest Service (USFS) states PNM estimates a Total Capital Investment (TCI) 

for installation of SCR on Units 1-4 at SJGS to range from $423 to $568/kW (in 2010 dollars). 

Based on several studies conducted by Industry, and American Electric Power (AEP), the 

installed cost for SCR is between $75 and $240/kW in 2009 dollars. Data from EPA's Region 8 

office confirm that capital costs for SCR typically range from $73 - $243/kW; as such, PNM's 

cost analysis appears to be an overestimation. PNM has not provided valid information to justify 

their higher cost estimates for SCR installation at the SJGS. Additionally, to reach their cost 

estimates, PNM utilized methodology not approved by the EPA. PNM's contractor Black & 

Veatch based their capital cost estimates on the "Coal Utility Environmental Cost (CUECost) 

estimates, cost data supplied by equipment vendors (budget estimates), and estimates from 

previous in-house design/build projects." In using CUECost estimates, PNM's contractors went 

against the guidance of Office of Air Quality Planning and Standards (OAQPS) and EPA which 

recommends using the OAQPS Cost Manual instead to ensure a transparent and consistent 

means to assess cost analyses across the nation. NMED's December 21, 2007 letter specifically 

requested that PNM use OAQPS Cost Manual method. The USFS also takes issue with PNM's 

estimation of indirect (soft) costs which include: engineering costs; construction and field 

expenses (i.e., costs for construction supervisory personnel, office personnel, rental of temporary 

offices, etc.); contractor fees; and start-up and performance test costs. The proposal of PNM 

includes $22 million for Owner's Costs like "staff for site coordination during construction, 

equipment receiving, contract management, interface with regulatory agencies, and owner 

engineering costs." On May 10, 2010, EPA has rejected the inclusion of Owner's Costs in the 

SCR installation analysis at Milton R. Young power plant in North Dakota as these costs are not 

included in OAQPS Control Cost Manual and are not unique to a specific power plant. The $423 

 11 Minnesota Power's Environmental Improvement Plan submitted to the MN PUC 10/27/06, Docket #E015/M061501. LNB+OFA+SCR TCI = $77 million in 2006 $ on 375 (gross) MW Unit #3 = 

($77,000,000)/(375,000)(521.91499.6) = $224/kW. 

12 Exhibit 19 - lE. Cichanowicz Overview of Information on Project Control Technology Costs - October 15,2010 

13 Steve Blankinship, SCR = Supremely Complex Retrofit, Power Engineering, November 2002, Ex. 7. The unit 

cost: ($325,000,000/1,120,000 kW) (521.9/395.6) = $383/kW. 

http://pepei.pennnet.com/display_article/162367/6/ARTCL/none/none/1/SCR-=-Supremely-Complex-Retrofit/ 14 Standing on the Shoulder of Giants, Modem Power Systems, July 2002, Ex. 8. 

15 McIlvaine, NOx Market Update, August 2004, Ex. 9. SCR was retrofit on Gibson Units 2-4 in 2002 and 2003 at 

$179/kW. Assuming 2002 dollars, this escalates to ($ I79/kW) (521.9/395.6) = $236/kW. 

http://www.mcilvainecompany.com/sampieupdateslNoxMarketUpdateSample.htm 
4 

- $568/kW (in 2010 dollars) TCI provided by PNM indicates overestimates throughout their cost 

analysis. PNM's contractor Black & Veatch deviated from standard practice and because of this, 

their cost projection to control NOx with SCR at SJGS is higher than at other similar sources. 

The USFS feels these higher costs are due to flawed methodology and not to any unique 

circumstances that would make retrofitting SCR atypically expensive. The USFS believes EPA's 

proposed three year time frame to install SCR at the SJGS instead of the usual five year time 

frame is reasonable because the control technology is available and conditions at SJGS are not 

uniquely difficult to require additional time to install. The large amount NOx emissions from 

SJGS (15th largest in the nation) necessitate a tighter time frame to protect visibility conditions 

and air quality. 

Response: We found that PNM raised some legitimate points about costs, and as 

discussed elsewhere, we have adjusted several of our cost estimates upward based on those 

points. However, in large part, we agree with the NPS and the USFS that PNM’s estimated costs 

for installing SCR on the units of the SJGS are higher than justified. Please see our other 

responses to comments for more details on how we have adjusted our cost estimates. The 

following table illustrates our revised costs in terms of $/kW. These costs agree with the ranges 

presented by the NPS and the USFS in their comments: 

Table 1 

EPA Revised Estimated Costs of Installing SCR on the Units of the SJGS 

 Unit 1 Unit 2 Unit 3 Unit 4 

Proposed ($/kW) $144 $155 $116 $110 

Final ($/kW) $211 $234 $179 $165 

We note, that as required by the BART Guidelines, “[i]n order to maintain and improve 

consistency, cost estimates should be based on the OAQPS Control Cost Manual, [now renamed 

“EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/452/B-02-001, January 2002] 

where possible.” 70 FR at 39166 (July 6, 2005). We also agree with the USFS that owner’s 

costs are not an appropriate cost item to include in a BART cost estimate, as owners costs are not 

included in the Cost Manual. 

Comment: PNM and its consultants estimated the cost of retrofitting SJGS with SCRs to 

be between $194 million and $261 million per unit (depending on the unit) with a total cost of 

$908 million for all four units. EPA maintains that SCRs can be purchased and installed for 

much less – between $52 million and $63 million per unit for a total of about $229 million. 

EPA’s estimates of annual operating costs for the SCRs are also much lower than PNM’s 

estimate. PNM’s analysis indicates annual operating costs for all four SCRs would be 

approximately $114 million per year, whereas EPA expects PNM to be capable of operating the 

SCRs for only about $28 million per year. In short, EPA believes that SCRs cost $679 million 

less, or one quarter of the amount estimated by PNM. The commenter calls our cost estimate 

into question, since the disparity between these two estimates is large. 

Response: Black & Veatch estimated it would cost between $446/kW and $559/kW to 

retrofit SCR on the SJGS units. Five industry studies conducted between 2002 and 2007 have 
5 

reported the installed unit capital cost of SCRs to be $79/kW to $316/kW, where the upper end 

of the range is for very complex retrofits that are severely site constrained.16 Others have noted 

the anomalously high costs reported for SJGS.17 18 We revised our cost estimates based on some 

comments highlighted in comments, but even with those changes, our revised costs for SCR are 

from $165/kW to $234/kW,19 still well within the accepted range of expected costs for such 

controls. 

We believe the difference between our costs and Black & Veatch's costs is not due to a 

failure to consider site specific challenges. These have been specifically considered, based on 

the site visit, as documented elsewhere. The revised costs, summarized in Exhibit 1, RTC 

Revised Cost Analysis, range from $165/kW to $234/kW, well within the accepted range. Black 

& Veatch's SJGS costs are unusually high for four principal reasons: (1) using a methodology 

(e.g., Allowance for Funds Used During Construction (AFUDC)) that has been disallowed under 

EPA”s Cost Manual methodology and specifically disallowed for SCR; (2) consistently using 

assumptions at the upper end of the range for key SCR components (e.g., SCR backpressure; 

stiffening design pressure); (3) including costs for equipment that is not necessary for a SCR 

(e.g., balanced draft conversion, sorbent injection, SCR bypass); and (4) using excessive 

contingencies. The BART Guidelines require that "documentation" be provided for "any 

unusual circumstances that exist for the source that would lead to cost-effectiveness estimates 

that would exceed that for recent retrofits."20 The Black & Veatch analysis does not support its 

unusually high cost estimates. 

Further, the Black & Veatch analysis is not site specific but rather extrapolated from 

other non-similar facilities, includes nonessential components, and uses unsupported 

contingencies. The Navajo Generating Station BART analysis, conducted by Sargent and 

Lundy, for a nearby similar facility burning a similar coal with similar site constraints, is an 

example of a better supported BART cost analysis. The Navajo analysis includes appendices 

that contain: 

A: Design Basis 

B: Equipment List 

C: Meteorological Data 

D: Piping & Instrumentation Diagrams 

E: Crane Radius/Capacity Diagrams 

F: Electrical One Line Diagrams 

G: Project Schedule 

H: Contractor Schedules and Labor Rates 

I: General Arrangement Site Plans Showing SCR and Duct Work Layout 

J: Cost and Risk Analyses 

K: RFPs and Vendor Proposals 

 16 Revised BART Cost Effectiveness Analysis for Selective Catalytic Reduction at the Public Service Company of 

New Mexico San Juan Generating Station, November 2010, pp. 28-29. 

17 Comments submitted by United States Department of Interior, National Park Service, dated 3/31/11. 

18 New Mexico Environment Department, Appendix A, NMED, Air Quality Bureau, BART Determination, Public 

Service Company of New Mexico, San Juan Generating Station, Units 1-4, 6/21/10. 

19 See Exhibit 1, RTC Revised Cost Analysis 

20 70 FR at 39168 (July 6, 2005). 
6 

L: Vendor Procurement List 

M: Model Files (.jsm) 

N: Isomeric Drawings 

P: Detailed Description of Existing Facilities (underground utilities, electrical power, fan, 

air heater) 

Most of this information is missing from the Black & Veatch analysis. We believe this 

information is required to support claims that site specific issues result in costs that are outside of 

the normal range. Specifically, information such as project schedules, general arrangement site 

plans showing SCR and duct layout, requests for proposal (RFPs), vendor proposals, and a 

complete description of existing facilities are essential to document site-specific conditions that 

lead to costs outside of the normal range. 

Instead of preparing a site-specific SCR design, Black & Veatch in most circumstances 

made a worst case, upper bound assumption that, taken together, result in overall costs that are 

significantly outside of the normal range for SCR. However, Black & Veatch provided no 

record support for their decision to choose the upper end of the range for nearly every aspect of 

the cost of SCRs. It is unlikely that so many upper bound assumptions could be justified, and if 

Black & Veatch believed that they were justified, they should have explored that proposition in a 

risk analysis. Therefore, we believe that our approach to considering site specific conditions that 

would lead to costs outside of the normal range, is justified. 

Comment: It has been stated that the cost to PNM will be 500 and some people have said 

$750 million. This is not true. And we have taken the trouble to go through the numbers and 

refute them in public documents. PNM has not refuted our calculations. At the very least, PNM 

has only 46 percent of this plant, and as a result of that, its effect on PNM is half of that. We 

believe that the cost to PNM is close to $250 million, not the 500 to $750 million that has been 

stated so far. This is a modest investment in the future of the people of this area, and there is 

absolutely no threat that this plant will be closed as a result of that. There is a false dichotomy 

here between jobs and this investment. In fact, the plant will stay open and the investment is an 

investment in the future. Utilities as far away as Tucson and California are making decisions as 

to where they're going to invest their money, there's nine owners, not just PNM. The cost of 

BART needs to be considered and borne by all the owners of the SJGS.. 

Response: As we discuss elsewhere in our response to comments, we agree that the cost 

of installing SCR on the four units of the SJGS is considerably lower than PNM estimated. 

Comment: The CAA visibility provisions, EPA’s own RH regulations, and the preambles 

to those rules all envision a “source-by-source” approach to BART, which by its nature must 

account for site-specific challenges at each facility. However, despite the significant amount of 

information provided by PNM in its original BART analysis, in subsequent exchanges with the 

New Mexico Environment Department (NMED) and EPA, and in meetings between EPA and 

PNM specifically to discuss the site-specific challenges at SJGS, EPA did not to take into 

account many of the most significant costs that are essential in calculating an accurate cost 

estimate of installing SCRs at SJGS. 
7 

Response: We agree that a source-by-source analysis is appropriate. However, we do 

not agree that Black & Veatch provided a site-specific BART analysis for SJGS. The costs were 

extrapolated from other facilities,21 some based on confidential information that was not 

provided in response to requests;22 estimated using worst-case upper bounds in lieu of making a 

site-specific estimate; inflated by adding components that are not required at this site; and further 

increased using exaggerated contingency factors. In response to direct questions as to why 

various things are assumed, general site specific constraints are alleged, but none are identified 

specifically or supported with any drawings, photographs, or engineering calculations.23 

Therefore, we feel, with the exception of certain issues related to site congestion that are 

addressed separately in other comments, all costs that are properly accounted for, based on the 

available information. 

Comment: To justify the approach based entirely on the median of different control 

technologies, EPA downplays the complicated process of designing and constructing an SCR, 

thereby not only ignoring the technology itself, but also the site specific-factors that must be 

considered at SJGS. SCRs at SJGS would have to be constructed so that each SCR can be 

positioned at the proper point in the flue gas stream, which will significantly complicate the 

foundation and supports that will be needed, resulting in additional costs of $35,630,000 that 

EPA failed to recognize or consider. 

Response: All SCRs have to be constructed so that each SCR can be positioned at the 

proper point in the flue gas stream, with proper foundation and supports; this is not unique to the 

SJGS. Over 300 retrofit SCRs have been installed since the early 1990s in the United States. 

Accordingly, constructability issues are well understood. Standard design and construction 

management methods have been developed from these 300+ existing installations.24 This 

experience would inform the design and construction of the SJGS SCR, resulting in significant 

economies compared to the estimates presented by Black & Veatch based on a very rough 

preliminary design that has not been optimized for constructability. The record does not identify 

any unusual site-specific conditions that would result in direct installation costs for SJGS that are 

 21 See, e.g., 9/27/10 Norem Email to Kordzi, Responses to Questions 10 (air heater cost based on experience of 

confidential client), 11 (costs for bypass extrapolated from unidentified unit), 18 (factored estimates based on 

"B&V's significant experience" with no further explanation); 10/8/10 Norem Email to Kordzi, Response to 

Questions 2 (asking for SCR catalyst design basis and being pointed to other facilities), 3 (air heater modifications 

and balanced draft conversion costs from other projects), 6 (ammonia system cost scaled from SJRPP), 8 (elevator 

costs scaled from SJRPP), 11 (structural steel scaled from SJRPP); Discussion of OAQPS Cost Manual Method for 

AQCS Estimation, Section 4.0 (explaining how costs were extrapolated from bids for SJRPP). 

22 See, e.g., 9/27/10 Norem Email to Kordzi, Responses to Questions 1 (request for Excel version of cost 

spreadsheets so calculations could be inspected refused), 2 (request for basis of 77% NOx control not fully 

addressed), 9 (request for basis of catalyst life not fully addressed), 20 (request for basis of scaling factors from 

proprietary database). 

23 9/27/10 Norem Email to Kordzi, Responses to Questions 3 (no plot plans exist), 15 (high lost generation due to 

unidentified site-specific constraints), 17 (high contingency factor due to site specific challenges not "fully resolved" 

or "fully determined"). 

24 J.A. Hines and others, Design for Constructability -- A Method for Reducing SCR Project Costs, Mega, 2001, 

available at: http://www.babcock.com/library/pdf/br-1720.pdf; see also Institute of Clean Air Companies (ICAC), 

White Paper, Selective Catalytic Reduction (SCR) Control of NOx Emissions from Fossil Fuel-Fired Electric Power 

Plants, May 2009, EPA-R09-OAR-2009-0598-0032 and Walter Nischt and others, Update of Selective Catalytic 

Reduction Retrofit on a 675 MW Boiler at AES Somerset, ASME International Joint Power Generation Conference, 

July 24-25, 2000, available at: http://www.babcock.com/library/pdf/br-1703.pdf. 
8 

substantially higher than upper bound direct installation costs reported by other SCR design 

firms for similarly complex sites. In fact, Black & Veatch has provided no support in the record 

for its assumptions. Finally, the design costs are not a direct installation cost, but rather indirect 

costs discussed elsewhere in our response to comments. 

Comment: EPA suggests that the engineering needed to design four SCRs can be 

completed all at the same time, thus saving time and money. While some economies may arise 

with a multiple SCR installation, as lessons learned in designing and installing one SCR are 

applied to the next, a three-year deadline would require PNM to design all four SCRs at the same 

time. Designing all four SCRs at once would require four separate design and construction 

teams, which would eliminate the opportunity to apply any experience gained. As a result, the 

costs associated with designing the SCRs will be much higher on a shorter timeframe, not lower 

as EPA appears to suggest. The short, three-year deadline also allows no time for additional 

design work that may be needed to address unforeseen engineering challenges that are likely to 

arise at each unit. 

Response: We disagree with this comment and believe it mischaracterizes our analysis. 

In our proposal, we simply noted that "multiple unit discounts may apply to much of this 

equipment."25 Multiple unit discounts were not assumed in our revised cost analysis. It is well 

established that economies arise from constructing multiple units at a single site. Economies will 

arise, for example, from common equipment that would serve all four units, such as the ammonia 

injection system and the control system. Economies arise from shop and material discounts 

based on quantity. Our cost analysis, however, did not assume any discount for multiple unit 

discounts. Regardless, for other reasons as stated elsewhere in our response to comments, we are 

finalizing a schedule which calls for compliance with the emission limits within 5 years – rather 

than 3 years – of the effective date of our final rule. 

Comment: The proposed FIP costs do not acknowledge, or take into account, the $330 

million incurred in the past five years implementing a comprehensive emission control plan at 

SJGS. EPA’s proposed BART determination for the SJGS is too expensive and EPA should 

accept the recently installed pollution control equipment at the SJGS as BART. 

Response: We did, as part of our NOx BART evaluation, consider the controls 

previously installed by PNM as a result of its March 10, 2005 consent decree with the Grand 

Canyon Trust, Sierra Club, and NMED. These controls included the installation of low-NOx 

burners with overfire air ports, a neural network system, and a pulse jet fabric filter. However, 

BART is defined 26 as: 

an emission limitation based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction for each pollutant 

which is emitted by an existing stationary facility. The emission limitation must 

be established, on a case-by-case basis, taking into consideration the technology 

available, the costs of compliance, the energy and nonair quality environmental 

 25 Revised BART Cost Effectiveness Analysis for Selective Catalytic Reduction at the Public Service Company of 

New Mexico San Juan Generating Station, November 2010, p. 5. 

26 40 CFR 51.301. 
9 

impacts of compliance, any pollution control equipment in use or in existence at 

the source, the remaining useful life of the source, and the degree of improvement 

in visibility which may reasonably be anticipated to result from the use of such 

technology. 

Therefore, we are obligated by the RHR to examine additional retrofit technologies.27 In 

so doing, we have determined that SCR is cost effective and results in significant visibility 

improvements at a number of Class I areas, over and above the existing pollution controls 

currently installed. 

Comment: EPA states in its proposal that the Agency “believe[s] that an implementation 

plan that provides for emissions reductions consistent with the assumptions used in the WRAP 

modeling will ensure that emissions from New Mexico sources do not interfere with the 

measures designed to protect visibility in other states.” 76 Fed. Reg. at 496-97. EPA states that 

the WRAP modeling assumed that SJGS’s NOx emission rate would be limited to 0.27 

lb/MMBtu for units 1 and 3 and 0.28 lb/MMBtu for units 2 and 4 in 2018. Id. at 497. The 

Agency proposes to conclude that, because SJGS currently is subject to a federally enforceable 

permit limit of 0.30 lb/MMBtu for NOx, which is less restrictive than the WRAP modeling’s 

assumed NOx rates for those units (as characterized by EPA), additional NOx emission controls 

are required. EPA, however, proposes on this basis to determine that the BART emission limit 

for units 1 through 4 at SJGS is not 0.27 (or 0.28) lb/MMBtu but is instead 0.05 lb/MMBtu based 

on the application of SCR technology. Id. at 498. EPA acknowledges that other technologies, 

including SNCR, are technologically feasible, but it proposes, with little elaboration, to 

determine that those technologies are not “capable of significantly improving” visibility in 

specified Class I areas. Id. at 502. As a result, EPA discontinues its evaluation of them before 

fully assessing their relative cost-effectiveness and other factors mandated by section 169A(g)(2) 

of the Act. See id. EPA’s analytical approach is in conflict with its own BART rules and is 

inconsistent with a logical approach to assessing relative cost-effectiveness of various 

technology options. Cutting off a full analysis after evaluating only relative visibility impacts 

precludes that necessary comparative assessment. 

Response: We disagree with this commenter’s characterization of our analysis. As 

discussed in our proposal (76 FR 491), once we established that units 1, 2, 3, and 4 of the SJGS 

were subject to BART, we conducted a full five factor BART analysis (40 CFR 

51.308(e)(1)(ii)(A)), rather than relying on the WRAP modeling. In conducting the BART 

analysis, we identified all available retrofit control technologies, including Selective Non 

Catalytic Reduction (SNCR), considering the technology available, the costs of compliance, the 

energy and non-air quality environmental impacts of compliance, any pollution control 

equipment in use at the source, the remaining useful life of the source, and the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such 

technology. In so doing, we did assess other NOx control technologies. 28 

 27 “You are expected to identify potentially applicable retrofit control technologies that represent the full range of 

demonstrated alternatives.” 70 FR at 39164. 

28 76 FR at 499. 
10 

Comment: Several commenters stated EPA should follow its own promulgated RHR and 

follow New Mexico’s recommendation for BART determinations. These commenters are 

referring to the proposal that was sent to New Mexico’s Environmental Improvement Board on 

February 11, 2011 (later formally submitted to EPA on July 5, 2011). The proposed revision to 

the SIP finds that BART for SJGS is SNCR - not SCR. One commenter believed that the 

application of the 2005 BART Guidelines supports a NOx emission rate for the SJGS of between 

0.23 to 0.39 lb/MMBtu, as opposed to our proposed FIP of 0.05 lb/MMBtu, which requires 

costly SCR technology. One commenter stated the presumptive limits should be required 

“unless you [the BART-determining authority] determine that an alternative control level is 

justified based on consideration of the statutory factors.” 70 FR at 39171. Except for cyclone 

boilers (which are not present at SJGS), this commenter noted, our presumptive NOx BART 

limits are not based on application of SCR; as noted above, they are instead based on the use of 

combustion controls. Further, EPA determined that when current combustion control technology 

would be insufficient to meet the presumptive limits, it would be appropriate to “consider 

whether advanced combustion control technologies such as rotating opposed fire air should be 

used to meet these [presumptive] limits.” Id. at 39172. Another commenter asserted that a 

proper BART assessment would take the presumptive limits into account by beginning with the 

assumption that the established presumptive limit for these units is appropriate, and then would 

proceed with an analysis of whether the least stringent control options could achieve that limit. 

A five-factor BART analysis of increasingly stringent control options could then properly assess 

incremental costs (and cost-effectiveness) and any benefits of requiring more stringent controls. 

Response: We note the RHR states: 

For each source subject to BART, 40 CFR 51.308(e)(1)(ii)(A) requires that States 

identify the level of control representing BART after considering the factors set out in CAA 

section 169A(g), as follows: 

States must identify the best system of continuous emission control technology for each 

source subject to BART taking into account the technology available, the costs of compliance, 

the energy and non-air quality environmental impacts of compliance, any pollution control 

equipment in use at the source, the remaining useful life of the source, and the degree of 

visibility improvement that may be expected from available control technology29

The RHR also states: 

States, as a general matter, must require owners and operators of greater than 750 MW 

power plants to meet these BART emission limits. We are establishing these requirements based 

on the consideration of certain factors discussed below. Although we believe that these 

requirements are extremely likely to be appropriate for all greater than 750 MW power plants 

subject to BART, a State may establish different requirements if the State can demonstrate that 

an alternative determination is justified based on a consideration of the five statutory factors. 30

 29 70 FR at 39158. 

30 70 FR at 39131. 
11 

We followed the five statutory factors when assessing NOx BART at the SJGS, in 

determining that a different level of BART control was warranted.31 This analysis included an 

examination of whether other technologies should be BART for the SJGS. We also performed 

our BART evaluation on the basis of increasingly stringent levels of control and assessed 

incremental costs and cost effectiveness. Thus, we do not believe we improperly truncated the 

NOx BART assessment for the SJGS. 

 

We received a New Mexico RH SIP on July 5, 2011. This SIP does contain a revised 

BART analysis that concludes that NOx BART for the SJGS should be SNCR and an emission 

rate of 0.23 lb/MMBtu on a 30-day rolling average. We will review the State RH SIP submittal, 

and if there is significant new information that changes our analysis, we will make appropriate 

revisions to today’s decision. However, the State RH SIP recommends SNCR as BART, and we 

have considered that technology in the context of responding to other comments in this notice. 

For the reasons discussed in our proposal (76 FR 491), and in other responses to comments, we 

have concluded that BART for the SJGS is an emission limit of 0.05 lbs/MMBtu, based on a 30 

BOD average, more stringent than the levels achievable by the SNCR technology recommended 

by the State. 

Comment: To meet a three-year deadline, PNM would have to prefabricate as much of 

the SCRs as possible. In addition, a three-year deadline would also require significant overtime 

hours, expedited material costs, double “heavy long-lift” crane costs, and a larger construction 

workforce overall. Because these costs would never be incurred in the normal course of 

installing SCRs, PNM did not include these costs in its analysis, but they would be unavoidable 

in the event a three-year deadline is required. Such a short construction deadline would also 

exacerbate the shortage of skilled labor caused by the significant number of similar projects that 

are either ongoing or planned for the near future in the region. The failure to account for the 

additional labor costs associated with such a short timeframe, particularly given other factors 

affecting the market for skilled labor, renders both the three-year deadline and the cost estimate 

prepared by EPA unrealistic. 

Response: The information in the record does not demonstrate a shortage of labor 

necessary to complete the installation of SCRs at the SJGS. However, as stated elsewhere in our 

response to comments, we have modified the schedule for compliance with the emission limits to 

now require compliance within 5 years – rather than 3 years -- from the effective date of our final 

rule. We believe this compliance schedule will provide adequate time to schedule the necessary 

labor resources for the installation of controls at the SJGS. 

Comment: The NPS recommends that in addition to the $/ton metric, we evaluate the 

visibility metric $/deciview as an additional tool to report the benefits of emissions controls. The 

NPS contends that BART is not necessarily the most cost-effective solution. Instead, it 

represents a broad consideration of technical, economic, energy, and environmental (including 

visibility improvement) factors. For example, Oregon DEQ has established a cost/ton threshold 

of $7,300 based upon the premise that improving visibility in multiple Class I areas warrants a 

higher cost/ton than where only one Class I area is affected. The NPS states that in their BART 

proposal for SJGS, New Mexico used a range from $5,946/ton to $7,398/ton. Colorado uses 

 31 76 FR 491, 499. 
12 

$5,000/ton, New York uses $5,500/ton, and Wisconsin is using $7,000 -$10,000/ton as its BART 

threshold. EPA has proposed SCR at the Four Corners Power Plant at $2,600 -$2,900/ton, and at 

SJGS at $1,600 - 1900/ton. 

One of the options suggested by the BART Guidelines to evaluate cost-effectiveness is 

cost/deciview. The NPS believes that visibility improvement must be a critical factor in any 

program designed to improve visibility. The NPS goes on to provide several examples of 

$/deciview calculations. 

Two other comments recommend we employ the $/deciview metric. One commenter 

states EPA has not appropriately considered the costs of compliance for any proposed BART for 

the SJGS because it relies on a $/ton metric. The commenter maintains that cost should be 

related to the amount of visibility improvement that it is projected to achieve and proposes the 

$/dv as the means for making a rational comparison of the relative cost-effectiveness of control 

measures. 

This commenter also states that a method that aggregates projected visibility 

improvement in each affected class I area is not appropriate for several reasons. That approach 

masks the fact that it is cumulative over time and space and does not represent actual change at 

any one class I area. That approach also ensures an artificially low measure of cost-effectiveness 

simply by allowing the control cost to be divided by a larger value. The commenter suggests that 

a $/dv metric expressed as a range of the values for each affected class I area would be an 

appropriate means for comparing cost-effectiveness of different controls. The commenter states 

that EPA’s current measure of cost-effectiveness in terms of $/ton is virtually meaningless in the 

context of the RH program. Thus, EPA’s assessment of the $/ton costs of BART candidates for 

the SJGS is flawed because the premise for its use is faulty, i.e., a change in emissions is not a 

suitable surrogate to represent a change in visibility. 

Another commenter believes that a dollar per deciview of visibility improvement metric 

would be more in line with the overall goal of the RH program, namely to improve visibility in 

national parks and wilderness areas. To properly gauge cost-effectiveness, EPA must consider 

the fact that installing SCRs at San Juan will cost between $78 million and $336million per 

deciview, depending on the Class I area. 

Response: The BART Guidelines require that cost effectiveness be calculated in terms of 

annualized dollars per ton of pollutant removed, or $/ton32. The commenters are correct in that 

the BART Guidelines list the $/deciview ratio as an additional cost effectiveness measure that 

can be employed along with $/ton for use in a BART evaluation. However, the use of this metric 

further implies that additional thresholds of acceptability, separate from the $/ton metric, be 

developed for BART determinations for both single and multiple Class I analyses. We have not 

used this metric because (1) we believe it is unnecessary in judging the cost effectiveness of 

BART, (2) it complicates the BART analysis, and (3) it is difficult to judge. We conclude it is 

sufficient to analyze the cost effectiveness of potential BART controls using $/ton, in 

conjunction with the modeled visibility benefit of the BART control. We have addressed the 

 32 70 FR 39167. 
13 

commenter’s statement that we should not aggregate visibility improvement over Class I areas 

elsewhere in our response to comments. 

2. Comments on Specific Cost Line Items 

Comment: The NPS stated that PNM has improperly rejected use of the Cost Manual in 

favor of methods not allowed by EPA. The NPS states the SCR cost estimates submitted by 

PNM are severely lacking in the types of specific information needed to give them credibility. 

The NPS goes on to provide a great deal of detailed information that supports their opinion that 

specific cost items were overestimated. This information includes the following cost item 

categories: 

Appropriateness of using the Cost Manual 

Problems in Black & Veatch’s scaling of cost items from another project 

Ductwork and ammonia grid costs 

Reactor box and breaching 

Expansion joints 

Sonic horns 

Elevator 

Structural steel 

SCR bypass 

Catalyst 

NOx monitoring 

Auxiliary electrical system upgrades 

Instrumentation and control systems 

Air preheaters 

Balanced draft conversion 

Contingencies 

Operating Labor 

Reagent 

Auxiliary power demand 

Catalyst life 

Interest rate 

Effect on cost of PNM’s assumption of an emission rate of 0.07 lbs/MMBtu 

The NPS concluded their critique of PNM’s cost estimate with their own estimate of an 

average cost of $2,600/ton for the four units of the SJGS. 

Response: We agree with the general contention that many individual cost items for the 

installation of SCR on the units of the SJGS were overestimated by PNM. Please see elsewhere 

in our response to comments for our opinion regarding the appropriate estimated costs for these 

and other cost items. We note that the NPS estimate of an average cost of $2,600/ton for the four 

units of the SJGS closely agrees with our own revised estimate. 

Comment: EPA failed to account for the costs associated with ensuring sufficient 

auxiliary power to operate SCRs at SJGS. The Region 6 cost analysis recognizes that the 
14 

installation of SCRs at SJGS will require additional auxiliary power that is currently unavailable 

with the existing auxiliary power sources. That additional auxiliary power would be needed to 

operate the larger fans that the SCR would require, and to operate other existing fans at a higher 

operating levels to overcome the additional differential pressure resistance that an SCR would 

add to the flue gas path for each unit. Without upgrades to the auxiliary power system, the SJGS 

units would be unable to achieve rated capacity and overall efficiency of the units would 

decrease. Accordingly, PNM’s estimate includes the costs associated with upgrades that would 

be needed to ensure sufficient auxiliary power is available for SCR operation and allow the units 

to achieve rated output capacity. Region 6 discounted by nearly 80 percent the estimated cost of 

the auxiliary power upgrades needed to power the SCRs. The theory behind this sharply 

discounted cost estimate is that the SCRs will only be responsible for approximately 20 percent 

of the total draft pressure of the units and that therefore the cost of the auxiliary power upgrades 

should be allocated in similar fashion. Region 6’s approach complicates an otherwise simple 

issue. Without SCRs, no additional auxiliary power would be needed; with SCRs, auxiliary 

power upgrades would be critical to the continued safe and reliable operation of the units. As 

such, those costs must be included in the cost of the SCRs, as they represent one of the sitespecific concerns that could make the installation of SCR at SJGS more difficult than other units. 

The decision by Region 6 to exclude these costs underestimates the cost of SCRs for SJGS by 

$73,175,000. 

Response: This comment states that installing SCRs would by itself trigger the need to 

upgrade the auxiliary power system. We believe this is incorrect. The auxiliary power upgrade 

is required due to the cumulative effect of the Consent Decree projects (LNBs/OFA, scrubber 

upgrade, baghouse, carbon injection) and the SCR. These projects were planned around the 

same time. PNM has not identified any reason to single out the SCR to bear 100% of the costs. 

Further, the upgrade benefits the entire auxiliary power system. The modifications, for example, 

include new transformers, switchgear, and motor control centers that will serve the entire fan 

auxiliary loads of both the Consent Decree projects and the SCR.33 The modifications also 

include replacing the existing fans with upgraded units. Obviously, these fans will service more 

than just the SCRs. 

The SCR project was initially evaluated at the same time that the Consent Decree projects 

were being designed.34 The auxiliary power system upgrade cost was not in the initial Black & 

Veatch BART cost effectiveness analysis.35 At the time these projects were being planned, no 

upgrade was believed to be required. However, after the Consent Decree projects were 

operating, PNM realized an upgrade would be required as the cumulative effect of these control 

projects exceeded the capacity of the auxiliary power system. 

 

 33 Black & Veatch, San Juan Generation Station BART Project, Review and Update of 2007 BART Cost Estimates, 

October 22, 2010 (B&V 10/22/10 Cost Analysis), Sec. 3.0 and 11/4/10 Norem Email to Kordzi, Re: Questions on 

PNM's Revised Cost Estimate for the SJGS SCR Project, Response to Question 3, Table 3 of attachment 1. 

34 See, e.g., 6/7/07 B&V BART Analysis, pp. ES-1, 1-1. 

35 B&V 10/22/10 Cost Analysis, pp. 3-6 ("In the initial 2007 estimate, PNM expected the existing auxiliary power to 

be sufficient. However, now that the consent decree AQC equipment has been installed, B&V has determined that 

the current auxiliary power system is not sufficient to power the additional loads that would result from adding SCR 

and associated equipment."). 
15 

This comment advocates attributing 100% of the cost of the auxiliary power system 

upgrade, recognized after the fact, to the last project to be implemented, the SCR. This is 

contrary to standard practice which distributes cost among projects that benefit from a change 

according to their proportional share. 

We did not "discount" the cost of the auxiliary power system by 80%, but rather 

distributed it among the control projects planned around the same time that triggered its need 

according to each control's contribution to draft pressure lost. This is a standard engineering 

practice. 

Comment: EPA failed to account for additional costs associated with protecting the air 

preheater following an SCR Installation. Retrofit SCRs are designed to convert NOx into 

nitrogen gas and water through the injection of ammonia into the flue gas in the presence of a 

catalyst. However, that same ammonia also reacts with sulfur in the flue gas downstream of the 

SCR forming ammonium bisulfate (ABS), which condenses in the air preheater where flue gas 

temperatures drops to the dew point of ABS. ABS is an acidic substance that forms a sticky 

deposit on heat transfer surfaces, resulting in both corrosion of the equipment and the collection 

of fly ash that plug passages, which ultimately impairs the efficiency and reliability of the unit. 

As such, the installation of a retrofit SCR generally requires a modification to the air preheater to 

allow for easier cleaning of the basket surfaces in order to protect the heat transfer elements 

against the potential damage that might otherwise result from ABS. Region 6 deleted the costs 

of protecting the air preheater in its SCR cost analysis, “pending compelling justification that 

they are required for the SCR.” Region 6’s cost analysis recognizes that modifications to the air 

preheater are generally required for “units that burn high sulfur coal,” but Region 6 assumes that 

such modifications are not necessary “for a properly designed SCR on a boiler that burns low 

sulfur coal.” Without further defining the difference between “high” and “low” sulfur coal, 

Region 6 assumes that SJGS would not experience significant ABS formation using a low 

oxidation SCR catalyst and an ammonia slip of 2 ppm. As justification for deleting the air 

preheater costs, Region 6 cites to a BART analysis recently prepared by Sargent and Lundy for 

the Navajo Generating Station, which did not recommend modification of the air preheater if 

SCR were required for that facility. Region 6 also cites an article from an air preheater vendor 

for support as well. The two materials cited by Region 6 do not support its conclusion that ABS 

“is not an issue” for units combusting low-sulfur coals. First of all, the Navajo Generating 

Station does not actually have an SCR, so the assumptions and recommendations made in the 

BART determination report prepared for that source are not based on actual operating 

experience. Perhaps more importantly, however, the Region’s characterization of the report as 

suggesting that ABS is not a concern is inaccurate. On the contrary, the BART analysis prepared 

for the Navajo Generating Station includes the following discussion of the dangers of ABS 

formation in the air preheater following installation of an SCR: 

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

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

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

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

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

preheater. If favorable conditions for this reaction persist and ammonia concentrations reach 
16 

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

required. ABS will condense from the gas stream and form a sticky deposit on the heat transfer 

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

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

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

loss in thermal efficiency for the plant. 

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

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

ammonium bisulfate and accelerates the plugging mechanism. The ABS dew point while 

burning bituminous fuel will be in the temperature range of 590 °F to 615 °F. The melting point 

of this compound is 300 °F and the boiling point is 914 °F. Once this compound is formed, it 

will be in liquid phase above 300 °F and the solid phase below 300 °F. Therefore, all metal 

surfaces of the APH from 300 °F to 615 °F will be subjected to ammonium bisulfate deposition. 

Since the air heater outlet temperatures of both Navajo Generating Station and SJGS are below 

the 300o F threshold, both projects units would be at risk for ammonium bisulfate deposition 

upon installation of an SCR. Region 6 is correct that, in spite of the quoted discussion above, 

Sargent & Lundy did not recommend air preheater modifications in the SCR cost analysis for the 

Navajo Generating Station. However, that recommendation was based on the specific emission 

characteristics at Navajo Generating Station, which differ significantly from those at SJGS. For 

instance, although SJGS does burn relatively low sulfur coal, the sulfur content is still typically 

higher than that of the coal burned at the Navajo Generation Station. In addition, the higher 

heating value (HHV) of the SJGS coal is 1000 Btu/lb lower than coal burned at Navajo 

Generating Station and the ash content is one-hundred-eight percent (108%) higher. The higher 

ash content increases the risk of pluggage associated with ABS if SCRs are installed at SJGS. 

The difference between SJGS and the Navajo Generating Station seem to have been completely 

ignored in the effort to rely on the BART determination for the Navajo Generating Station to 

delete the air preheater costs from the SJGS estimate prepared by Black & Veatch. 

The article cited by Region 6 to suggest that air preheater modifications are only required 

for units that burn high sulfur coal also does not support Region 6’s position. To the contrary, 

rather than focusing on the level of sulfur in the flue gas the article simply states that “[b]ased 

upon the sulfur content of most American coals, predominantly ammonium bisulfate will form.” 

Since ammonia would be absent from the flue gas stream without SCRs, any formation of ABS 

at SJGS would be entirely attributable to the installation of the SCRs. The article cited by Region 

6 also notes that, even in “low ammonia slip designs, fouling has often been observed due to 

increases of slip during transient load conditions.” In other words, even if ammonia slip is 

generally kept below 2 ppm, changes in load will likely result in higher slip that will form ABS 

in the air preheater. Region 6 ignores this fact in its analysis. 

Response: This comment attempts to distinguish the emission characteristics of Navajo 

Generating Station and SJGS by pointing to differences in the coal quality to support air 

preheater modifications at SJGS but not at Navajo. However, PNM did not supply coal quality 

data for Navajo, but rather generically describes only three parameters. We obtained the Navajo 

design basis coal quality, which is compared to SJGS below: 
17 

Table 2, Comparison of Coal Quality 

SJGS and Navajo Report on As Received Basis 

Plant Sulfur

(%) 

Ash 

(%) 

Heat 

Content

(Btu/lb)

SJGS36 0.77 21.29 9,692

Navajo37 0.63 10.36 10,418

The differences in coal quality are either not material (sulfur, heat content) or mitigate the 

potential impacts of ammonium bisulfate plugging (higher ash at SJGS). The material following 

the passage quoted above from the Sargent & Lundy Navajo BART analysis indicates that the 

key factors that determine whether ammonium bisulfate plugging will occur are not coal quality, 

but rather the amount of sulfur trioxide (SO3) and ammonia (NH3) in the exhaust gases that reach 

the air preheater and the air preheater temperature regime.38 

The amount of ammonia is an SCR design parameter and is controlled by the ammonia 

injection system, not coal quality. The design ammonia slip for both the SJGS and Navajo SCRs 

is 2 ppm. Regardless of small differences in coal sulfur content, some of which becomes SO3, 

actual test data indicate that SO3 concentrations are somewhat higher at Navajo than at SJGS,39

indicating a greater likelihood of ammonia bisulfate plugging at Navajo than at SJGS. The 

exhaust gas temperatures at the air preheaters at the two plants are about the same. 

The formation of ammonium bisulfate depends on the relative amounts of NH3 and SO3

in the exhaust gases. When the molar ratio is more than 2:1, ammonium sulfate is formed.40 The 

average molar ratio for both SJGS and Navajo over the catalyst lifetime is much higher than 

2:1.41 Thus, ammonium sulfate would be preferentially formed. Ammonium sulfate is a dry 

powder at all air preheater operating temperatures and does not create a fouling problem. Thus, 

consistent with Sargent & Lundy's conclusion for the nearby Navajo Generating Station, which 

burns a similar coal, ammonium bisulfate fouling would not be expected and no upgrades are 

justified for the air preheaters due to SCR installation. 

 36 6/7/07 B&V San JuanBART Analysis, p. A-2. 

37 8/17/10 Salt River Project Navajo Generating Station Units 1, 2, 3 SCR and Baghouse Capital Cost Estimate 

Report (S&L Navajo Cost Analysis), Appendix A, p. 3. 

38 See, e.g., 8/17/10 S&L Navajo BART Analysis, pp. 3-4 - 3-5, cited by PNM. 

39 Compare SO3 concentrations reported in the 8/17/10 S&L Navajo Cost Analysis, p. 3-5 (3.72 ppmvd) with those 

measured at San Juan in 10/8/10 Norem Email to Kordzi, Source Emissions Testing Report for Public Service New 

Mexico: San Juan Generating Facility, Units 1 and 3, March 11, 2009, p. 3 (0 - 2.0 ppmvd). 40 Louis P. Bondurant III, SCR Compatibility for the Ljunstrom Air Preheater, p. 2, Available at: 

http://www.airpreheatercompany.com/Data/DownloadDocuments/Mega%20Symposium%201999.PDF. 41 The average NH3 slip concentration over the catalyst lifetime is 0.75 ppm (EPRI, Estimating Total Sulfuric Acid 

Emissions from Stationary Power Plants, 2010, p. 4-10). The NH3 flow rate for each unit is reported in the 11/10 

Fox Report, Ex. 1 and an elevated (10x times higher than measured) estimate of SO3 is reported in the 6/7/07 B&V 

BART Analysis, Appx. A, p. A-3. Thus, taking Unit 4 as an example. Moles of NH3 = (533 lb/hr)(0.25/0.24)(0.75 

ppm/2.0 ppm)/17 lb/lb-mol = 12.2 lb-mol/hr. Moles of SO3 = (112 lb/hr)(0.1)/80 lb/lb-mol = 0.14. Molar ratio 

NH3:SO3 = 12.2/0.14 = 87. Thus, ammonium sulfate would form over almost the entire lifetime of the catalyst 

(NH3 slip >0.02 ppm) as the SO3 concentration is so low, e.g., even when the catalyst is new and the slip is just 

0.02 ppm, the molar ratio would be greater than 2. 
18 

Finally, the claimed 108% higher ash at SJGS will reduce the likelihood of any 

ammonium bisulfate plugging at SJGS, compared to Navajo, as the SO3 and ammonium bisulfate 

are absorbed by the ash particles before they reached the air preheater and are carried through the 

air preheater. Further, the high ash content of the coal provides some abrasive cleaning of the air 

preheater, minimizing any potential impact.42 In fact, particle injection upstream of the air 

preheater has been used as a control technology for SO3. Particles have been intentionally 

injected into the flue gas upstream from the air preheater to enhance SO3 removal. The particles 

provide nucleation sites for heterogeneous condensation in preference to condensation on metal 

air preheater surfaces.43 As SJGS is claimed to have 108% higher ash than Navajo, SJGS would 

be expected to have a much lower air preheater fouling potential than Navajo, where Sargent & 

Lundy concluded air preheaters modifications were not required. 

Thus, for all of these reasons, ammonia bisulfate deposition should be less of a concern at 

SJGS than at Navajo. Sargent & Lundy concluded based on a more complete SCR design than 

available for SJGS that air preheater modifications were not required, as this excerpt from the 

Navajo BART analysis demonstrates: 

3.5.5.3 Air Preheater Recommendation 

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

value during initial operation to less than 2 ppm towards the end of the catalyst 

life. After the SCR installation, SO2 levels as high as 6 ppmvd at 3% O2 are 

possible. SRP currently operates on a three year outage cycle which will require 

the SCR systems to operate at close to 100% reliability. Significant ABS 

formation and air preheater plugging is not expected due to the low SO2 content in 

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

required. 

Ammonia bisulfate plugging is controlled by designing the SCR to reduce the likelihood 

of its formation in mild cases such as these where SO3 and NH3 flue gas concentrations are low. 

The key design methods are ensuring proper catalyst design, including 2 ppm ammonia slip and 

maximum 0.5% oxidation of SO2 to SO3 across the SCR reactor and ensuring NH3/NOx 

distribution requirements are confirmed by CFD and physical flow modeling to avoid large areas 

of high ammonia slip.44 These standard practices presumably will be used to design the SJGS 

SCR. Thus, PNM has not documented any reason to conclude that air preheater modifications 

will be required at SJGS but not at Navajo. In fact, it has provided data within its own comment 

that indicate that ammonium bisulfate plugging of the air preheaters is not a concern. 

 42 Bondurant III 2008, p. 2 ("...a significant portion of the ABS formed collects on the ash particles, and carries 

through the air preheater...Additionally, fly ash does provide some degree of abrasive cleaning."). 43 E. Bowes et al., Sulfur Trioxide Reduction Technology Demonstration at Dominion Generation’s Chesterfield 

Power Plant, PowerGen, 2006; Bowes et al., Sulfur Trioxide Reduction Technology Demonstrated at Dominion 

Generation’s Chesterfield Power Station, Mega Symposium, August 2006. 

44 8/17/10 S&L Navajo Cost Analysis, p. 3-7. 
19 

It is true that any formation of ammonium bisulfate (ABS) would be due to NH3 injected 

for the SCR. However, the NH3 injected for the SCR does not necessarily form ABS. The cited 

article, SCR Compatibility for the Ljunstrom Air Preheater, explains, as noted above, that when 

the ratio of NH3 to SO3 is greater than 2, as is the case here, that ammonium sulfate is formed, 

rather than ammonium bisulfate. Ammonium sulfate does not foul the air preheaters. The article 

goes on to state that "based upon the sulfur content of most American coals, predominately 

ammonium bisulfate will form and the ammonia slip level will be the controlling factor in the 

extent to which these deposits interfere with routine unit operation."45 The sulfur content of the 

SJGS coal, 0.77%, is low compared to most American coals, which typically have from 1% to 

4% sulfur. 

Comment: Region 6 Failed to Account for Code Required Boiler Stiffening. The 

installation of SCR at SJGS would increase the resistance in the flue gas path for the units. To 

overcome that additional resistance, PNM would need to install new higher capacity fan rotors 

and motors because the SCRs will add an additional pressure drop in the system of 10 inches of 

water. This change in pressure and higher fan pressure ratings would increase the potential risk 

of a boiler implosion during transient (upset or malfunction) conditions. The analysis prepared 

by Black & Veatch of the expected cost of an SCR retrofit includes the costs to mitigate the 

implosion risk by converting to balanced draft and stiffening the boiler and associated flue gas 

path. The specific recommendation made by Black & Veatch ensures that the SJGS boilers 

would remain in compliance with the National Fire Protection Association (NFPA) Code 85. 

NFPA 85 governs fire and implosion protection for Boilers and Combustion Systems and 

establishes structural and controls design requirements that must be incorporated. Throughout 

the industry, state inspection authorities and insurers routinely use NFPA 85 as a minimum 

standard to determine when a boiler requires stiffening for implosion and explosion protection. 

SJGS is currently in compliance with the NFPA 85 and therefore would not need to stiffen the 

boiler in the absence of the proposed FIP requiring SCRs. 

Region 6 recognizes in its cost analysis that larger ID fans will be needed and that an 

SCR would increase the flue gas pressure drop through the units by 10 inches of water. Region 

6’s conclusions with regard to the size of the fans needed, however, are unsupported, and fail to 

take into account the need to add additional operating margin to the fan capacity. Region 6 also 

concludes that additional boiler stiffening would not be required, stating simply that “a balance 

draft conversion with the proposed stiffening is not part of an SCR project.” Based on the 

analysis performed so far, boiler stiffening would be a necessary part of any SCR project at 

SJGS to maintain a safe and reliable facility that also meets code requirements. Costs associated 

with code compliance must be taken into account in making a site-specific BART determination 

for SJGS. Region 6 improperly focuses on other pollution control equipment that already exists 

at the site in an effort to argue that those controls, not the SCR, trigger the need for additional 

boiler and duct stiffening. In fact, partial boiler stiffening was already performed during the 

installation of the existing controls to bring the unit into compliance with NFPA 85. However, 

an SCR would present additional draft system pressure concerns beyond that presented during 

the installation of the existing control equipment. 

 45 Bondurant III 2008, p. 2. 
20 

Response: We note that the pressure drop due to the SCR was assumed to be 10 in. wg,46

which is at the upper end of the usual range of 3 to 10 in. wg. The overall SCR system pressure 

drop consists of losses from the SCR catalyst, static mixers, and duct work. Determining the 

pressure drop due to the SCR requires a more advanced design than presented in the Black & 

Veatch BART analysis. Instead, Black & Veatch appears to have selected the upper end of the 

range. This record, for example, contains no duct arrangement drawings; no catalyst vendor 

quotes; does not identify the type of catalyst, e.g., honeycomb or plate; does not specify the 

catalyst pitch; and is silent as to static mixers, all important factors in determining the pressure 

drop due to the SCR. 

Thus, we do not believe there is a basis for the 10 in. wg used to cost boiler stiffening and 

to justify balanced draft conversion. This pressure drop likely has not been optimized and could 

be significantly reduced by catalyst selection (e.g., by using honeycomb with large pitch)47 and 

ductwork design. An SCR system is normally designed to optimize distribution of flue gas, 

reactant, and gas temperature while minimizing pressure drop.48 The pressure drop is typically 

minimized, for example, by expanding the flue gas path and by catalyst selection.49 A high 

pressure drop SCR is generally associated with a "high velocity SCR" designed for low NOx 

removal, 30% - 50%.50 The basis for selecting 10 in. wg for a 77% NOx removal SCR is not 

explained or documented in the record. Therefore, we do not concur that the record supports a 

pressure drop of 10 in wg for the SCR. 

Comment: Region 6’s consultant, Dr. Fox, states in her analysis of boiler stiffening costs 

that “[m]y review of the 2004 and 2007 revisions of NFPA 85 indicates that the 2004 revision of 

the [relevant code provisions] applied to the Consent Decree projects.” The “Consent Decree” 

projects referenced in the Region’s cost analysis include the demisters, low NOx burners, 

baghouses, and activated carbon injection systems that PNM installed in compliance with a 2005 

Consent Decree. Dr. Fox makes the assertion to support her opinion that “stiffening was 

triggered by the Consent Decree projects, based on the plain language of NFPA 85” and that 

“[t]hus, none of the stiffening costs should be attributed after the fact to the SCR.” Dr. Fox 

further suggests that, because of an “ambiguity” in the 2007 version of the code, it may not apply 

to the SJGS boilers at all, although she does eventually apportion some of the boiler stiffening 

cost to the SCR. Dr. Fox’s interpretations and conclusions about the code and the boiler 

stiffening are incorrect in several ways and likely the result of her inexperience with the code. In 

 46 10/22/10 B&V Cost Analysis Update, Appendix B; 6/7/07 B&V San Juan BART Analysis, p. B-3. 47 Topsoe SCR DeNOx Technology, Available at: 

http://www.topsoe.com/business_areas/flue_and_waste_gas/processes/nox_removal/~/media/PDF%20files/Scr_den

ox/SCR_DeNOx_technology.ashx; Brad Buecker, Emissions Control: SCR Design and Operation, 

http://www.powergenworldwide.com/index/display/articledisplay/152600/articles/power-engineering/volume106/issue-8/features/emissions-control-scr-design-and-operation.html. 

48 See, e.g., Alden, Improving Selective Catalytic Reduction (SCR) System Performance Using Physical Air Flow 

Modeling, Available at: http://www.aldenlab.com/index.cfm/handlers?GID=14&ContentID=171 

49 D.P. Tonn and T.A. Uysal, 22WW MW SCR Installation on New Coal-Fired Project, Institute of Clean Air 

Companies, ICAC Forum '98, March 1998, Available at: http://www.babcock.com/library/pdf/br-1654.pdf; Scot 

Pritchard and others, Optimizing SCR Catalyst Design and Performance for Coal-Fired Boilers, EPA/EPRI 1995, 

Available at: 

http://www.cormetech.com/brochures/OptimizingSCRCatalystDesignPerformanceCoalFiredBoilers.pdf 50 Scot G. Pritchard and others, SCR Catalyst Under Severe Operating Conditions, Cormetech Brochure, Available 

at: http://www.cormetech.com/brochures/Under%20Severe%20Operating%20Conditions.pdf 
21 

contrast, Black & Veatch’s boiler and draft system expert, Mr. Kris Gamble, has over 30 years of 

boiler and draft system design experience. Mr. Gamble also serves on the Technical Committee 

on Multiple Burner Boilers that help write the NFPA 85 code. 

Response: We regard Dr. Fox to be an expert on regulatory cost analysis. She has 

informed us that in her 30+ years of experience preparing hundreds of regulatory cost analyses 

for BACT and BART determinations for SCRs and other pollution controls, she has never 

encountered costs for code compliance that are 50% of the purchased equipment cost, as here. 

Code compliance is not broken out and costed separately, but rather included in construction 

directs or contingencies. The SJGS "code compliance" costs are very high and very unusual, 

warranting documentation. See discussion elsewhere in these responses. 

Comment: Dr. Fox’s belief that the 2004 version of the Code applied to the Consent 

Decree projects is incorrect. The 2004 version was superseded by the 2007 version during the 

Consent Decree work, and the 2007 version was utilized in that work. In addition, the Code is 

not ambiguous in the manner suggested by Dr. Fox. Rather, it allows boiler owners to either (i) 

meet a generally-applicable pressure standard of +/-35 inches w.g., or (ii) conducting “a more 

complete and rigorous analysis” to develop a design that utilizes other safety precautions, so long 

as the designer can demonstrate that those other safety precautions will sufficiently protect the 

boiler from implosion and explosion risks. PNM complied with NFPA 85 during construction of 

the Consent Decree projects by demonstrating, through “a more complete and rigorous analysis,” 

that the SJGS boilers would be adequately protected from implosion during upset or transient 

conditions. Additional duct and boiler stiffening was completed at that time to meet code. The 

2007 version of NFPA 85 has recently been superseded by a 2011 version, but that version does 

not make any material changes to the provisions discussed above. 

Response: We do not believe this comment tells the complete story of the boiler 

stiffening cost analysis. The conclusions attributed to Dr. Fox are actually statements made by 

Black & Veatch that were corrected after Dr. Fox submitted her report. In the 2007 BART 

analysis, Black & Veatch states that at the time of the Consent Decree projects, stiffening was 

not required as NFPA 8551 (2004 revision) did not apply to hybrid systems which were neither 

"truly forced draft or truly balanced draft."52 In the 2010 cost revision, Black & Veatch states 

that by 2007, NFPA 85 (2007 revision) had changed to require stiffening of hybrid systems.53 In 

this revision, Black & Veatch again affirms the 2004 version of the NFPA applied at the time of 

the Consent Decree work (contrary to this comment). Further, in the 2010 cost revision, Black & 

Veatch states that the 2007 NFPA requires balanced draft conversion and the lesser of stiffening 

to +/- 35 inches w.g. or adjusting the ratings of the ID/booster fan to ambient temperature.54 

On November 12, 2010, we asked PNM for the dates of the Consent Decree work in 

order to determine which code revision applied and requested copies of the implosion studies. 

PNM replied a month later, on December 8, 2010, after Dr. Fox had finalized her report based on 

 51 National Fire Protection Association (NFPA) Code 85, Boiler and Combustion Systems Hazards Code (NFPA 

85). 

52 6/7/07 B&V BART Analysis, p. 4-6. 

53 B&V 10/22/10 Cost Analysis, Sec. 4.0. 

54 B&V 10/22/10 Cost Analysis Update, pp. 7-8. 
22 

Black & Veatch's BART analysis. In PNM's response to the query about dates (going to the fact 

that Black & Veatch had mischaracterized the applicable code sections), PNM retracted Black & 

Veatch's prior statements about NFPA compliance that Dr. Fox relied on and offered the 

explanation contained in this comment.55 

The correction in the 12/8/10 email for the first time states that the owner could stiffen 

the boiler to meet either meet +/- 35 in. w.g. or conduct "a more complete and rigorous 

analysis." The correction and this comment further note that this latter approach was pursued for 

the Consent Decree projects but the BART cost analysis is based on the former approach, which 

yields an upper bound estimate. This is an important clarification as stiffening costs are based on 

the former, worst case situation. It is silent on balanced draft conversion. 

Comment: Installation of SCR’s at SJGS will again increase boiler and duct implosion 

potential due to increased draft system requirements and fan pressure ratings. SCRs will trigger 

the need to once again choose between either designing to the general standard of +/- 35 inches 

w.g. (which is typical for a newly designed power plant) or performing a “more complete and 

rigorous analysis” to determine whether PNM will qualify for an exception from the generallyapplicable implosion protection standard through the use of alternative methods. To date, neither 

PNM nor its consultants have fully determined whether an alternative to the +/- 35 inches w.g. 

standard would suffice following installation of an SCR, due to the significant amount of time 

and expense that would be associated with that analysis. For example, the analysis conducted for 

the Consent Decree control projects cost more than $300,000 to complete, and clearly exceeds 

the level of detailed engineering required for a BART determination. Based on the information 

that is currently available, and the acknowledged increase in differential pressures associated 

with an SCR, Black & Veatch concluded that including the cost for stiffening the boilers to +/-35 

inches w.g. is the only way to ensure full compliance with the NFPA 85 standard. Therefore, 

Black & Veatch included the cost of stiffening the boilers to +/- 35 inches w.g. in its analysis. 

Response: This comment acknowledges that the boiler stiffening costs represent a worst 

case estimate. The magnitude of these costs is unusual. The BART Guidelines require that 

unusual costs be documented in the record. These costs are stated without providing the 

underlying engineering calculations.56 PNM states in a footnote to its comments that the boilers 

were stiffened to negative pressure differentials of 18 in. w.g. during the Consent Decree 

projects. As the upper bound estimate for the increase in pressure differential due to the SCR is 

10 in. w.g., it would appear that the cost estimate is not only an upper bound but unreasonable. 

We do not "acknowledge" that the SCR will increase the pressure differential by 10 in. w.g. as 

alleged in this comment. The 10 in. w.g. estimate is a worst-case upper bound that is not 

supported by vendor quotes and SCR design. 

Comment: This explanation [referring to the previous comment] was previously 

provided to Region 6 and to Dr. Fox, but it appears to have been entirely ignored in Region 6’s 

cost analysis of SCRs for SJGS. In addition, Region 6 has no regulatory authority to determine 

whether the proposed design meets the requirements of NFPA 85. According to the code, that 

authority lies with the entity defined as the “Authority Having Jurisdiction,” which for SJGS is 

 55 12/8/10 Norem Email to Kordzi, Response to Question1. 

56 10/22/10 B&V Cost Analysis Update, Table 4. 
23 

PNM’s insurance carrier, FM Global. PNM’s experts currently believe significant boiler 

stiffening will likely be required to protect the boilers from implosion following installation of an 

SCR and, without a successful demonstration that the boilers could be adequately protected 

without stiffening to the NFPA 85 standard, PNM must assume that stiffening will be required. 

The mere existence of a possible exception from the generally applicable NFPA 85 standard, 

even if successfully obtained in the past, does not suggest that it will be possible to do so again. 

Region 6’s failure to properly account for the boiler stiffening costs underestimates the cost of 

the SCR retrofits for SJGS by $55,718,000 in capital costs for boiler stiffening and properly 

sized fans and motors. 

Response: As noted above, this explanation was not received until December 8, 2010, 

after our cost analysis had been finalized. We agree some cost for code compliance is warranted. 

However, we disagree as to the amount. The worst case used in Black & Veatch's analysis is 

unreasonable and unsupported, given the SCR's potential upper bound contribution of 10 in. wg. 

Absent the "more complete and rigorous analysis" to support upper bounds for both an SCR 

pressure differential and stiffening to +/- 35 in w.g., we feel stiffening costs should have been 

based on no more than the SCR's contribution to the increase from current conditions of 18 in. 

wg to 35 in. w.g. Thus, we modified our cost analysis to estimate the stiffening cost based on the 

SCR's maximum contribution to the increase from 18 in. w.g to 35 in. w.g or by 59% 

(100*10/[35-18]) (Exhibit 1, Fox Row 45). This increased our estimate of the capital cost to 

install SCRs by $19,258,318. 

Comment: In addition, the Region 6 cost estimate also underestimates the cost of lost 

generation and associated replacement power costs by $78,682,000 because it did not consider 

the outage time needed to complete the boiler stiffening. Lost power generation is a real cost 

that PNM will incur as a result of the SCR retrofit. Also, while the SJGS units are offline, PNM 

and the other owners of SJGS will have to purchase power to satisfy their customers’ needs. 

This “replacement power” will cost more than the cost to produce power at SJGS, and thus will 

result in additional costs to the SJGS owners. These costs must be taken into account in the cost 

estimate for the SCRs.

Response: We have extended the compliance schedule, as discussed elsewhere in our 

response to comments. We feel this will allow any required stiffening work to be completed 

during routinely scheduled outages, which occur every 3 years for 3 to 4 weeks and every 6 years 

for 16 to 17 weeks. We feel there should be no lost generation if the SCRs are properly staged. 

Regardless, the record does not contain any schedule and no support for the claim that longer 

outages than normal would be required. 

Comment: EPA failed to account for the cost of installing the initial layers in the SCR. 

SCRs must have several initial layers of catalyst to begin operating. Those initial layers of 

catalyst become deactivated over a period of time due to various factors and lose the ability to 

reduce NOx emissions. The catalyst layers must be replaced periodically to optimize catalyst 

life and maintain emissions performance. There are two ways to accurately account for the cost 

of both the initial catalyst layers and the replacement catalyst layers. The first method is to 

include the initial catalyst layers in the capital cost calculation for the SCR and account for each 

of the replacement layers in the annual operating cost calculation. The second method is to 
24 

include all of the catalyst layers, both the initial layers and the replacement layers, in the annual 

cost calculation. Either way, the cost analysis must take into account both the initial catalyst 

layer and all of the replacement layers that will be needed over time operate the SCR. 

The cost analysis prepared by Black & Veatch followed the first method described above 

by including the cost of the initial layers of catalyst in the capital cost and including the 

replacement layers in the annual operating cost calculation. Region 6’s consultant, however, 

appears to have misunderstood the analysis and assumed that the initial catalyst layers were 

double-counted. As a result, she subtracted the initial catalyst cost from the capital cost 

calculation, without adding it to the annual cost calculation. In doing so, the Region’s analysis 

entirely eliminates the cost of the initial catalyst layers. As such, Region 6’s failure to include 

the cost of the initial layers of catalyst in its analysis underestimates the cost of installing SCRs 

at SJGS by $33,556,000. 

Response: We agree with this comment. We have revised our cost analysis to include 

the initial catalyst charge (Exhibit 1, Fox Row 19).

Comment: Sorbent injection will be needed if PNM must install SCRs at SJGS, and the 

EPA cost analysis should reflect those costs. In order to reduce the cost-effectiveness 

calculations, Region 6 eliminated from the analysis costs associated with the installation and 

operation of a sorbent injection system. Sorbent injection systems are often used at coal-fired 

power plants equipped with SCRs to help reduce emissions of sulfuric acid mist that are an 

unavoidable byproduct of the chemical reactions that occur in an SCR. PNM included the cost 

of the sorbent injection system in its cost analysis of the SCRs for SJGS for several reasons. 

First, sulfuric acid mist resulting from SCR operation has been known to cause a visible plume at 

some units in the industry. Although the installation of SCRs may not result in such a plume at 

SJGS, the sorbent injection system would be needed to ensure a visible plume does not 

materialize. The second reason PNM included the cost of sorbent injection in its cost estimate is 

that the failure to address the sulfuric acid mist created by the SCR can reduce any visibility 

benefits associated with an SCR. Incurring the significant costs to install SCRs without 

addressing the inherent increases in sulfuric acid mist that would also result would simply be 

counter-productive, as recognized in the analysis conducted by PNM and both the 2010 and 2011 

draft BART determinations developed by NMED. 

Response: We disagree with this comment. Black & Veatch updated its cost analysis in 

October 2010.57 This is the most recent version of Black & Veatch's cost analysis, which was 

critiqued in our TSD in our proposal. This analysis did not include any costs for sorbent 

injection. NMED concluded that BART for SJGS was SCR plus sorbent injection to remove 

sulfur trioxide (SO3) and requested a sorbent injection cost analysis. However, we disagreed and 

concluded that sorbent injection was not required due to the low sulfur content of the coal, 

availability of low conversion SCR catalyst, and our calculations.58 We see no reason to change 

 57 Black & Veatch, San Juan Generation Station BART Project Review and Update of 2007 BART Cost Estimates, 

October 22, 2010 (B&V 10/22/10 B&V Cost Analysis Update). 

58 Michael Feldman and Erik Snyder, Visibility Modeling for BART Determination: San Juan Generating Station, 

New Mexico, In: Technical Support Document, p. 37. 
25 

that view. The reasons advanced in this comment for requiring sorbent injection to control 

sulfuric acid mist (SAM) are not applicable to the SJGS SCR. 

First, PNM suggests that SCR operation at SJGS could result in a visible plume. We do 

not believe this is plausible. Visible plume issues have only been experienced at units that burn 

high sulfur coal, containing greater than 2+% sulfur and typically over 3% sulfur, e.g., Gavin, 

Ghent. The coal burned at SJGS contains 0.77% sulfur, much lower than the amount of sulfur 

that has resulted in visible plume issues elsewhere and considered to be low sulfur. 

Second, PNM suggests that "although the installation of SCRs may not result in such a 

plume at SJGS, the sorbent injection system would be needed to ensure a visible plume does not 

materialize." No explanation is provided for why the commenter believes a plume may 

"materialize" on installing SCR. If the SCR is properly designed to address SJGS's coal, a plume 

should not materialize. 

An SCR will typically include two to three active layers of catalyst and one spare. Low 

SO2 conversion catalysts were developed to address blue plume encountered at high sulfur 

eastern bituminous coal plants after installing SCRs, the first being AEP’s Gavin Station in 

Ohio.59 The Gavin SCR reactors are a 3 + 1 (three initial layers and one spare) design (compared 

to 2+1 at SJGS, which thus can meet even lower conversion). The new catalyst at Gavin was 

designed for 90% NOx reduction from high sulfur eastern bituminous coals and a guaranteed 

0.38% SO2 conversion, which was measured at 0.1%. 

Low conversion catalysts capable of achieving an SO2 conversion as low as 0.1% per 

layer of catalyst in the high dust, hot (>650 F) position and 0.5% across the entire SCR reactor 

are common in higher sulfur and other applications.60 Even lower levels can be achieved if the 

catalyst is regenerated.61 Vendors will guarantee a total SCR system SO2 conversion of 0.5% for 

 59 Anthony C. Favale and others, Application and Operating Results of Low SO2 to SO3 Conversion Rate Catalyst 

for DeNOx Application at AEP Gavin Unit 1, Proceedings of the 2006 Environmental Controls Conference, U.S. 

DOE, NTL, 2006, (Attach. 61). Available at: 

http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/Favale_Summary.pdf. 60 Isato Morita and others, Development and Operating Results of Low SO2 to SO3 Conversion Rate Catalyst for 

DeNOx Application; Anthony C. Favale and others, Application and Operating Results of Low SO2 to SO3 

Conversion Rate Catalyst for DeNOx Application at AEP Gavin Unit 1, Proceedings of the 2006 Environmental 

Controls Conference, U.S. Department of Energy, National Energy Technology Laboratory. (Attach 65). See also 

Cormetech SCR Catalyst Brochure. (“Cormetech offers a low SO2 conversion catalyst that achieves less than 0.1% 

SO2 oxidation while balance all other key product performance features.”). Available at: 

http://www.cormetech.com/brochures/SCRCatalyst.pdf; DNX – Topsøe SCR DeNOx Catalysts Properties and 

Features (“The low SO2-oxidation activity has been demonstrated and SO2 oxidation rates down to 0.1% have been 

designed for and guaranteed in coal-fired power plants.”). Available at: 

http://www.topsoe.com/business_areas/flue_and_waste_gas/~/media/PDF%20files/Scr_denox/Topsoe_scr_oxidatio

n.ashx; William J. Gretta and others, The SCR Retrofit Design for the Seminole Generating Station, PowerGen 

2008; DNXTM – Topsøe SCR DeNOx Catalysts Oxidation of SO2 into SO3. (“Topsøe has demonstrated superior 

performance together with low SO2 oxidation under industrial conditions and has provided guarantees for SO2 

oxidation down to 0.1%.”). 

61 Mark Ehrnschwender and April Freeman Sibley, SCR Catalyst Regeneration – 10 Years of R&D Development 

and Commercial Application, Mega Symposium, 2008.. Available at: 

http://secure.awma.org/presentations/Mega08/Papers/a104_1.pdf. 
26 

two active and one spare layer based on the 0.1% per layer catalyst.62 See, for example, the 

discussion of the Seminole SCR elsewhere in our response to comments. 

Securing a guarantee at 0.5% for SJGS should present no problems as its coal contains 

relatively low sulfur compared to the high sulfur applications for which these catalysts were 

developed. In fact, Black & Veatch proposed a 0.5% conversion catalyst on the nearby Four 

Corners facility, which burns a similar coal.63 Sargent & Lundy obtained a 0.5% conversion 

vendor quote for the nearby Navajo Generating Station, which burns a similar coal. This quote 

was for maximum SO2 to SO3 conversion of 0.125% per layer at the end of catalyst life for a 4+2 

installation, or 0.5% across the SCR when all four layers are in place.64 The SCR for the 

Coronado Generating Station will use a 0.5% conversion catalyst.65 The contract for the 

Coronado SCR was recently awarded to Riley Power, Inc. with a project on-line date of June 

2014.66

Third, PNM alleges that the "failure to address the sulfuric acid mist created by the SCR 

can reduce any visibility benefits associated with an SCR." This is incorrect. As explained 

above, the sulfuric acid potentially created by an SCR is mitigated by specifying a low SO2

conversion catalyst. The Black & Veatch analyses assumed a 1% conversion catalyst, twice as 

high as achievable and specified for similar coals at nearby facilities, and significantly 

underestimated inherent removal by existing pollution controls. 

Comment: EPA’s calculation of sulfuric acid emissions is incorrect. EPA estimated 

sulfuric acid mist emission levels based on a document prepared by the Electric Power Research 

Institute (EPRI), which describes a formula used by many utilities to estimate sulfuric acid 

emissions. However, in applying that formula, EPA assumed an ammonia slip value of 2.0 parts 

per million (ppm), even though actual ammonia slip varies over the life of a catalyst layer from 

very low values up to 2.0 ppm as the catalyst ages. A more appropriate assumption for ammonia 

slip is the 0.75 ppm value recommended by the EPRI formula, which better represents the 

expected ammonia slip over the life of a catalyst. Using that assumption, the sulfuric acid 

emissions from SJGS are calculated to be twice that assumed by EPA. As a result, EPA’s 

attempt to justify its decision to delete the costs of sorbent injection based on minimal sulfuric 

acid mist emissions is incorrect. 

Response: The commenter is correct in that the EPRI report does suggest that a value of 

0.75 ppm should be used. We note that the ammonia slip of an SCR is minimal when the 

catalyst is new and increases as the catalyst ages. In order to be conservative, we recalculated 

the sulfuric acid emission rate, based on zero ammonia slip, to be 2.6 X10-4 lb/MMBtu, 

 62 See, e.g., CERAM, “Hot Topic Hour” Presentation on SCR Catalyst, October 12, 2006, Slides, p. 3 (“10 U.S. 

high dust, high sulfur (3.0 to 5.5% S) references operating since 2003 with oxidation rates <0.50%). 

63 Black & Veatch, Four Corners Steam Electric Station Units 1 through 5 NOx Compliance Report, Revision D, 

February 2010, Table 9-1. 

64 8/17/10 S&L Navajo Cost Analysis, Appx. K, Catalyst for Coal-Fired Boilers Request for Quote, File: SCR - 

Catalyst RFB 

65 Arizona Department of Environmental Quality (ADEQ), Technical Review and Evaluation for Salt River Project, 

Coronado Generating Station, Significant Permit Revision #46236 (Revision to Operating Permit #30732) and 

Significant Permit Revision #46236, Coronado Generation Station, January 21, 2009. 

66 Utility E-Alert, May 6, 2011. 
27 

compared to our original value of 1.06 X10-4 lb/MMBtu at 2ppm ammonia slip. The 2.0 ppm we 

selected in our proposed visibility modeling was based on the maximum slip from PNM's design 

specifications. This revised sulfuric acid emission rate remains significantly lower than that 

estimated by NMED and is a minimal level of sulfuric acid emissions. We continue to conclude 

that sorbent injection is not required due to the low sulfur content of the coal, availability of low 

conversion SCR catalysts, removal by existing control equipment and our revised calculations. 

Comment: The EPA also cites to the results of a stack test performed at the Navajo 

Generating Station in November 2009 to conclude that actual sulfuric acid mist emissions are 

lower than would be estimated using the EPRI Method. However, the air quality control 

industry generally considers sulfuric acid testing to be very prone to inaccuracy because the test 

methods used are susceptible to bias. Also, sulfuric acid emissions vary significantly from unit 

to unit because emissions removal is dependent on many variables including temperature, 

moisture, process operation, air quality control equipment, ambient conditions, and the quality of 

the testing. As mentioned above, SJGS and the Navajo Generating Station differ significantly in 

many of these respects. Therefore, it is not appropriate to use test results from Navajo 

Generating Station to make assumptions about SJGS. 

 

Response: We believe this comment mischaracterizes our analysis. We did not use test 

results from the Navajo Generating Station to make assumptions about the SJGS. Rather, we 

compared sulfuric acid mist emissions calculated for the Navajo Generating Station using the 

EPRI procedure with a stack test at the Navajo Generating Station in accordance with EPA 

Method 8A procedures. Thus, we compared Navajo EPRI estimates with Navajo test data to 

judge the accuracy of the EPRI procedure. This comparison suggests that the EPRI method may 

overestimate sulfuric acid mist emissions when firing a similar coal if PNM’s assumptions are 

used. This analysis supports the conclusion that the EPRI method and parameters we used 

provide a better estimation of sulfuric acid emissions than the methodology and parameters 

utilized by PNM and NMED in their analysis, which overestimates these emissions. We also 

note that PNM estimates for sulfuric acid emissions that were reported to the Toxic Release 

Inventory in recent years are much lower than those estimated by PNM for their BART analysis. 

Comment: It is appropriate to include sorbent injection costs in the SCR cost analysis 

because sorbent injection may be required by law. The Prevention of Significant Deterioration 

(PSD) program under the CAA requires major sources to install additional controls to address 

any significant net emissions increases resulting from a physical change to an emissions unit. 

Because the SCR will constitute a physical change to the SJGS emission units, and could have 

the potential to result in a significant net emissions increase in sulfuric acid mist, additional 

controls could be required by the PSD program. If triggered, the PSD program would require the 

installation of “best available control technology,” which for sulfuric acid mist emission 

increases would likely include a sorbent injection system. Although there remains some 

uncertainty as to whether the SCR would trigger PSD permitting requirements, PNM believes it 

is appropriate to include the cost of the system in the SCR cost analysis, and the failure to 

include those costs underestimates the cost of the SCRs by $12,118,000. 

Response: For the reasons outlined elsewhere in our response to comments, we believe 

the level of sulfuric acid generated at the SJGS will be so low that sorbent injection will not be 
28 

needed. However, it is possible that the installation of SCR on all four units of the SJGS could 

generate enough additional sulfuric acid that a PSD review could be triggered. EPA is not the 

permitting authority for sources in New Mexico but we believe it is reasonable to anticipate that 

a subsequent BACT analysis for sulfuric acid emissions at the SJGS will determine that no 

additional controls are required because despite the projected increase in sulfuric acid emissions, 

emissions are expected to remain low. In considering SCR for controlling NOx, EPA 

specifically considered the issues of sulfuric acid formation. In our review, we believe that the 

emission limits for NOx can be achieved through the use of lower reactivity catalyst, thus 

mitigating the formation of sulfuric acid across the catalyst bed. We have set an emission limit 

for emissions of sulfuric acid that restricts the increase of sulfuric acid. According to the two 

most recent Toxic Release Inventory (TRI) reports submitted by SJGS, the total sulfuric acid 

emissions are very low (17.77 TPY for 2009, and 27.5 TPY for 2008). Based on our 

calculations, we believe the current emissions of sulfuric acid to be significantly lower than these 

reported values due to the low sulfur content of the coal and the removal of sulfuric acid in the 

installed control equipment, including wet scrubbers and fabric filters. We project, with the 

implementation of SCR using a low reactivity catalyst that total emissions of sulfuric acid will 

remain below 22 tons/year.67 In this particular case, sorbent injection technology is unlikely to 

be cost-effective on a cost per ton basis of sulfuric acid mist removed. Again, we note that the 

New Mexico Environmental Department is the permitting authority and has the primary 

responsibility to implement the New Source Review program which includes the PSD permitting 

process, and the issuance of the applicable permit. NMED will be responsible for determining if 

PSD will be triggered for increases in sulfuric acid emissions or other NAAQS pollutants and in 

determining the BACT for such increases. 

Comment: Region 6 assumed that the “complexity factor” applied to the structural steel 

cost in PNM’s cost analysis was a “contingency factor.” As such, Region 6 assumed that PNM 

had double-counted contingency costs by using both the “complexity factor” for structural steel 

and a more general “contingency factor” overall. Region 6 misunderstood PNM’s analysis 

because a “complexity factor” is not a “contingency factor.” “Contingency factors” are designed 

to address unforeseeable costs. “Complexity factors” are used to reflect expected additional 

costs related to site congestion identified during the analysis. 

Region 6 relies on Dr. Fox’s opinion that SJGS is no more congested than other sites, 

including the St. John River Power Park (SJRPP), which was used as a comparison point in 

developing the SCR cost analysis for SJGS. According to her report, Dr. Fox’s opinion is based 

on a review of the SJGS and SJRPP using Google Earth, a web site that includes a database of 

satellite photographs. 

Google Earth is not a valid means of ascertaining site-specific engineering challenges at a 

complex industrial facility. PNM asks Region 6 to reconsider the analysis provided by Black & 

Veatch, given that the engineers at Black & Veatch made several site visits to SJGS and 

designed the SCRs for SJRPP. The pictures of SJRPP and SJGS provided by Black & Veatch in 

Attachment B illustrate the differences in site congestion: 

 67 Based on our emission limit of 2.6x10-4 lb/MMBtu and conservatively assuming each unit operates 100% of the 

year (8760 hr/yr) . 
29 

The extreme site congestion at SJGS is caused by several factors that do not exist at 

SJRPP. First, SJGS has “hot side” ESPs that are ahead of the air preheater in the flue gas path, 

whereas most coal plants have “cold side” ESPs that are downstream of the air preheater. 

Because the ESPs for SJGS are located in front of the air heaters they are right in the middle of 

the boiler outlet duct area, which severely restricts the area in which SCRs would need to be 

installed, particularly given the fact that the stacks are also located right next to the air heaters. 

 

The second primary cause of site congestion at SJGS is the arrangement of the four units 

in a row, which leaves two units (Units 2 and 3) on the interior of the row. There is very little 

space between units – in fact, as shown in the pictures in Attachment B, the only space available 

between units are small maintenance roads to go into the boiler building. As a result, there is 

very little room between units for the cranes that will be needed to hoist the SCRs into place. 

 

To account for the site congestion at SJGS, Black & Veatch added a “complexity” factor 

to the amount that would normally be associated with a typical retrofit SCR installation – 20 

percent for Units 1 and 4 and 50 percent for Units 2 and 3. A higher retrofit factor was used for 

Units 2 and 3 because they are “interior units” (located in between the exterior units 1 and 4) and 

crane access is especially limited on those units. The factor applied to the normal structural steel 

cost was not a “contingency factor,” but rather an expected cost of installing SCRs at the 

complex and congested SJGS site. Region 6 underestimated the cost of its BART proposal by 

$35,087,000 by failing to accurately account for site congestion. 

Response: First, a complexity factor is a subset of a contingency factor as it estimates 

unknown costs. PNM applied a complexity factor of 1.2 for Units 1 and 4 and 1.5 for Units 3 

and 4. We regard these factors as unknowns that cannot be determined until the SCR is 

designed. Second, there are approximately126 coal-fired EGUs that have hot-side ESPs ahead of 

the air preheater and of these, 17 have been retrofit with SCRs.68 In these situations, it is 

common to locate the SCR on top of the hot-side ESP, as proposed for SJGS. The cost of these 

types of retrofits and other more complex ones, in which the SCR is supported 200-300 feet 

above grade, such as at Gibson and Belews Creek, are substantially lower than the capital costs 

estimated for SJGS, pointing to an overestimate for SJGS. 

An SCR is a large metal frame stuffed with blocks of catalyst. The SCR is usually 

installed between the economizer exit and the air heater inlet. The economizer and air heater 

typically follow one another and are close together to minimize duct lengths and pressure drop. 

At existing units that were built before SCRs were required (all units built prior to about 1995), 

this location is necessarily constrained as facility design did not envision the need to leave room 

for SCRs. There is usually no space between the economizer outlet and air heater inlet. Thus, 

SCRs are commonly constructed above existing equipment, such as the boiler house, air heater, 

or electrostatic precipitator. Finding space for and retrofitting SCRs at all sites is challenging, 

not just at SJGS. 

 68 Based on EIA-860, the following units have hot-side electrostatic precipitators and SCR: Brandon Shores (MD) 

1,2; Cardinal (OH) 3; Deerhaven (FL) 2; E C Gaston (AL) 5; East Bend (KY) 2; Ghent (KY) 3,4; Gorgas (AL) 10; 

H L Spurlock (KY) 2; Havana (IL) 9; J M Stuart (OH) 1,2,3,4; Killen Station (OH) 2; and Roxboro (NC) 4. 
30 

We visited the SJGS plant on May 19, 2011.69 This visit confirmed that the site is 

congested. However, this does not confirm that the cost of structural steel for Units 1 and 4 

would be 1.2 times higher than at SJRPP and 1.5 times higher for Units 2 and 3, as alleged in this 

comment. We have not visited SJRPP, and the record does not contain any plot plans or design 

drawing for SJRPP (or SJGS) that would allow one to conclude anything about the cost of 

structural steel at one facility compared to the other. Photographs attached to the PNM 

comments (Attachment B) indicate more room for crane access at SJRPP than at SJGS, but this 

does not address the capital cost of the structural steel framework, only the cost of constructing 

it. 

The BART Guidelines require that "documentation" be provided for "any unusual 

circumstances that exist for the source that would lead to cost-effectiveness estimates that would 

exceed that for recent retrofits."70 We specifically asked PNM to identify any retrofit constraints 

and to support them with engineering calculations, drawings, and photographs.71 PNM did not 

respond. Therefore, we do not believe PNM has provided any specific documentation that 

supports the use of the structural steel complexity factors. Nevertheless, we have modified our 

cost analysis to use Black & Veatch's estimate for structural steel, which includes the 

"complexity factors" cited in this comment. (Exhibit 1, Fox Row 22) as Black & Veatch 

designed both facilities. 

Comment: EPA failed to account for the SCR bypass that will be necessary to protect the 

SCR during startup on oil. EPA assumed that SJGS could initiate startup of its units on oil 

without fouling the catalyst in the SCR. EPA’s justification for the removal of this cost line item 

was that fuel oil is efficiently burned in modern low NOx burners with oil igniters, citing two 

coal-fired units that have shown the ability to startup on oil without a bypass and two oil-fired 

boilers with SCRs that do not have a bypass. Based on these references, EPA concluded that 

SJGS will be able to startup on oil without risking catalyst fouling resulting from a coating of 

incompletely combusted fuel oil. The failure to account for the needed SCR bypass system 

underestimates the cost of installing SCR at SJGS by $126,484,000. 

Response: We disagree with this comment. The removal of SCR bypass costs was based 

on several factors. First, a noted air pollution handbook concluded (before U.S. ozone season 

trading programs made them routine): "most applications do not have SCR bypasses, since 

routines are used during startup and shutdown which preclude their need” (Cho and Dubow),72

and regulations sometimes prohibit their use. Also, experience in Japan and Germany has shown 

them to be costly and not required to prevent damage due to low-load oil firing, thermal 

gradients, and other conditions. 

Comment: Region 6 assumed that SJGS could initiate startup of its units on oil without 

fouling the catalyst in the SCR. The Region’s justification for the removal of this cost line item 

 69 See San Juan Generating Station Site Visit, 5/23/11 

70 70 FR 39168 (July 6, 2005). 

71 9/23/10 Kordzi Email to Norem, Question 4 ("Identify any retrofit constraints and support them with engineering 

calculations, drawings, and photographs.") 

72 S.M. Cho and S.Z. Dubow, Design of a Selective Catalytic Reduction System for NOx Abatement in a CoalFired Cogeneration Plant, Proceedings of the American Power Conference, April 13-15, 1992, pp. 717-722. 
31 

was that fuel oil is efficiently burned in modern low NOx burners with oil ignitors, citing two 

coal-fired units that have shown the ability to startup on oil without a bypass and two oil-fired 

boilers with SCRs that do not have a bypass. Based on these references, the Region’s consultant 

concluded that SJGS will be able to startup on oil without risking catalyst fouling resulting from 

a coating of incompletely combusted fuel oil. 

Response: We disagree with this comment. The removal of SCR bypass costs was based 

on several factors. First, a noted air pollution handbook concluded (before U.S. ozone season 

trading programs made them routine): "...most applications do not have SCR bypasses, since 

routines are used during startup and shutdown which preclude their need (Cho and Dubow73), 

and regulations sometimes prohibit their use. Also, experience in Japan and Germany has shown 

them to be costly and not required to prevent damage due to low-load oil firing, thermal 

gradients, and other conditions."74 We believe a bypass is not required in a properly designed 

and operated SCR system to prevent SCR catalyst fouling during startup or operation on oil. 

Two examples were cited in our TSD as part of our proposal to confirm this information. 

Comment: Although some new units have shown the ability to startup on oil without 

bypassing the SCR, as the risk of catalyst fouling due to incompletely combusted fuel oil is much 

greater with a retrofit SCR at an existing unit. Even with new burners, greater uncertainties exist 

during startup of older units with retrofit burners and retrofit SCRs. Black & Veatch determined 

that a bypass would be necessary at SJGS to avoid fouling of the SCR catalyst, based on their 

wealth of experience in installing and supporting operational retrofit SCRs across the nation. 

Since the BART analysis requires a site-specific analysis, Region 6 should defer to the opinions 

of experts who have practical experience with the site-specific questions involved, rather than 

rely on anecdotal references to other units. The failure to account for the needed SCR bypass 

system underestimates the cost of installing SCR at SJGS by $126,484,000. 

Response: This comment claims that Black & Veatch "determined that a bypass would 

be necessary at SJGS to avoid fouling of the SCR catalyst..." However, this determination is not 

in the record. The costs for the bypasses are simply added into the cost estimate without a 

supporting design, customized for the site, or any engineering calculations or LNB specifications 

that demonstrate the need for the bypass. In fact, PNM and Black & Veatch have not pointed to 

a single unit that required an SCR bypass to prevent catalyst fouling from operation on oil at any 

time including startup, or a single reference that documents that SCR catalyst fouling is an issue 

when firing oil or starting up on oil or any analysis at all that supports this conclusion. 

The cost for the SJGS bypass was based on a Black & Veatch design for the St. Johns 

River Power Park (SJRPP) SCR, installed to comply with the CAIR trading program. This SCR 

included a bypass and isolation dampers to allow SJRPP to isolate the SCR for maintenance,75

not startup on oil. This unit burns oil.76 The cost for the SJGS catalyst was based on a Black & 

 73 S.M. Cho and S.Z. Dubow, Design of a Selective Catalytic Reduction System for NOx Abatement in a Coal-Fired 

Cogeneration Plant, Proceedings of the American Power Conference, April 13-15, 1992, pp. 717-722. 74 Arthur Kohl and Richard Nielsen, Gas Purification, Fifth Edition, Gulf Publishing Co., 1997, p. 921. 

75 Gerald Smith and others, St. Johns River Power Park 2 x 670 MW SCR - Designed to Ensure Fuel Flexibility, 

Mega 2008, p. 1. 

76 EIA-923 
32 

Veatch design for the IPALCO Harding Street Unit 7 SCR. This unit burns oil.77 This SCR, 

installed on an existing unit of about the same age (startup 1973) as the SJGS units (startup 

1972-1982), does not have any SCR bypass. Thus, the two SCRs that Black & Veatch designed 

and used to extrapolate costs for SJGS are existing units that do not use SCR bypasses to prevent 

catalyst fouling during startup on oil. 

Most all of the SCRs that include reactor bypasses were installed to comply with the NOx 

SIP Call, a NOx trading program that only required the use of SCR during the May to October 

ozone season. During the nonozone season, when SCR is not required, the reactors are taken 

offline and laid up because SCR catalyst continues to age even when ammonia is not injected. 

The ozone-season SCR reactors are thus bypassed during the balance of the year. However, it is 

uncommon for existing units that are retrofit with SCR and operate year round to include 

bypasses as they significantly add to the cost of an SCR. Proper design eliminates the need for 

bypasses in these situations. 

In our proposal, we previously identified two existing coal-fired stations with retrofit 

SCRs that startup on oil but do not have SCR bypasses: Morgantown (2 units) and Belews Creek 

(2 units). In addition, the retrofit SCR installed on Chalk Point Unit 1 which starts up on oil and 

Lake Hubbard Unit 2,78 which operates on oil and gas, have no bypasses.79 These are not 

isolated examples, but the norm for year round SCRs due to the significant capital cost of a 

bypass and lack of need. 

Sargent & Lundy, for example, specifically did not recommend an SCR bypass in the 

BART analysis for Navajo (3 units), 80 a nearby existing facility of about the same age and 

retrofit complexity that burns a similar coal and starts up on oil.81 Sargent & Lundy is a major 

 77 EIA-923 

78 William J. Gretta, W. Scott Hinton, and O. Bennett Jones, Results from the In-Line SCR Retrofit at TXU's Lake 

Hubbard Station, Power-Gen, 2002. 

79 In the Matter of the Application of Mirant Chalk Point, LLC for a Certificate of Public Convenience and 

Necessity Authorizing the Modification of the Chalk Point Generating Station in Price George's County, Maryland, 

Before the Public Service Commission of Maryland, October 6, 2006. 

80 8/17/10 S&L Navajo Cost Analysis, p. 3-8 ("No reactor bypass would be provided.") and Appx. A, p. 6 ("The 

SCR reactors will be designed without flue gas bypass provisions around the reactor."). 81 See, e.g., for 2010: "2010: EIA-923 January - December, Excel Format." Boiler Fuel Data (U.S. Energy 

Information Administration form EIA-923 (2010), "Schedule 3. Part A. Boiler-Level Information For SteamElectric Organic-Fueled Plants - Fuel Consumption"). Data Released: May 17, 2011. U.S. Energy Information 

Administration. Annual Electric Utility Data - EIA-906/920/923 Data File 

(http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html); for 2009: "2009: EIA-923 January - December 

Final, Nonutility Energy Balance and Annual Environmental Information Data, Excel Format." Boiler Fuel Data 

(U.S. Energy Information Administration form EIA-923 (2009), "Schedule 3. Part A. Boiler-Level Information For 

Steam-Electric Organic-Fueled Plants - Fuel Consumption"). Data Released: May 17, 2011. U.S. Energy 

Information Administration. Annual Electric Utility Data - EIA-906/920/923 Data File 

(http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html); and for 2008: 2008: EIA-923 January - December 

Final, Nonutility Energy Balance and Annual Environmental Information Data, Excel format." Boiler Fuel Data 

(U.S. Energy Information Administration form EIA-923 (2008), "Schedule 3. Part A. Boiler-Level Information For 

Steam-Electric Organic-Fueled Plants - Fuel Consumption"). Data Released: May 17, 2011. U.S. Energy 

Information Administration. Annual Electric Utility Data - EIA-906/920/923 Data File 

(http://www.eia.doe.gov/cneaf/electricity/page/eia906_920.html). 
33 

engineering design firm with 56 SCR systems to its credit and 30% of the SCR market,82 almost 

twice the number claimed by Black & Veatch.83 The BART SCR design for the Navajo facility 

is much more advanced than Black & Veatch's design for SJGS and includes site layout 

drawings, isometric drawings, detailed design specifications, a complete SCR technology 

assessment, requests for proposal, and even vendor quotes.84 

Further, Black & Veatch itself has not specified SCR bypasses, contrary to PNM's 

allegation in this comment that only new units that startup on oil would not require bypasses, in 

NOx reduction studies prepared for other similarly situated units—similar age and coal-fired 

with oil startup. Black & Veatch did not recommend bypassing the SCR in the BART cost 

analysis for the nearby Four Corners facility (5 units), a similar aged facility that burns a similar 

coal and starts up on oil.85 Black & Veatch also specifically did not recommend bypassing the 

SCR at Rawhide Unit 1, a 250-MW existing unit built in 1983 that burns PRB coal and starts up 

on oil.86 In fact, the record does not identify a single unit that required an SCR bypass due 

catalyst fouling while firing oil nor due to any unusual circumstances at SJGS that would require 

a bypass while none is required at the 13 units I identified. 

While some catalysts (e.g., platinum-based oxidation catalysts) are sensitive to oil when 

fired in a cold furnace, this issue can be resolved by selecting a catalyst that is not,87 or by 

preheating the SCR reactor prior to placing it into service. This practice is followed at some 

facilities as it not only eliminates NOx spikes from the cold startup of the SCR, it also eliminates 

claimed adverse impacts from startup on fuel oil, dew-point operation, shortens reactor startup, 

lengthens catalyst life, and reduces stress on reactor structural members.88 

Comment: The EPA cost estimate also does not properly estimate annual operating costs 

for auxiliary power consumption and catalyst replacement rate. Black & Veatch estimated the 

amount of auxiliary power needed to run the SCR to be 16,297 kW (for all four units) at a cost of 

$0.06095 per kWh, based on a site-specific analysis. Specifically, Black & Veatch’s calculation 

was based on the calculation of the additional fan energy (based on flue gas flow rate and 

estimated pressure drop from the SCR) and the power consumption for the auxiliary equipment 

(such as the ammonia system). EPA, on the other hand, simply assumed a cost of 5,400 kW at 

$0.05 per kWh based on a percentage estimate for “typical” SCR installations. This error 

underestimates the cost of auxiliary power consumption when operating SCRs by $5,388,000. 

 82 Sargent & Lundy, Navajo Generating Station, Preliminary Cost Estimate, Slides, July 20, 2010, In: 8/17/10 S&L 

Navajo Cost Analysis, Appendix R. 

83 PNM Comments, p. 16; & Veatch, Building a World of Difference, p. 4, Available at: 

http://www.bv.com/Downloads/Resources/Brochures/rsrc_ENR_CoalSelectiveCatalyticReduction.pdf. 84 8/17/10 S&L Navajo Cost Analysis, Appendices. 

85 Black & Veatch, Arizona Public Service Company Four Corners Generating Plants Units 1 through 5, Best 

Available Retrofit Technology Engineering Analysis, December 4, 2007, Rev. 3. See, e.g., p. 3-8 and Fig. 3-4. 

86 Black & Veatch, Platte River Power Authority, Rawhide Energy Station, Rawhide NOx Reduction Study, January 

2009, Rev. 3, pp. 2-19 ("As part of the design assumptions, a SCR bypass system will not be included due to year 

round operation of the SCR system..."), 5-1 ("Cost savings were realized by eliminating the SCR bypass (due to 

year-round operation instead of ozone season operation) which removes additional ductwork and dampers."). 87 See, e.g. Gretta et al, 2002, p. 6 (A large pitch catalyst was selected to prevent fouling. This would also reduce 

pressure drop). 

88 Ted Kurtides, Lessons Learned from SCR Reactor Retrofit, Coal-Gen 2003, (Attach 20), pp. 2, 17-18. 
34 

Response: We disagree with the comment. This comment claims the Black & Veatch 

auxiliary power demand cost estimate is based on a site-specific analysis for SJGS and thus 

should be favored over generic estimates from the Control Cost Manual. This site-specific 

analysis does not appear to be in the record, thus preventing us from reviewing it. The 

assumptions used in the analysis, e.g., duct length, catalyst pressure drop, are unknown as the 

SCR system has not yet been designed. In fact, the record does not even contain an arrangement 

diagram, required to determine duct lengths. 

First, the Black & Veatch estimate of 16,297 kW was initially rejected by us as it 

amounts to 0.9% of the total gross generating capacity of the station, which is high compared to 

other estimates known to the Region.89 An SCR typically uses about 0.3% of a plant's electric 

output, which would be about 5,400 kW or three times less than assumed in the cost analysis.90 

The BART Guidelines require that unusual costs be documented in the record. PNM did not 

supply any additional information to support its unusually high estimate. 

As the SCR has not been designed and thus has not been optimized, power demand likely 

can be reduced. The pressure drop due to the SCR was assumed to be 10 in. w.g,91 which is at 

the upper end of the usual range of 3 to 10 in. w.g. No support was provided for picking this 

upper bound number. It is unclear whether 10 in. w.g. was used in estimating the auxiliary 

power demand as the calculations are not in the record. However, it is likely that this upper 

bound estimate could be significantly reduced by selecting a catalyst with a low (<1 in. w.g.) per 

layer pressure drop. 

Second, the unit cost of electricity used by Black & Veatch, $0.06095/kWh, was rejected 

by us as it is much higher than the auxiliary power cost commonly used in cost effectiveness 

analyses. Auxiliary power is the power required to run the plant, or power not sold. Cost 

effectiveness analyses are based on the cost to the owner to generate electricity, or the busbar 

cost, not market retail rates. The Black & Veatch estimate is based on the average forecasted 

cost of replacement power for 2007 to 2012.92 Thus, even if this is the correct site specific cost, 

it is the wrong metric for a cost effectiveness analysis. We further note that the use of forecast 

cost is inconsistent with the BART methodology, which is based on current dollars. 

As to the cost of auxiliary power, we conservatively used the upper end of the range of 

costs assumed in BART cost effectiveness analyses ($0.03/kWh to $0.05/kWh)93 or $0.050/kWh 

(Exhibit 1, Fox Row 81). After our analysis was complete, PNM responded to a question from 

 89 Fox Report, p. 24. 

90 EPA Air Pollution Control Cost Manual, pdf 470; J. Edward Cichanowicz, Current Capital Cost and Cost 

Effectiveness of Power Plant Emissions Control Technologies, Prepared for Utility Air Regulatory Group, June 

2007, Table 7-2 [100($265,000/$20/MWh)/(500 MWx8760 hr/yr) = 0.3%] 

91 10/22/10 B&V Cost Analysis Update, Appendix B; 6/7/07 B&V San Juan BART Analysis, p. B-3. 

92 Email from Norem to Kordzi, October 21, 2010, Re: PNM Responses to Follow-Up Questions from October 14, 

2010 Conference Call Regarding BART Cost Estimate, October 21, 2010 (10/21/10 Responses), Response to 

Question 9, pp. 3-4. 

93 Sargent & Lundy, Sooner Units 1 & 2, Muskogee Units 4 & 5 Dry FGD BART Analysis Follow-Up Report, 

Prepared for Oklahoma Gas & Electric, December 28, 2009 , Attach. C, pdf 109; (Gerald Gentleman - 

$45.65/MWh; White Bluff - $47/MWh; Boardman/Northeastern/Naughton - $50/MWh; Nebraska City - $30/MWh). 
35 

us that its average cost of production is $0.047/kWh ($47.83/MWh).94 This rounds up to 

0.05/kWh, the number we used. Thus, we have made no changes to our estimate of auxiliary 

power demand. 

Comment: Because of the Region 6’s underestimation of the capital cost of the project, 

the capital recovery (which represents the annual impact of the initial capital expenditure) for the 

project is also underestimated by $50,407,000. 

Response: We believe this comment is incorrect because the capital cost of installing 

SCR at SJGS was not underestimated by $50,407,000, as explained elsewhere. Some minor 

adjustments have been made to capital costs, based on the site visit, which have increased capital 

cost, but the impact of the these changes on annual costs are minor, and do not change our 

overall finding that the cost of installing SCR is cost effective. 

Site‐specific cost factors do not appear to have been considered in the EPA’s analysis of 

SJGS, which vastly underestimated cost impact results for EPA’s proposed FIP. EPA’s 

consultant’s cost effectiveness study departs from the BART analysis of control options prepared 

by PNM, and shows a total cost more than $670 million lower than the total cost prepared for 

PNM by the engineering consulting firm, Black & Veatch. Black & Veatch has designed and 

built SCRs at 15 facilities over the last 10 years, totaling nearly 10,000 MW in capacity. Black 

& Veatch estimated that the total capital cost of installing SCR on all four units at SJGS would 

be approximately $908 million. EPA has estimated the total capital cost at approximately $247 

million, which is less than one-third of PNM' s expert's estimate. This alone should cause EPA 

to pause and at a minimum question and reanalyze the underlying assumptions, and lack of 

assumptions, it has made as well as its overall cost estimate. This disconnect seems to be based 

on the limitations of the approach used by EPA’s consultant in considering control cost data and 

engineering analyses into her BART cost analysis, relying exclusively on the 2002 EPA Cost 

Manual instead of the 2005 BART Guidelines (Federal Register, Vol. 70, No. 128, July 6, 2005). 

In contrast to the 2002 EPA Cost Manual, the 2005 BART Guidelines provide an open process 

for use of multiple sources of data for establishing control option engineering design and costs, 

including site‐specific retrofit restrictions (Ibid, pg. 39164, Ibid, pp. 39164‐39166, Ibid, pg. 

39166, Ibid, pg. 39168). The 2005 BART Guidelines encourage sources in performing BART 

analyses of cost effectiveness to explore, consider, and use many relevant sources of information, 

engineering design, and cost data in developing and documenting their site‐specific cost 

assessments of BART control options. 

Elsewhere in its BART rules, EPA makes the nonbinding nature of the Manual even 

more explicit and reaffirms the requirement that real, site-specific costs must be taken into 

account. It states, for instance, that BART determinations must take into account additional 

information ... used for the cost calculations, including any information supplied by vendors that 

affects ... assumptions regarding purchased equipment costs, equipment life, replacement of 

major components, and any other element of the calculation that differs from the Control Cost 

Manual. Id. at 39166 n.15 (emphasis added). Similarly, the preamble to the BART rules states: 

We believe that the Control Cost Manual provides a good reference tool for cost calculations, but 

if there are [cost] elements or sources that are not addressed by the Control Cost Manual or 

 94 12/8/10 Norem Email to Kordzi, Response to Question 1. 
36 

there are additional cost methods that could be used, we believe that these could serve as useful 

supplemental information. Id. at 39127 (emphasis added). Thus, the Manual is not the only 

source of cost information that states or EPA must consider when determining BART, and the 

fact that the Manual fails to include a particular line item provides no basis for striking that item 

from a BART analysis. On the contrary, EPA is bound by its rules and the holding of the D.C. 

Circuit in American Corn Growers. The Agency’s proposed determination that failure to adhere 

exclusively to cost calculations and methods in the Manual is an error and is fundamentally at 

odds with the governing law. Accordingly, the proposed determination that SCR is BART 

cannot be sustained. Indeed, a proper analysis undoubtedly would result in a determination that 

SCR is not cost-effective and is not BART for SJGS. EPA must correct its error and provide a 

new analysis for public review and comment. 

Commenter references PNM’s comments for a listing of site-specific costs it alleges 

should have been considered: 

• Additional costs associated with ensuring sufficient auxiliary power to operate SCRs. 

• Costs associated with protecting the air preheater following an SCR installation. 

• Costs for Boiler “stiffening” required by conversion to a “balanced draft” boiler furnace 

operation. 

• Costs of installing the initial catalyst layers in the SCR. 

• Cost of sorbent injection. 

• Costs of additional steel frameworks needed due to the unusually high site congestion. 

• Costs of annual operations were underestimated. 

• Costs of an SCR bypass required to protect the SCR during startup on oil fuel were not 

included. 

• Reasonable cost escalation factors were not included. 

• Some costs appear not to have been included because they were misunderstood to be 

“contingency” costs but are not. 

Response: The site-specific costs the commenter alleges we should have considered are 

addressed elsewhere in our response to comments. A BART cost effectiveness analysis is a 

regulatory cost analysis that follows a consistent set of rules so that costs incurred for pollution 

control equipment can be compared between facilities and sources. A BART cost effectiveness 

analysis does not seek to estimate the cost to PNM at some point in the future or the cost that can 

be recovered in a rate-making case, or the cost an owner might use to select among various 

options to control NOx or even the actual cost of the control. Rather, a BART cost effectiveness 

analysis is a regulatory cost analysis. Thus, while the experiences gained by Black & Veatch 

designing SCRs are useful when correctly applied, they result in erroneous results when applied 

in the regulatory context without following the proper methodology. 

Cost effectiveness is determined by comparing annual cost per ton of pollutant removed 

for the source of interest to the range of cost effectiveness values for other similar facilities 

calculated in the same way. If a given cost effectiveness value falls within the range of costs 

borne by others, it is per se cost effective unless unusual circumstances exist at the source.95 

 95 70 FR 39168 (July 6, 2005). 
37 

Thus, cost effectiveness is a relative determination, based on costs borne by other similar 

facilities. To compare costs among units, a level playing field must be established by following 

the same cost rules in each determination.96 Thus, in evaluating BART cost effectiveness, it is 

important that a consistent set of rules be used. Otherwise, one runs the risk of comparing apples 

with oranges when making the cost effectiveness determination. 

The Black & Veatch cost estimating method deviates from the standard procedure 

developed by EPA used to establish the range of acceptable cost effectiveness values for BART. 

In other words, the Black & Veatch cost effectiveness analyses uses a nonstandard cost method 

and compares the results to costs derived using the standard method. This results in erroneous 

conclusions. For example, if the Black & Veatch method is used to estimate cost effectiveness, 

this same method must be used in all other BART cost values used to establish the acceptable 

range as cost effectiveness is relative. If all cost effectiveness values for SCR for all BART 

sources were calculated as advocated by Black & Veatch, then the cost of SCR for SJGS would 

be well within the usual range and hence cost effective. The cost for the SJGS SCR only appears 

to be higher than the normal range because Black & Veatch has followed a nonstandard 

procedure and compared it to values estimated using the standard regulatory procedure.97

For power plants having a capacity in excess of 750 MW, as here, Section 169A(b) of the 

CAA requires that States follow guidelines promulgated by EPA for determining BART.98 The 

responsive guidelines are contained in Appendix Y to Part 51, "Guidelines for BART 

Determinations Under the Regional Haze Rule." These Guidelines include methods to determine 

both cost and cost effectiveness. For cost analyses, the Guidelines stipulate: "In order to 

maintain and improve consistency, cost estimates should be based on the OAQPS Cost Control 

Manual, where possible."99 We believe these Guidelines were correctly applied in our analysis 

and were not correctly followed by Black & Veatch, resulting in erroneous conclusions. 

Comment: Region 6’s justification for relying so heavily on the Control Cost Manual is 

that use of the manual will lend consistency to the BART cost analysis. That is the same reason 

EPA provided in its Guidelines for recommending the manual as one possible source of 

information, but the Guidelines continue to support the use of other sources of information in 

spite of that policy, and only recommend use of the Control Cost Manual “where possible,” 

recognizing the limits to which the BART determination process may be standardized. 

 96 See discussion of this issue in Letter from John Bunyak and Sandra V. Silva, Fish & Wildlife Service, to Mary 

Uhl, New Mexico Environmental Department, August 17, 2010, p. 5, footnote 9 ("November 7, 2007, statement 

from EPA Region 8 to the North Dakota Department of Health: "...in order to maintain and improve consistence, 

cost estimates should be based on the OAQPS Cost Control Manual. Therefore, these analyses should be revised to 

adhere to the Cost Manual methodology."), p. 6 (quoting a May 10, 2010 EPA letter to North Dakota Department of 

Health: "These accounting items [owner's cost] are unauthorized under the Cost Control Manual, create an unlevel 

playing field for comparison with other BACT analyses and alone account for an increase in capital costs from the 

Cost Control Manual by a factor of 1.6."). See discussion in: Letter from Andrew M. Gaydosh, Assistant Regional 

Administrator, EPA Region 8, to Terry O'Clair, Director, Division of Air Quality, North Dakota Department of 

Health, Re: EPA's Comments on the North Dakota Department of Health's April 2010 Draft BACT Determination 

for NOx for the Milton R. Young Station, May 10, 2010, pp. 14-16. 

97 PNM Comments, Appx. A 

98 See, e.g., 70 FR 39158 (July 6, 2005) ("States must follow the guidelines in making BART determinations on a 

source-by-source basis for 750 megawatt (MW) power plants..."). 

99 70 FR 39166 (July 6, 2005). 
38 

Furthermore, perfect consistency in the cost analysis would entirely eliminate the caseby-case nature of the analysis envisioned by Congress. In a recent telephone conference on 

March 21, 2011, EPA’s Office of Air and Radiation agreed that consistency among various EPA 

Regions is important but recognized that site-specific considerations must be addressed because 

“plants are not all alike.” As such, Region 6’s failure to properly consider costs for site-specific 

challenges beyond those identified in the manual is inappropriate and inconsistent with the 

regional haze program. 

Response: We agree that site-specific challenges must be identified and factored into the 

cost effectiveness analysis. However, the items at issue here are not "site-specific challenges," 

but rather use of the wrong costing methodology and improper categorization of costs as 100% 

SCR costs. We are not advocating "perfect consistency" in the cost analysis, but rather 

consistency in the methodology and appropriate allocation of costs. As explained elsewhere, the 

Control Cost Manual provides two broad categories of guidance: (1) methodology and (2) 

control-specific costing algorithms. Site-specific considerations come into play in the latter, in 

control-specific costing method. We discuss these elsewhere in our response to comments. 

Comment: In its analysis, EPA recognized that the Cost Manual does provide factors to 

estimate certain “direct installation costs,” namely foundation/supports, handling/erection, 

electrical, piping, insulation, painting, demolition, and relocation. However, the Control Cost 

Manual fails to provide factors to estimate these costs for SCR, as recognized in EPA’s analysis. 

EPA indiscriminately took the median of the factors for other control technologies, which vary 

significantly from SCRs. As a result, EPA’s analysis slashes in half the direct installation costs 

estimated by Black & Veatch. For example, the direct costs assumed by EPA for Unit 1 are 

$8,799,917, but that amount would only cover 159,998 man-hours, or 21 weeks of construction. 

EPA’s own schedule, even though insufficient itself, assumes 38 weeks of construction, nearly 

double of the amount that EPA’s analysis could afford. Thus, EPA’s estimate is insufficient for 

its own estimated construction timeline, much less the 64 to 72 weeks of construction that 

PNM’s experienced consultants predict. 

Response: We disagree with this comment. Direct installation costs consist of individual 

cost estimates for 8 separate components: (1) foundations and supports; (2) handling and 

erection; (3) electrical; (4) piping; (5) insulation; (6) painting; (7) demolition; and (8) relocation. 

We do not believe that the Black & Veatch direct installation costs are supported in the record, 

even though both New Mexico and NPS specifically requested support. Instead, they were 

calculated by multiplying total purchased equipment costs by various unsupported percentages, a 

rough estimating practice referred to as "factoring." The basis for the various factors that Black 

& Veatch used is not in the record. 

The percentages that Black & Veatch used are demonstrably high. We compared each of 

Black & Veatch's direct costs with those from a major SCR designer's (Babcock Power) database 

and from similar SCR projects with which our consultant has experience. The Babcock Power 

information includes cost curves ($/MW) for engineering, foundation and site work, structural 
39 

steel, and electrical/instrumental and controls, among others. The costs are plotted as a function 

of unit size in MW for units with low, median, and high costs. 100 A sample is shown below. 

Figure 1, Foundations and Site Work 

This figure shows that foundation and supports, costed by Black & Veatch as 30% of 

purchased equipment cost, for example, based on its estimate of purchased equipment cost, are 

two to three times higher than upper bound costs reported by Babcock Power for similar sized 

units ($8/MW compared with $18/MW to $29/MW for SJGS). Based on these comparisons the 

Black & Veatch's costs were excessive. No documentation has been provided to justify these 

costs. 

The Control Cost Manual estimating procedure for direct installation costs is based on the 

same factoring approach used by Black & Veatch. However, the SCR section of the Control 

Cost Manual did not include factors for direct installation of SCR. We thus tabulated the factors 

for total direct installation costs for all controls reported in the Manual. These ranged from 30% 

to 85% of the purchased equipment cost. In comparison, Black & Veatch assumed direct 

installation costs were 103% to 113% of total purchased equipment cost. 

We calculated direct installation costs for SJGS using the median of this range or 62% of 

purchased equipment cost. This is consistent with the upper bound Babcock Power estimate for 

actual retrofit SCR installations. It is also consistent with estimates of direct installation costs 

made by others.101 This estimate is reasonable as an SCR is a metal frame stuffed with blocks of 

 100 LG&E Energy and Babcock Power, Selective Catalytic Reduction: From Planning to Operation, PowerGen 2005. 101 Malcolm Pirnie, Air Pollution Control Equipment Cost Estimates, Palm Beach Renewable Energy Facility No. 2, 

Appendix D; EXPAND: CUECost Estimates, Cinergy. 
40 

catalyst. It has no moving parts. Painting, for example, is minimal as most items arrive at the 

site primed; structural steel arrives at the site painted. 

The Black & Veatch estimate is also high compared to direct installation costs that it 

reported for the SJRPP SCR, which was otherwise used to extrapolate equipment costs to SJGS. 

The direct installation costs for the SJRPP SCR were 95% of the total purchased cost.102 We 

have revised our cost estimate to use this estimate to conform with the balance of the Black & 

Veatch cost estimate. 

This comment claims that our estimate of direct installation costs for Unit 1 ($8,799,917) 

would account for only 21 weeks of the 38 weeks of construction for Unit 1 assumed by EPS’s 

proposed schedule. However, this estimate assumes a 150-man crew for the entire 21 weeks, a 

50-hour workweek for the duration, and a wage of $55/hour. This represents peak staffing and 

labor rates. The number of workers would vary over time, depending on the nature of the tasks 

and stage of construction.103 Thus, our estimate of direct installation costs corresponds to a 

longer duration than claimed. Regardless, it is important to note that this duration corresponds to 

construction of a much smaller project (less bypass, preheater modifications, etc.) than proposed 

by Black & Veatch. Further, we did not estimate construction duration but rather the length of 

time from the effective date of the final rulemaking to startup of the SCR or 36 months. Thus, 

the basis of this comment's starting point, an EPA estimate of 38 weeks, appears incorrect104. 

The SJGS record does not contain a schedule, which is required to estimate the staffing and 

duration of construction. 

Comment: EPA asserts that “[t]he contingencies included in the Black & Veatch cost 

estimates are double-counted and excessive,” based on the misimpression that there are three 

contingencies “imbedded” in the analysis. However, two of the three allowances are for known 

costs, and therefore are not “contingencies.” Specifically, the complexity factor for structural 

steel costs of 1.2 (for Units 1 and 2) and 1.5 (for Units 3 and 4) are known, expected costs, and 

therefore do not constitute a contingency factor, as noted previously. Also, the $2 million 

estimated for underground obstructions and the $500,000 estimated for on-site buildings are also 

known, and therefore do not represent a duplicative contingency factor. Thus, EPA’s claim that 

PNM double-counted its contingency costs is incorrect and underestimates the cost of SCRs at 

SJGS by $61,978,000. 

Response: This comment explains that the "complexity factor," site unknowns, and 

general building requirements are not contingencies, but rather known factors. Based on this 

explanation and the information we have about the SJGS, we concur that these complexity 

 102 10/21/10 Norem Email to Kordzi, PNM Responses to Follow-Up Questions from October 14, 2010 Conference 

Call Regarding BART Cost Estimate, Table 1. Presentation of SJRPP Estimate in the BART Format. 

103 See, for example, J.A. Hines and others, Reliant Energy SCR Construction Implementation Plan, ICAC Forum 

'02: Cutting NOx, 2002, Available at: http://www.babcock.com/library/pdf/BR-1728.pdf and J.A. Hines and others, 

Design for Constructability -- A Method for Reducing SCR Project Costs, Mega, 2001, Available at: 

http://www.babcock.com/library/pdf/br-1720.pdf. 104 The commenter’s statement of our assumption of 38 weeks of construction, references “EPA-600/R-02/076.” 

This document, entitled, “Emissions of Organic Air Toxics from Open Burning,” does not have anything to do with 

SCR and appears to be a mistake. 
41 

factors, and the engineering estimates for underground obstructions and on-site buildings, are 

reasonable and we have modified our cost estimates to reflect Black & Veatch's estimates. 

Comment: EPA also claims that the Interest During Construction included in the Black 

& Veatch cost estimates are not allowed by the Cost Manual. Therefore, this cost was eliminated 

from the cost analysis underlying the proposed FIP. However, this cost item is a real project 

cost, which will be incurred by PNM to finance the project and must by recovered from the SJGS 

customers. The rejection of costs associated with Interest During Construction underestimates 

the cost of the project by $78,300,000. 

Response: The Black & Veatch cost analysis includes a charge for interest during 

construction of 7.41% of direct plus indirect costs. This charge is generally known as the 

Allowance for Funds Used During Construction (AFUDC) and is specifically disallowed under 

the Cost Manual methodology and specifically disallowed for SCRs.105 A cost effectiveness 

analysis is a regulatory analysis that is based on current annual dollars without any inflation. 

AFUDC is an accounting method. Assets under construction do not provide service to current 

customers and thus associated interest and allowed return on equity are not charged to current 

customers. Instead, AFUDC capitalizes these costs and adds them to the rate base so that they 

can be recovered from future customers when the assets are used. Thus, these charges represent 

future cash income to the utility. In other words, AFUDC is the accumulated cost of carrying 

capital and holding it waiting to spend, so money can be made in the future by selling electricity. 

Future income should not be charged against the cost of a SCR in a BART cost-effectiveness 

analysis. These costs are not part of the constant dollar approach found in the Cost Manual and 

should not be included in BART cost-effectiveness analyses. 

3. Concerns over Possible Electricity Rate Increases 

Comment: Both the CAA and EPA BART regulations require consideration of the 

remaining useful life of a source. Requiring the imposition of possibly $1 billion or more of 

control technology capital costs at SJGS, a nearly 40-year old plant, presents a likely scenario 

where the remaining useful life of SJGS is less than the time period needed for amortizing the 

costs of the control technologies. As such, it could make production at SJGS during its 

remaining useful life uneconomical in comparison with other existing or future plants. If, in 

light of SJGS' estimated remaining useful life, it is determined that an investment of such 

magnitude does not make economic sense, owners of SJGS must evaluate alternate long-term 

options for meeting obligations to provide a cost-effective, reliable supply of electricity to 

customers. As such, the significant cost of requiring such SCR at SJGS will substantially 

increase the cost of electricity produced by SJGS. Over two million electric customers in New 

Mexico and other western states stand to be directly and adversely affected by the EPA proposal. 

PNM estimates that the average residential customer will experience a 10 percent increase in 

rates due solely to EPA's proposed SCR technology. As a result of the Proposed Rule, PNM has 

indicated that possible sources of replacement power may be needed to ensure it can fulfill its 

obligation to provide electricity to the citizens of New Mexico. 

 105 EPA Air Pollution Control Cost Manual, pdf 486, Table 2.5, E (Allowance for Funds During Construction) = 0. 
42 

Response: The commenter is correct that the remaining useful life of a facility may 

impact the BART determination. As we note in the BART Guidelines, 

The ‘‘remaining useful life’’ of a source, if it represents a relatively short time period, 

may affect the annualized costs of retrofit controls. For example, the methods for calculating 

annualized costs in EPA’s OAQPS Control Cost Manual require the use of a specified time 

period for amortization that varies based upon the type of control. If the remaining useful life 

will clearly exceed this time period, the remaining useful life has essentially no effect on control 

costs and on the BART determination process. Where the remaining useful life is less than the 

time period for amortizing costs, you should use this shorter time period in your cost 

calculations. 106

The BART Guidelines further clarify, “[w]here this affects the BART determination, this 

date should be assured by a federally- or State-enforceable restriction preventing further 

operation.” 

As part of our review of PNM’s BART determination for the SJGS, we met with 

representatives of PNM and its contractor several times, and communicated numerous times 

through email and phone. At no point did PNM indicate that it wished to constrain the 

amortization period for financing BART controls based on the remaining useful life of the 

facility through the use of a federally enforceable restriction. 

Comment: Several local and county governments and municipal power systems 

expressed concern that the proposed FIP would require a major capital expenditure that could 

well exceed $750 million, according to PNM. Such significant costs will drastically increase the 

cost of power produced by the SJGS and have the potential to increase electricity rates in the 

communities served by the SJGS. Another commenter stated our NOx BART proposal for the 

SJGS would cost New Mexico or Albuquerque ratepayers $10.20 more a year, or 85 cents a 

month, which is the price of a candy bar, so cleaning up this decades old air pollution is 

affordable and now is the time to do it. 

Response: As discussed in our proposal, we disagree with PNM’s cost estimate for 

installing SCR on the four units of the SJGS. Although PNM estimated the total cost to be in 

excess of $1 Billion, we estimated that cost to be approximately $250 Million. As discussed 

elsewhere in our response to comments, taking into consideration various comments, we have 

refined our estimate to be $344,542,604. In light of the visibility benefits we predict will occur, 

we consider this to be cost effective. We take our duty to estimate the cost of controls very 

seriously, and make every attempt to make a thoughtful and well informed determination. 

However, we do not consider a potential increase in electricity rates to be the most appropriate 

type of analysis for considering the costs of compliance in a BART determination. Nevertheless, 

we note that our cost estimate, being about 1/3 that of PNM’s will result in significantly less 

costs being passed on to rate payers. 

4. Comments that Opined on our Reliance on the EPA Air Pollution Control Cost Manual 

 106 70 FR 39104, 39169. 
43 

Comment: The rejection of PNM's escalation factors is unrealistic. By relying too 

heavily on the Cost Manual, EPA’s analysis not only omits the specific line items, it also omits 

or alters various estimating factors utilized by Black & Veatch in PNM’s analysis. EPA relied 

on the Chemical Engineering Plant Cost Index (CEPCI) to escalate costs from the Cost Manual. 

However, although that index may be a reasonable tool for a chemical plant, it does not properly 

account for escalation of costs at power plants. In contrast, Black & Veatch developed an 

appropriate escalation factor with the help of an outside consulting firm specializing in financial 

analysis and forecasting, which incorporates the complete Black & Veatch database of “as-built” 

costs, the Bureau of Labor Statistics indices, and the consulting firm’s database of costs and 

indices, all tailored specifically to the power generation industry. 

Response: The CECPI, which is published monthly by the magazine, Chemical 

Engineering, has been used for decades in regulatory cost effectiveness analyses and is one of 

the factors that allows a comparison to be made between cost effectiveness analyses at different 

facilities. This method was selected by EPA's Office of Air Quality Planning and Standards for 

use in regulatory cost effectiveness analyses because "this index specifically covers cost items 

that are pertinent to pollution control equipment (materials, construction labor, structural support, 

engineering & supervision, etc.)."107 The Black & Veatch escalation index, on the other hand, is 

proprietary and not subject to public review. 

Comment: In rejecting PNM's cost estimates, EPA incorrectly asserts that some of the 

costs relied on by PNM are not consistent with EPA's Air Pollution Control Cost Manual 

("Manual"). See 76 Fed. Reg. at 502. However, EPA is required to consider site-specific costs, 

even when those costs are not included in such Manual. See Am. Corn Growers Ass'n v. EPA, 

291 F.3d 1,6-7 (D.C. Cir. 2002); 70 Fed. Reg. 39127, 39166 & n.15 (July 6, 2005). As detailed 

in American Corn Growers, BART determinations must be made on a "source-specific basis," 

which includes costs that are source specific. Moreover, EPA's own BART rules contemplate 

that based upon site specific elements, an available control technology may be eliminated from 

consideration. "[O]ne or more of the available control options may be eliminated from 

consideration because they are demonstrated to be technically infeasible or to have unacceptable 

energy, cost, or non-air quality environmental impacts on a case-by-case (or site-specific) basis." 

Emphasis added. Id. at 39164. Despite the recognition by EPA regulations and guidance that its 

Control Cost Manual may be inadequate in some cases, Region 6 refers to the Cost Control 

Manual as “the standard procedure developed by EPA” that is “stipulated in the BART 

Guidelines,” and cites to it more than thirty times in its analysis. Although Region 6’s analysis 

acknowledges the requirement that BART analyses must take “unusual circumstances” into 

account, the Region’s analysis fails to properly do so. Region 6 criticizes PNM and Black & 

Veatch for “deviating” from that “standard procedure.” However, those “deviations” in fact 

represent either estimates of costs associated with the “unusual circumstances” that would 

significantly complicate the installation of SCRs at SJGS or adjustments to the assumptions in 

the manual to appropriately reflect the real costs that will be associated with installing SCRs at 

SJGS. 

 107 Email from Larry Sorrels (OAQPS) to Don Shepherd (Park Service) with cc to Anita Lee (EPA Region 9), dated 

7/21/10, concerning the SRP Navajo Generating Station SCR cost estimate. 
44 

Response: We disagree with commenter’s view that our cost analysis is improper, but we 

agree that the Cost Manual is not the only source of information for the BART analysis. For 

instance, the reference to the Cost Manual in the BART Guidelines clearly recognizes the 

potential limitations of the Manual and the need to consider additional information sources: 

The basis for equipment cost estimates also should be documented, either with 

data supplied by an equipment vendor (i.e., budget estimates or bids) or by a 

referenced source (such as the OAQPS Control Cost Manual, Fifth Edition, 

February 1996, EPA 453/B-96-001). In order to maintain and improve 

consistency, cost estimates should be based on the OAQPS Control Cost Manual, 

where possible. The Control Cost Manual addresses most control technologies in 

sufficient detail for a BART analysis. The cost analysis should also take into 

account any site-specific design or other conditions identified above that affect 

the cost of a particular BART technology option.108

The Control Cost Manual contains two types of information. First, it establishes a 

methodology for calculating cost effectiveness that allows comparison across multiple units. 

This methodology is a regulatory cost analysis that is not intended to reflect the "real costs that 

will be associated with installing SCRs at SJGS." The regulatory cost is expressed in current real 

or constant dollars, less inflation. Consistency among analyses performed across the United 

States is critical to establish cost effectiveness. Black & Veatch did not follow the regulatory 

cost method. Instead, it used a combination of methods that has been rejected in numerous other 

similar cases. These methods included the use of CUECost, a model that estimates control costs 

using the levelized cost method developed by the Electric Power Research Institute (EPRI), and 

which is not approved for BART determinations; extrapolation from several other projects; and 

its own proprietary and confidential databases not available for public review. 

Second, the Control Cost Manual contains specific cost estimating procedures for 

individual pollution control equipment, such as flares, scrubbers, and SCRs. These sections of 

the Manual generally set out standard design procedures used to size the equipment, factors for 

estimating direct and indirect costs from installed capital costs (obtained from vendor quotes), 

and sometimes provide cost estimates for some equipment components. We generally did not 

use this section of the Manual except as discussed elsewhere in these responses to demonstrate 

that Black & Veatch's estimates were out of reasonable bounds. 

Finally, as to unusual circumstances, the Guidelines require that "documentation" be 

provided for "any unusual circumstances that exist for the source that would lead to costeffectiveness estimates that would exceed that for recent retrofits."109 PNM did not provide any 

documentation of unusual circumstances related to the BART determinations in any of its cost 

analysis. An example of adequate documentation is that found in the appendices of the 8/17/10 

Navajo Cost Analysis prepared by Sargent & Lundy for a nearby, similar facility. 

 108 70 FR 39104, 39166. 

109 70 FR 39168 (July 6, 2005). 
45 

We subsequently toured the SJGS plant site on May 19, 2011.110 The SJGS site is tightly 

packed, but not more so than other space-constrained sites where SCR has been retrofit for much 

less than estimated for SJGS.111 Gibson, a complex, space-constrained retrofit in which the SCR 

was built 230 feet above the power station using the largest crane in the world112 only cost 

$249/kW in 2010 dollars.113 See photograph in Figure 2. Similarly, the Belews Creek SCR, one 

of the largest and most complex SCR retrofit projects in the U.S., involved installing the SCR 

280 feet above ground level above the boiler building. This retrofit only cost $145/kW (in 2003, 

escalate) in 2010 dollars,114 compared to $423/kW to $567/kW for SJGS. 

Figure 2 

Construction of SCR at Gibson115

Black & Veatch's estimates of capital cost to retrofit SCR at SJGS ($446/kW - $599/kW) 

are higher than actual installed cost for Gibson and many other existing retrofit SCRs, including 

those with extreme retrofit difficulty. The record including our site visit does not document any 

unusual circumstances that would justify the out-of-bound costs claimed by Black & Veatch for 

SJGS. Thus, we do not believe that unusual circumstances are warranted. 

 110 See San Juan Generating Station Site Visit, 5/23/11 111 Fox Report, pp. 28-29. 112 Bob Ellis, Standing on the Shoulder of Giants, Modern Power Systems, July 2002. 113 McIlvaine, NOx Market Update, August 2004. SCR was retrofit on Gibson Units 2-4 in 2002 and 2003 at 

$179/kW. Assuming 2002 dollars, this escalates to ($179/kW)(550.7/395.6) = $249/kW. 

http://www.mcilvainecompany.com/sampleupdates/NoxMarketUpdateSample.htm. 114 Bill Hoskins, Uniqueness of SCR Retrofits Translates into Broad Cost Variation, PowerGen Worldwide, May 

2003. Available at: http://www.power-eng.com/articles/print/volume-107/issue-5/features/uniqueness-of-scrretrofits-translates-into-broad-cost-variations.html. 

115 http://www.fwc.com/GlobalPowerGroup/AuxillaryEquipment/SelectiveCatalyticReductionSystems.cfm. 
46 

Comment: The exclusive use of the Cost Manual underestimates the expected costs for 

SCRs at SJGS for several reasons. First, the Manual was last updated in 2002 and Section 4.2, 

Chapter 2, Selective Catalytic Reduction, was actually written in October 2000. In addition, on 

page 2-40 of the SCR section, the Manual indicates that the costs presented are based on 1998 

dollars. Therefore, the Manual does not reflect more recent experience with SCR installations, 

the cost of which has skyrocketed. Second, the 2002 version of the Manual was the very first 

version to specifically address NOx controls at all. According to the introduction to the Manual, 

EPA was at that time “entering new and uncharted territory for part of the Manual” because 

“previous editions did not discuss NOX or SO2 controls, and [the 2002] edition starts the process 

of correcting that oversight.” Finally, EPA also admits in the Manual that it had difficulty 

obtaining information on control costs because most of the information is proprietary – the very 

type of information to which Black & Veatch has ready access. 

Response: As discussed elsewhere in our response to comments, the Cost Manual 

contains two types of information, general cost analysis methodology and control-specific 

costing information. This comment addresses the latter. The information on SCR in Chapter 2 

of the Cost Manual contains general information on SCR, design procedures, and some cost 

information. We agree that the cost information does not reflect current market costs. Thus, cost 

data should be escalated to current dollars using the CECPI before it is used or replaced with 

site-specific vendor quotes. We did not use any SCR costs data from this chapter in our analysis. 

Comment: The Region 6 cost estimate rarely differs from the Cost Control Manual, and 

only does so where the information from outside the Cost Control Manual would serve to reduce 

the amount of the cost estimate. Region 6 provides no justification for straying from the manual 

in those instances, despite focusing so heavily on it in others. For example, Region 6’s 

consultant applied an SCR life span of 30 years instead of the 20 year life span provided in the 

Cost Control Manual. The justification for choosing a different life span than provided for in the 

manual is that other facilities have requested 30 year life spans in requests for proposal and some 

unidentified SCRs in Europe have lasted that long. If such general, anecdotal information were 

sufficient to convince Region 6 to stray from the Cost Control Manual, the Region 6 analysis 

should be replete with variations from the outdated Cost Control Manual. However, the Region 

6 analysis only varies from the manual where it serves to further reduce costs. In contrast, 

because PNM did not perform a specific life span analysis of an SCR at SJGS, PNM’s analysis 

accepts the Cost Control Manual’s recommendation of a 20-year SCR life span. The use of a 30-

year lifespan underestimates the cost estimate of SCR by $15,268,000. 

Response: We disagree with this comment and we used the Cost Manual appropriately, 

as directed by the RHR. We used the Cost Manual for cost factors that for reasons expressed 

elsewhere in our response to comments, we feel were miscalculated by Black & Veatch, but 

were not otherwise available in the public domain. We did not use any actual cost data from the 

Cost Manual. In the case of SCR lifetime, the Cost Manual does not recommend a lifetime for 

an SCR, but rather sets out a calculation example that uses a lifetime of 20 years. In fact, this 

same calculation makes many other assumptions that we felt were not applicable to SJGS and if 

used anyway, would have resulted in lower cost estimates, but which were not used in our 

analysis. 
47 

The lifetime of an SCR, which is a metal frame packed with catalyst modules, is equal to 

the lifetime of the boiler, which might easily be over 60 years. The lifetime of a retrofit SCR is 

generally set equal to the remaining useful life of the facility. The record is silent on the 

remaining useful life of the SJGS units. These units were built between 1972 (Unit 1) and 1982 

(Unit 4) and are currently 30 to 40 years old. Thus, based on the record in this case, there is no 

reason to assume their remaining useful life is less than 30 years, based on experience in the 

utility industry. Further, USGS studies of the coal reserves that SJGS relies on indicates that the 

local coal supply is adequate to support a remaining useful life of 30 years.116 

Further, as previously noted, there are many SCRs that were installed in Europe in the 

1980s that are still in operation today. Many utilities routinely specify 30+ year lifetimes in 

requests for proposal and to evaluate proposals. A study of the economic risks from SCR 

operation at the Detroit Edison Monroe power plant, for example, used 30 years as the 

anticipated lifetime.117 PNM has not provided any contrary information. In fact, an analysis 

prepared by Black & Veatch for another facility assumed a 40 year SCR lifetime.118 And finally, 

Sargent & Lundy assumed a design life of 30 years119 for the nearby Navajo Generating Station 

which burns a similar coal. We conclude there is nothing in the record to support a 20 year 

lifetime for the SCR and believe a 30 year lifetime is justified. 

Comment: EPA also justifies its refusal to consider additional line items outside the 

scope of the Cost Control Manual on the grounds that “PNM had provided no documentation 

regarding unique circumstances related to the BART determinations.” That claim is incorrect. 

Region 6’s own analysis cites the documentation PNM submitted to demonstrate the unique 

circumstances at SJGS, referred to by Region 6 as Black & Veatch’s “Cost Analysis Manual 

Commentary.” That document was a response to the cost analysis that was initially prepared by 

NMED in March 2008 as a response to follow-up questions from NMED regarding the BART 

determination for SJGS. The “Cost Analysis Manual Commentary” demonstrates two critical 

points. First, the document demonstrates that the Cost Control Manual method of estimating cost 

would omit the significant line item expenditures noted above that will be real costs associated 

with installing SCRs at SJGS. Second, the document demonstrates that, but for those line items, 

the Black & Veatch estimates would be comparable to NMED’s cost estimate. 

In addition to the “Cost Analysis Manual Commentary,” PNM also provided significant 

evidence of the site-specific challenges directly to Region 6 in response to its questions over the 

several months during which Region 6 prepared its BART determination for SJGS. PNM also 

discussed those questions with Region 6 and its consultant in a lengthy, detailed telephone 

conference on October 14, 2010. The significant amount of information provided previously to 

NMED regarding site-specific challenges was also provided to Region 6. Thus, the assertion by 

 116 Gretchen K. Hoffman and Glen E. Jones, Coal Availability Study - Fruitland Formation in the Fruitland and 

Navajo Fields, Northwest New Mexico, USGS Open-File 464, January 24, 2002, Available at: 

http://geoinfo.nmt.edu/publications/openfile/downloads/ofr400-499/451-475/464/ofr_464.pdf. 

117 S.D. Unwin and others, Selective Catalytic Reduction (SCR) System Design and Operations: Quantitative Risk 

Analysis of Options, Presented at CCPS 17th Annual International Conference: Risk, Reliability, and Security, p. 3. 

Available here: http://www.unwin-co.com/files%5CSCR-Risk-Paper,CCPS-RRS2002.pdf. 118 Email from O'Brien to Van Helvoirt, September 28, 2004, Re: Cost Impact, WPS-011904 at WPS-011905. 

119 8/17/10 Salt River Project Navajo Generating Station Units 1, 2, 3 SCR and Baghouse Capital Cost Estimate 

Report (S&L Navajo Cost Analysis), Appendix A, p. 6, Sec. 1.7. 
48 

Region 6 that PNM has failed to sufficiently document the site-specific challenges at SJGS is 

incorrect. 

Response: The specific items in dispute are discussed elsewhere in our response to 

comments. The information provided in the "Cost Analysis Manual Commentary" and 

additionally provided to NMED and us explains how Black & Veatch extrapolated costs that it 

estimated from other facilities to apply to SJGS. The alleged unique, site-specific constraints at 

SJGS, that would justify extrapolating costs from these other facilities, the St. Johns River Power 

Project, which burns coke, and Harding Street, were never explained. The record, for example, 

does not contain any structural steel and duct layout drawings to justify this high contingency 

and other factors, nor does it contain vendor quotes specific to SJGS's coal and site constraints. 

In fact, as noted elsewhere, we specifically asked PNM to document site specific constraints but 

they did not respond.

B. Comments on our Proposed NOx BART Emission Limits 

Comment: PNM questions EPA’s proposed compliance method because it would be 

inconsistent with the compliance demonstration required by other air quality standards that 

EPA’s BART Guidelines specifically encourage states to follow in setting BART limits. 

Regardless of the NOx limit chosen (whether 0.05 lb/MMBtu with SCRs, as EPA has proposed, 

or 0.23 lb/MMBtu with SNCRs, based on NMED’s 2011 draft SIP revision), the BART limit 

should not be based on daily averages of thirty (30) calendar days, as EPA has proposed. If 

calendar days are used, the average could include as little as one hour of operation if the unit is 

offline for an outage that lasts longer than thirty days because the first hour of operation would 

be the only data recorded in the last thirty calendar days. To avoid this approach, PNM asks 

Region 6 to consider changing “calendar days” to “boiler operating days” (i.e., days in which the 

unit ran for at least one hour). That approach would be consistent with EPA’s own BART 

Guidelines, which include the following advice to states: 

For EGUS, specify an averaging time of a 30-day rolling average, and contain a 

definition of “boiler operating day” that is consistent with the definition in the 

proposed revisions to the NSPS for utility boilers in 40 CFR Part 60, subpart Da. 

The “boiler operating day” (BOD) would ensure that, when an outage occurs, the 

emissions following startup will be averaged with the emissions data from before the outage, 

rather than with the period of time during which the unit did not have any emissions at all 

because it was offline. 

Response: We agree with this comment that our proposed NOx emission limit should be 

based on BODs, rather than a straight calendar average. In response to this comment, we have 

reanalyzed our proposed determination that the units of the SJGS can achieve a NOx emission 

limit of 0.05 lbs/MMBtu on a continuous basis, using the BOD concept. We have done this 

because we believe the same metric should be used to both determine BART and to determine 

compliance with BART. The results of that analysis are presented in response to another 

comment. In summary, we continue to believe that NOx BART for the units of the SJGS is an 

emission limit of 0.05 lbs/MMBtu. We have concluded that emission limit should be based on a 
49 

30-day BOD rolling average based on any operation in a given day counting toward the average. 

We believe that averaging scheme complies with the BART Guidelines, which defines a BOD to 

be “any 24-hour period between 12:00 midnight and the following midnight during which any 

fuel is combusted at any time at the steam generating unit.”120

Comment: The United States Forest Service (USFS) is in favor of the EPA's BART 

determination for SCR on the SJGS to meet a NOx emission limit of 0.05 lb/MMBtu. The USFS 

believes this emission limit is adequate and will improve visibility at Class I areas throughout the 

Four Comers region. Additionally, the USFS feels SCR has already been determined to be 

BART at several other coal-fired power plants across the United States. Lastly, the USFS 

approves of the methodology employed by EPA in their modeling assessment and agrees with 

examining the cumulative impacts at all affected Class I areas instead of individually. 

Response: We agree with the USFS. 

Comment: EPA predetermined the cost-effectiveness of SCR at SJGS “assuming an 

outlet NOx of 0.05 lb/MMBtu.” EPA then proposed that assumed rate as the BART emission 

limit for SJGS. EPA’s assumption is unfounded – the installation of SCRs at SJGS will not 

enable the units to achieve 0.05 lb/MMBtu on a continuous basis. As such, the proposed 0.05 

lb/MMBtu limit cannot be BART for SJGS. 

Response: We disagree with this comment. We initially estimated the cost effectiveness 

of SCR, assuming an outlet NOx of 0.07 lb/MMBtu, to provide a direct comparison with Black 

& Veatch's analysis. Following this, we determined that a BART emission limit of 0.05 

lb/MMBtu was appropriate and then refined the cost effectiveness on that basis. The BART 

level of 0.05 lb/MMBtu was selected based on an examination of continuous emission 

monitoring systems (CEMS) data for existing units operating with retrofit SCRs, as we explain 

elsewhere in our response to comments. 

Comment: It appears Dr. Fox nevertheless attempted to justify that assumption in Section 

IV of her report in several ways. First, Dr. Fox asserts that “SCRs are routinely designed to 

achieve 90% NOx control,” claiming that 90 percent reduction at SJGS would result in NOx 

emissions of 0.05 lb/MMBtu or even lower. In contrast, Black & Veatch, who has extensive 

practical experience in actually designing and installing retrofit SCRs determined that a retrofit 

SCR would only be capable of achieving 0.07 lb/MMBtu on a continuous basis, particularly if 

required to use the low-oxidation catalyst assumed by Region 6 to minimize ancillary emission 

increases associated with SCR. 

Response: We do not believe the claim that Black & Veatch "determined that a retrofit 

SCR would only be capable of achieving 0.07 lb/MMBtu on a continuous basis..." is supported 

in the record by any calculations or arrangement drawings. Rather, the 0.07 lb/MMBtu value is 

simply stated in the initial June 6, 2007 Black & Veatch BART analysis without any explanation 

as to how it was determined or why 0.07 lb/MMBtu satisfies BART rather than a lower limit.121 

The basis for this limit has been questioned by NMED, the National Park Service (NPS) and us 

 120 Id.. 121 6/7/07 B&V BART Analysis, Table ES-2, Table 2-3, Table 6-1, 7-1 
50 

since July 2007, but we do not believe that PNM has provided adequate supporting analysis. We 

do not view an unsupported statement, such as this, questioned on the record by many parties and 

inconsistent with retrofit SCR experience, to be sufficient to support a BART determination. 

During the NMED BART analysis, both NMED and NPS challenged the basis of 0.07 

lb/MMBtu, arguing it should be lower. In July 2007, PNM explained that the value of 0.07 

lb/MMBtu was selected based on an information search of the BACT/LAER Clearinghouse and 

specifically based on a permit issued by Georgia in May 2007 to the new Longleaf Energy 

Associates (LS Power) plant with a NOx limit of 0.07 lb/MMBtu for a 30-day rolling average.122 

Thus, PNM apparently based its NOx BART level on a permit limit established for a new 

facility. We identified seven other permits for new facilities with NOx emission limits of 0.05 

lb/MMBtu or lower.123 In addition, in April 2010, Georgia issued a second permit to new coalfired power plant, Plant Washington. Based on experience gained from then operating retrofit 

SCRs, Plant Washington was permitted with NOx emission limits of 0.050 lb/MMBtu based on a 

30-day rolling average and 0.030 lb/MMBtu based on a 12-month rolling average.124 PNM did 

not identify this new permit. 

In response to NMED and NPS comments, PNM also claimed that "[s]ince SCR 

performance is highly dependent on having even flow distribution into the ammonia injection 

grid and the catalyst, the 0.07 lb/MMBtu emission rate reflects the limitation associated with 

retrofit SCR's and specifically the limitations at SJGS."125 However, no support is provided for 

this claim. A demonstration of a 0.07 lb/MMBtu limitation for SJGS would require design of the 

ductwork and CFD modeling to assess the distribution of velocity, temperature, and ammonia of 

the flue gas. The record does not contain any responsive analysis or any evidence that even a 

preliminary design for the SCRs exist. In fact, in response to our request for a copy of plot plans 

to assess this issue, PNM responded that "[p]lot plans have not been developed for the SCR."126 

In October 2010, we specifically asked PNM for the basis of its proposed BART limit 

and for an explanation of why a higher removal efficiency (i.e., a lower NOx limit) could not be 

achieved. In response, PNM did not provide any site-specific information, calculations or design 

drawings, but rather argued that the NOx emission value was established based on outlet NOx 

emissions, not removal efficiency.127 We do not believe this provides any basis for the choice of 

0.07 lb/MMBtu or explain why a lower NOx limit cannot be achieved. 

 122 Email from Norem to Shepherd, 7/2/07, Available at: 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/NMED_Ex7c_EmailThread_CostAnalysisAttached.pdf. 123 Fox Report, p. 33. 124 Georgia Department of Natural Resources, Air Quality Permit, Plant Washington, Permit No. 4911-303-0051P010-0, April 8, 2010, (Attach. 45). Available at: 

http://airpermit.dnr.state.ga.us/gaairpermits/PermitPDF.aspx?id=PDF-PI-17924. 125 7/2/07 Norem Email and PNM Response to BART Analysis Questions from NMED, September 14, 2007, p. 8, 

Available at: 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/PNM_Response_to_NMED_Rev_070914rev2.pdf. 126 9/23/10 Norem Email to Kordzi, Re: PNM_BART notes re_Response to EPA_Fox 22 Questions 092710.DOC, 

Response to Question 3. 

127 Email from Norem to Kordzi, 9/23/10, Re: PNM_BART notes re_Response to EPA_Fox 22 Questions 

092710.DOC, Response to Question 2. 
51 

In fact, we do not believe PNM has established a basis for its assertion that SJGS and 

retrofit units in general cannot meet a NOx limit lower than 0.07 lb/MMBtu. Black & Veatch 

itself extrapolated the cost for the SJGS SCR from retrofit SCRs that it designed to achieve lower 

NOx emission limits than the claimed 0.07 lb/MMBtu retrofit cap. The catalyst cost for SJGS 

was extrapolated from Harding Street Unit 7, a retrofit SCR designed by Black & Veatch to 

reduce NOx from 0.34 lb/MMBtu to 0.044 lb/MMBtu, or by 87%128 and advertised by Black & 

Veatch at 0.05 lb/MMBtu.129 The costs for most of the rest of the SJGS SCR system were 

extrapolated from the St. John River Power Park project, a retrofit SCR designed by Black & 

Veatch to reduce NOx from an inlet of a maximum of 0.66 lb/MMBtu to 0.06 lb/MMBtu.130 We 

note the NOx design basis was 0.05 lbs/MMBtu for the SCR retrofit for the nearby Navajo 

Generating Station, a facility of a similar age that burns a similar coal, with a more constrained 

site.131

Lastly, as explained elsewhere in our response to comments, we present data that 

demonstrates that retrofit SCR installations are capable of achieving a NOx limit of 0.05 

lbs/MMBtu on a continuous basis. Therefore, we believe the statement that a retrofit SCR would 

only be capable of achieving 0.07 lb/MMBtu on a continuous basis, is factually incorrect. 

Comment: Several commenters stated that our claim that many facilities are using SCR 

to actually achieve lower emission rates than 0.07 lb/MMBtu (including the Havana Unit 9, 

Amos Units 1 and 2, Chesterfield Unit 6, Cardinal Units 2 and 3, Colbert Unit 5, Ghent Units 3 

and 4, and Mill Creek Unit 3) is incorrect. This commenter states that while these units have 

shown the ability to reach 0.05 lb/MMBtu or lower at times, those units are unable to do so on a 

continuous basis. Thus, the commenter claims, if the units cited by us were in fact subject to a 

0.05 lb/MMBtu emission limit, those limits would have been violated many times at each unit. 

Several other commenters stated that our proposed NOx BART emission limit of 0.05 

lbs/MMBtu is not achievable as a retrofit technology on older units for under a 30‐day rolling 

averaging period. The Clean Air Act programs applicable to stationary sources recognize the 

difference between the potential effectiveness of retrofit controls at existing units and controls 

that can be installed during the initial construction of a new unit. The visibility provisions of the 

Clean Air Act are no different. They clearly recognize that retrofitting existing units with new 

controls will often entail unique and difficult challenges that could result in lower control 

efficiencies than might be possible for new units and require permitting authorities to take those 

concerns into account. Region 6 fails to make that important distinction in its proposal to require 

SJGS to meet a 0.05 lb/MMBtu that has only been achieved on a continuous basis by two new 

units that are less than five years old and that were designed from inception to accommodate 

SCRs. One commenter stated that Black and Veatch, through a site-specific technical analysis 

has determined that the SJGS units could continuously achieve an emission rate of 0.07 lbs 

 128 Email from Norem to Kordzi, October 13, 2010, Re: SJGS BART Analysis - Response on Catalyst Sizing 

Methodology. The design basis of the Harding SCR was 87.18% NOx reduction to an outlet of 37.8 ppmvd. The 

37.8 ppmvd converts to: (37.8)(9780)(46)/385.5x106

 = 0.044 lb/MMBtu. The inlet NOx: (0.044/(1-8717) = 0.34 

lb/MMBtu. 

129 Black & Veatch, Building a World of Difference, p. 4, Available at: 

http://www.bv.com/Downloads/Resources/Brochures/rsrc_ENR_CoalSelectiveCatalyticReduction.pdf. 130 10/8/10 Norem Email to Kordzi, Re: COMPLETE 100930 EPA Questions on OAQPS.pdf. 131 8/17/10 S&L Navajo Cost Analysis, Appendix A, p. 2 and Appx. R, p. 36. 
52 

NOx/MMBtu so EPA should accept this analysis or perform a site-specific analysis of its own. 

The emission limit proposed by Region 6 is unachievable at SJGS and therefore violates the 

Clean Air Act and EPA regulations, which require BART emission limits to be achievable. 

Response: We disagree with this comment and continue to believe that the NOx 

emission limit we proposed for the four units of the SJGS, 0.05 lbs/MMBtu, is achievable on a 

continuous basis. In reaching this conclusion, we followed the language in the BART 

Guidelines: 132

It is important, however, that in analyzing the technology you take into account 

the most stringent emission control level that the technology is capable of 

achieving. You should consider recent regulatory decisions and performance data 

(e.g., manufacturer’s data, engineering estimates and the experience of other 

sources) when identifying an emissions performance level or levels to evaluate. 

In assessing the capability of the control alternative, latitude exists to consider 

special circumstances pertinent to the specific source under review, or regarding 

the prior application of the control alternative. However, you should explain the 

basis for choosing the alternate level (or range) of control in the BART analysis. 

Without a showing of differences between the source and other sources that have 

achieved more stringent emissions limits, you should conclude that the level being 

achieved by those other sources is representative of the achievable level for the 

source being analyzed. 

First, we examined “the most stringent emission control level that technology [SCR] is 

capable of achieving.” As demonstrated below, we concluded that SCR is capable of achieving a 

NOx emission limit of 0.05 lbs/MMBtu. Second, we examined the record to determine if there 

existed “special circumstances pertinent to the specific source under review” that would prevent 

the units of the SJGS from achieving this limit, and found none. Third, concluding there was no 

“showing of differences between the source and other sources that have achieved more stringent 

emissions limits” that would preclude the application of this limit, we “conclude[d] that the level 

being achieved by those other sources is representative of the achievable level for the source 

being analyzed.” The following discussion expands on these points. 

We believe the commenter, PNM, misquotes our consultant’s report, which was 

incorporated into our proposal’s Technical Support Document (TSD). That report contained a 

previous study of SCR performance during the ozone season for the period 2003 - 2006. This 

study showed that several units were achieving a NOx emission limit of 0.05 lb/MMBtu at that 

time to meet NOx SIP Call regulations that were then in force. These SCRs only operated from 

May to October of each year, the ozone season. The SCRs were bypassed during the remainder 

of the year as they were not required to meet the NOx SIP Call. 

Also, this comment ignores the second part of our contractor’s discussion which explains 

that other SCR system designers have analyzed EPA’s Clean Air Market’s CEMS data to 

determine the NOx levels that are currently being achieved by over 100 SCR-equipped coal-fired 

 132 70 FR 39166 
53 

boilers.133 This analysis identified 25 units that are achieving NOx emissions less than 0.05 

lb/MMBtu on an hourly average basis.134 Others have reported similar results.135 Some 

examples of retrofit SCRs that have been designed and tested at or below 0.05 lb/MMBtu are 

briefly described below. All of these units are located at congested sites that required careful 

design. 

• SCRs at Seminole Units 1 and 2, two existing 650 MW units firing bituminous coal, were 

designed for 90% NOx reduction, from an inlet NOx of 0.413 lb/MMBtu to 0.04 

lb/MMBtu. Performance testing indicated the SCR systems significantly outperformed 

their NOx removal guarantees.136 

• SCRs at Morgantown Units 1 and 2, two existing 642 MW boilers that burn high sulfur 

(3%) eastern bituminous coal, were 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.137 The 

acceptance test demonstrated 92.65% to 94.6% NOx removal to outlets of 0.032 

lb/MMBtu at maximum load and 90% to 91.3% at minimum load to NOx outlets of 0.043 

to 0.054 lb/MMBtu. 

• Louisville Gas & Electric (now E.ON) retained Babcock Power and Duke Fluor Daniel to 

engineer, procure, and construct six SCRs within the LG&E system. The first was 

Trimble Unit 1 (tangentially fired 547 MW), followed by similar projects at Mill Creek 

Unit 3 (opposed wall fired 410 MW); Mill Creek 4 (opposed wall fired 520 MW); Ghent 

Units 3&4 (opposed wall fired 520 MW); and Ghent Unit 1 (tangentially fired 520 MW). 

Each SCR system was designed to reduce baseline NOx emissions by 90%. These 

systems included a variety of boilers, operating conditions, space restrictions, low and 

high dust loadings, low and high sulfur coals, various coal blends, and inlet NOx ranging 

from 0.34 to 0.45 lb/MMBtu. The acceptance tests indicate that all systems met or 

exceeded design requirements.138 Detailed results have been published for one of the 

units, Trimble Unit 1, which fires high sulfur (~4%) eastern bituminous coal. The SCR 

was designed to reduce NOx from 0.32 lb/MMBtu by 90% to 0.032 lb/MMBtu. Trimble 

 133 Fox Report, p. 31. 134 Clay Erickson, Robert Lisauskas, and Anthony Licata, What New in SCRs, DOE’s Environmental Control 

Conference, May 16, 2006., p. 28. Available here: 

http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/Licata.pdf; LG&E Energy, Selective Catalytic 

Reduction: From Planning to Operation, Competitive Power College, December 2005, p. 75-77. (Attach. 29). 135 M.J. Oliva and S.R. Khan, Performance Analysis of SCR Installations on Coal-Fired Boilers, Pittsburgh Coal 

Conference, September 2005, (Attach 27). 136 Jason Peltier, Top Plants: Seminole Generating Station, Palatka, Florida, Power, October 1, 2009, (Attach 31). 

Available at: http://www.powermag.com/coal/Top-Plants-Seminole-Generating-Station-PalatkaFlorida_2181_p4.html. 

137 Kellie Bresnahan and others, Design, Installation and Startup Experience on a High Removal Efficiency SCR 

System at Morgantown Generating Station Units 1&2, Mega 2008, (Attach. 32). Available at: 

http://secure.awma.org/presentations/Mega08/presentations/5-Erickson.pdf. 138 Eileen Saunders and others, SCR System Performance at LG&E’s Trimble County Generating Station, EPRI 

Workshop on Selective Catalytic Reduction, October 2002. (Attach 33). 
54 

was a difficult retrofit application with space restrictions more severe than SJGS and a 

high sulfur fuel.139 The acceptance testing exceeded expectations. 

• American Electric Power (AEP) has installed SCRs designed to achieve 90% NOx 

control on many units in its fleet. The demonstrated performance of one of these units, 

the 1300 MW AEP Mountaineer facility, has been reported.140

• An 85% efficient SCR was originally installed on the 590 MW Cliffside Unit 5 in May 

2002. The unit burns 1.5% Central Appalachian bituminous coal. This unit was 

upgraded in 2003 to meet the NOx SIP call limit during the ozone season. The 

demonstration test indicate: “[T]he SCR system for the Unit 5 boiler at the Cliffside 

steam station operated at 93% NOx removal with the ammonia to NOx ratio variation 

within 5% for each reactor. While the SCR is not currently operated at this high NOx 

removal rate, the test results showed that the SCR is able to operate at high NOx removal 

without added risk to the catalyst or causing excessive ammonia slip.”141

• The 400 MW 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 performance tests demonstrated NOx removal at 91.6%.142

While these and other SCRs are routinely designed to achieve 90% NOx control, they are 

not routinely operated to meet these design targets as they operate under cap and trade programs 

that do not apply to specific units. This mismatch between design and operation, however, does 

not affect our basic conclusion regarding “the most stringent emission control level that the 

technology is capable of achieving.” Nevertheless, as we discuss below, we believe the units of 

the SJGS are capable of achieving a NOx emission limit of 0.05 lbs/MMBtu on a continuous 

basis. 

PNM presents graphs for each of the ozone season 2003-2006 units for the period 

January 2008 to November 2010. These graphs suggest that 0.05 lb/MMBtu is exceeded on 

numerous occasions and imply this was due to a limitation of the equipment to maintain control. 

There are several problems with these graphs. First, they appear to be based on an averaging 

convention that is inconsistent with their other comments. As is discussed elsewhere in our 

response to comments, we agree with PNM’s assertion in another comment that our proposed 

NOx emission limit should be based on boiler operating days, rather than a straight calendar 

average. In response to that comment, we have reanalyzed our proposed determination that the 

 

139 Eileen Saunders and others, Selective Catalytic Reduction System Performance at LG&E Energy LLC's 

Mill Creek and Ghent Generating Stations, EPRI Workshop on SCR, October 19-20, 2004, (Attach. 35). Available 

at: http://www.babcockpower.com/pdf/t-197.pdf. 

140 Clayton Erickson & Joseph Langone, Babcock Power Inc., Keys to Success: System Wide SCR Installation and 

Operation, Slides, PowerGen, 2006, (Attach 37). 141 Terence R. Ake, Clayton A. Erickson, and Linton K. Hutcheson, Increasing SCR NOx removal from 

85% to 93% at the Duke Power Cliffside Steam Station, April 2006 ASME Power Division Special Section, 

ENERGY-TECH.com, (Attach. 38). 

142 Saleem Zwayyed, Tom Pearson, and Travis Reynolds, Low Maintenance SCR at the South Carolina Electric and 

Gas Cope Generating Station Unit 1, PowerGen 2009, (Attach 39). 
55 

units of the SJGS can achieve a NOx emission limit of 0.05 lbs/MMBtu on a continuous basis, 

using the boiler operating day concept. 

PNM’s graphs appear to be based on calendar operating days. This distinction is 

significant, as the boiler operating day convention discussed by the regional haze rule143

smoothes out the 30-day rolling average outage spikes. Second, these charts include large blocks 

of time during which the SCRs were turned off because they were not required under the trading 

programs then in force. Third, these charts connect the dots across outage periods, when the 

SCRs are not in use and improperly include the zero hour days in the averages at elevated levels. 

We analyzed data from EPA’s Clean Air Markets Division (CAMD), which compiles 

continuous emission monitoring system (CEMS) data reported under various trading programs. 

We analyzed the NOx CEMS data for the period 2009-2010 to identify the best performing 

retrofit units that operate year round. We ranked the annual average NOx emissions for all units 

in the database for the years 2009 and 2010 from the lowest to the highest NOx emissions. The 

year 2009 was selected as it is the first year that most existing SCRs were operated year round to 

comply with CAIR, rather than just during the ozone season. The year 2010 was selected as it 

was the most current complete year of data at the time of analysis. We then selected those 

facilities that had at least one unit in the top 30 group in both years to identify consistently best 

performers. The annual average NOx emissions achieved by these two-year best performers are 

summarized below: 

Table 3 

Annual Average NOx Emissions 2009-2010 

Best Performers 

(lb/MMBtu) 

 2009 2010 

Havana 9 0.0361 0.0366

Cardinal 1 0.0379 0.0411

Parish 7 0.041 0.0543

Parish 8 0.0428 0.0407

Cardinal 2 0.0434 0.0523

Belews Creek 1 0.0451 0.0548

Amos 1 0.0452 0.0494

Cardinal 3 0.0454 0.0481

TS Power 0.0459 0.0457

Amos 2 0.048 0.0664

Edwards 3 0.0483 0.0504

Belews Creek 2 0.05 0.0558

Parish 5 0.0534 0.0519

Baldwin 1 0.0558 0.0548

Mitchell 1 0.0502 0.0535

Weston 4 0.0563 0.0561

Wansley 1 0.0567 0.0555

 143 70 FR 39172. 
56 

Parish 6 0.0671 0.0511

Baldwin 2 0.0601 0.0514

We then developed a spreadsheet program that used the CAMD data and calculated and 

graphed three types of 30-day rolling averages for most of these best performing units, plus those 

additional units graphed by PNM in Attachment C for the period 2008 - 2010 for the Ozone 

Transport Assessment Group (OTAG) units and 2006 - 2010 for the Texas units (Parish 7, 8). 

All of the units we analyzed were retrofitted with SCR. The period 2008 - 2010 was selected for 

the OTAG units as PNM used this period in the graphs it prepared to support this comment in 

Attachment C. 

As Exhibit 2 shows, the averaging conventions we used are: (1) a conventional 30-day 

calendar rolling average (30 day rolling); (2) a 30-day BOD rolling average based on any 

operation in a given day counting toward the average (BOD_any 30_day); and (3) a 30-day BOD 

rolling average based on only full 24-hour days (BOD_all 30_day). We believe that averaging 

scheme (2) complies with the regional haze rule, which defines a boiler operating day to be “any 

24-hour period between 12:00 midnight and the following midnight during which any fuel is 

combusted at any time at the steam generating unit.”144. 

The Havana Unit 9 data shows that it has operated under 0.05 lbs/MMBtu from mid-2009 

to the end of 2010 on a continuous basis. In fact, this unit has operated under 0.035 lbs/MMBtu 

for much of that time. The Parish Unit 7 data shows that it has operated under 0.05 lbs/MMBtu 

from mid-2006 to mid 2010 on a continuous basis. In fact, this unit has operated for months at 

approximately 0.035 lbs/MMBtu, and for approximately 2 years at approximately 0.04 

lbs/MMBtu. The Parish Unit 8 data show that it has operated almost continuously under 0.045 

lbs/MMBtu since the beginning of 2006. Other units’ data show months of continuous operation 

below 0.05 lbs/MMBtu. We believe this data demonstrates that similar coal fired units that have 

been retrofitted with SCR are capable of achieving NOx emission limits of 0.05 lbs/MMBtu on a 

continuous basis. 

In addition, it is important to note that most of the NOx CEMS data in the CAMD 

database is generated under cap and trade programs, such as the Acid Rain Program, Clean Air 

Interstate Rule (CAIR), and the NOx SIP Call145 or to comply with elevated permit limits, such 

as from netting out of NSR review. Therefore, these reporting units are not subject to regulatory 

requirements that compel the continuous operation of SCRs to achieve maximum NOx 

reductions. Consequently, a simple examination of the data will not always reveal the NOx 

reduction these limits are capable of achieving. Plants complying with regional, seasonal, or 

system-wide limits are under no obligation (and have no incentive) to continuously achieve the 

lowest individual rates possible. 

This is demonstrated by the Parish units in Texas, which are likely the best performing 

SCR units over the long term (SCRs operated year round since early 2003 under the Texas SIP). 

 144 70 FR 39172 145 See, for example, the 5/09 ICAC White Paper, pp. 4-7, the Clean Air Interstate Rule webpage at 

http://www.epa.gov/airmarkets/progress/CAIR_09/CAIR09.html, and Clean Air Markets Progress Reports at 

http://www.epa.gov/airmarkets/progress/progress-reports.html. 
57 

The SCRs on these units were installed in 2003 to comply with stringent NOx limits under the 

Houston-Galveston-Brazoria Nonattainment area cap and trade program,146 contained in Texas 

Administrative Code, Rule 117.1210 and 117.1220. They all had trouble-free startups, passed 

their performance guarantees, but encountered unexpected ash deposition problems, which were 

subsequently resolved. They have operated year round successfully since, as required under the 

Texas SIP. In 2003, these retrofits were considered to be challenging, as there was no successful 

operating experience with the PRB coals these units burn. 

The units operate to maintain a system wide cap, rather than to meet unit by unit limits.147 

Texas allows the purchase of offsets, through an emissions-trading program, so that individual 

permit limits need not be continuously met. The Parish results may not, therefore, reflect the 

maximum capacity of the SCRs to reduce the plants’ NOx emissions.148 The Parish SCR 

acceptance tests indicate that they can operate at design levels, or 0.03 lb/MMBtu.149 This is 

evidenced by examination of an excerpt from the hourly NOx data for Parish Unit 8. As 

evidenced by Figure 3, which is an excerpt from Exhibit 2, the unit which typically operates at a 

30-day rolling average of about 0.044 lb/MMBtu, was run for extended periods at 0.03 

lb/MMBtu from August 5, 2006 to September 20, 2009 and then at 0.035 lb/MMBtu from 

September 21, 2006 to December 1, 2006 to demonstrate its capability. 

Figure 3 

Parish Unit 8 30 Day Rolling Averages 

1/30/11 through 6/14/07 

 146 Brett Butler and R.P. Gaikwad, Operating Experience of SCRs at Texas Genco’s Coal and Gas Fired Plants, 

Mega Symposium, 2004 (Attach. 41). 

147 30 Texas. Admin. C. § 1712.15. 148 30 Texas Admin. C. § 117.1220. 

149 Brett Butler and R.P. Gaikwad, Operating Experience of SCRs at Texas Genco’s Coal and Gas Fired Plants, 

Mega Symposium, 2004 (Attach. 41). 
58 

In other words, lower NOx emissions from the existing fleet of SCR-equipped units are 

achievable than are reflected by a simple examination of the CAMD data. This is evident in the 

Parish data, which commonly shows, for example, very low steady operation (when required to 

meet caps), followed by extended periods of operation at higher levels, when required reductions 

can be more cheaply obtained by purchasing credits. 

Again, although we believe that considering current technology, a NOx emission limit of 

0.05 lbs/MMBtu is achievable on a continuous basis for the units of SJGS, we expect that by the 

time SCRs are installed, significant additional progress in SCR technology will exist. The 

Coronado SCR installation, which will control NOx from a similar western bituminous coal, for 

example, will be on line before the SJGS SCR has been designed. The Electric Power Research 

Institute, for example, has projected a steady downward progression in achievable NOx 

emissions from SCR, from 0.04 to 0.05 lb/MMBtu in 2005, to 0.01 to 0.02 lb/MMBtu in 2025, 

as experience is gained with the fleet.150 

Comment: In addition to the units EPA erroneously claims to be capable of achieving 

0.05 lb/MMBtu, EPA also cites seven units that have accepted 0.05 lb/MMBtu or lower as an 

enforceable NOx emission limit. However, all of the units cited are brand new units – none of 

the units are more than five years old and all of them were designed to accommodate SCR from 

inception. In addition, five of the seven units are not yet operational, and thus have not yet 

demonstrated the ability to meet the NOx limit cited by EPA. 

 150 Coal Utilization Research Council (CURC)/Electric Power Research Institute (EPRI) Technology Roadmap 

Update, September 2006, subsequently updated: The CURC-EPRI Clean Coal Technology Roadmap, 2008, 

(Attach. 57). Available at: http://www.coal.org/userfiles/File/Final_CURC-EPRI_Roadmap,_2008.pdf. The units 

of lb/MWh in the 2008 version were converted into lb/MMBtu using the unit heat rates reported in 2/10 B&V NOx 

Compliance Report, Appx. A (ranging from 9,881 Btu/kWh for Units 4 and 5 to 10,908 Btu/kWh for Units 1-3). 
59 

Response: We agree with this comment that the seven permits cited are for new units 

that were designed to accommodate SCR from inception and only two are currently operational. 

However, Black & Veatch itself selected the BART limit of 0.07 lb/MMBtu based on a permit 

issued to a new unit in May 2007, when the initial BART determination was being drafted. 151 

The reliance on permits to establish BART is consistent with and anticipated by BART guidance. 

The BART Guidelines note: "... if there is a permit requiring the application of a certain 

technology or emission limit to be achieved for such technology, this usually is sufficient 

justification for you to assume the technical feasibility of that technology or emissions limit."152 

The BART Guidelines also require permitting agencies to “consider recent regulatory decisions . 

. . when identifying an emissions performance level” that can be achieved by available pollutionreduction methods.153 

Regardless, we present information elsewhere in our response to comments that 

demonstrates the ability of retrofitted units to meet a NOx emission limit of 0.05 lbs/MMBtu on 

a 30 boiler operating day average. 

Comment: A commenter states that while the proposed NOx limit of 0.05 lbs/MMBtu as 

BART for SJGS would significantly reduce NOx emissions from the SJGS and have a positive 

impact on visibility and public health, a lower NOx limit of 0.035 lbs/MMBtu is not only 

technically feasible, but legally-required for SJGS under the CAA. The commenter points to our 

proposal language that the State of New Mexico “noted the potential for greater control rates as 

low as 0.03 lbs/MMBtu” for SJGS. This commenter references our TSD for the proposed FIP, 

that SCR technologies “are routinely designed and have routinely achieved a NOx control 

efficiency of 90%.” Therefore, assuming a 90% removal efficiency, based on SJGS’s current 

rate of emissions (under 0.30 lbs/MMBtu), the commenter concludes modern SCR technology 

would bring controlled emissions down to 0.03 lbs/MMBtu. The commenter proposed an 

emission limit of 0.035 lbs/MMBtu, based on a report performed by its own contractor. This 

report includes vendor guarantees for 90% controls, and presents information that an emission 

limit of 0.035 lbs/MMBtu is being achieved at other units. The commenter further states that we 

must present specific circumstances to preclude the application of this emission limit. Lastly, the 

commenter makes a case that, the feasibility of a lower NOx emission limit aside, the additional 

costs associated with achieving such a limit, weighed against the additional mass of NOx that 

would be removed, make such a limit cost effective. 

Response: We have reviewed the information presented in the commenter’s contractor’s 

report. As we discuss elsewhere in our response to comments, we agree there are SCR retrofits 

that are meeting NOx emission limits below 0.05 lbs/MMBtu. Our analysis also indicates there 

 151 Email from Norem to Shepherd, 7/2/07 ("The SCR controlled NOx value of 0.07 lb/MBu was based on an 

information search of the BACT/LAER Clearinghouse. A very recent new permit (5/14/2007) issued by the State of 

Georgia to Longleaf Energy Associates (LS Power) shows a NOx limit of 0.07 lb/Mbtu for a 30-day rolling 

average.). Available at: 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/NMED_Ex7c_EmailThread_CostAnalysisAttached.pdf. This 

is confirmed by the 6/7/07 BART Analysis, Table 2-3, which cited the 0.07 lb/MMBtu in footnote(3) to the 

EPABACT/LAER Clearinghouse. 

152 70 FR 39165. 153 70 FR 39166. 
60 

are a few SCR retrofits that have demonstrated the ability to do this on the basis of a 30 day 

BOD average. The commenter’s contractor has presented monthly emission data for a number 

of units which appear to indicate that some are occasionally able to meet monthly emission limits 

below 0.05 lbs/MMBtu. The Havana 9 unit is particularly highlighted, which appears to indicate 

that unit has even met such a limit for perhaps 4-5 months at a time. However, in our view, we 

conclude this is not enough time to demonstrate that the units of the SJGS are able to meet a 

NOx limit of 0.035 lbs/MMBtu on the basis of a 30 day rolling average year round. 

We further agree that it may be technically feasible, considering both vendor 

performance guarantees, and the data discussed above, for some SCR retrofits to reliably meet an 

NOx limit of 0.035 lbs/MMBtu on a 30 day rolling average (especially if figured on the basis of 

a BOD). However, we see no data, presented either by the commenter or from our own 

research,154 which we have discussed elsewhere in our response to comments, which would lead 

us to conclude that such a limit has been sufficiently demonstrated in practice. 

To our knowledge, there are no air permits in the U.S. that require that a NOx emission 

limit of 0.035 lbs/MMBtu be met for a coal-fired unit such as SJGS with retrofitted SCRs on the 

basis of a 30 day rolling average. Furthermore, the existence of a permit limit is not the only 

indicator of the technical feasibility of achieving a particular emission limit. However, its 

absence, combined with no documented instance of an SCR retrofit achieving this level of 

control on a continuous basis, causes us to conclude that a 30 day rolling average NOx emission 

limit of 0.035 lbs/MMBtu for the units of the SJGS is not BART. 

Comment: The National Park Service (NPS) believes PNM has underestimated the 

ability of SCR to reduce emissions. For example, Black & Veatch assumed that SCR could 

achieve 0.05 lb/MMBtu (annual average) when evaluating retrofitting of SCR at the Craig power 

plant in Colorado. EPA's Clean Air Markets (CAM) data and vendor guarantees) show that SCR 

can typically meet 0.05 lb/MMBtu (or lower) on an annual average basis. We are including 2010 

CAM data (electronic Appendix A) that shows that SCR can achieve year-round emissions of 

0.05 lb/MMBtu or lower at 26 coal-fired EGUs, eleven of which are dry-bottom, wall-fired units 

like SJGS. Although SCR may be capable of even lower annual NOx emissions at SJGS, we 

will continue to assume 0.05 lb/MMBtu in our analyses to reflect our understanding of vendor 

guarantees. PNM has not provided any documentation or justification to support the higher 

values used in its analyses. We are also presenting information from industry sources that 

supports our understanding that SCR can achieve 90% reduction6 and reduce emissions to 0.05 

lb/MMBtu or lower on coal-fired boilers. For example, according to the Institute of Clean Air 

Companies white paper titled "Selective Catalytic Reduction (SCR) Control of NOx Emissions 

from Fossil Fuel-Fired Electric Power Plants" (published in May 2009), "By proper catalyst 

selection and system design, NOx removal efficiencies exceeding 90 percent may be achieved." 

And, according to the June 13, 2009 "Power" magazine article "Air Quality Compliance: Latest 

Costs for S02 and NOx Removal (effective coal clean-up has a higher-but known-price tag)" by 

Robert Peltier, " An excellent example of the significant investment many utilities have made 

over the past decade is American Electric Power (AEP), one of the largest public utilities in the 

U.S. with 39,000 MW of installed capacity with 69% of that capacity coal-fired. AEP is under a 

 154 Exhibit 2, 30 Day Rolling Averages for Selected Best Performing SCR Retrofit Installations. 
61 

New Source Review (NSR) consent decree signed in 2007 that requires the utility install air 

quality control systems to reduce NOx by 90%..." 

Comment: PNM proposed emission control technology consisting of Low-NOx burners 

(LNB) with overfire air (OFA) combined with Selective Catalytic Reduction (SCR) for Units 1-4 

with an annual average emission limit of 0.07 lb/MMBtu. However, the USFS feels that PNM 

has underestimated the achievable emission limit that would result with LNB/OFA +SCR. 

Based on data from EPA's Clean Air Markets, SCR usually meets an annual average emission 

limit of 0.05lb/MMBtu or lower. Based on the same data, 26 electric generating units have met 

this emission limit, eleven of which are similar in design as the SJGS. NOx emissions can be 

reduced by 90% with SCR installed at 0.05 lb/MMBtu emission limit. Given the SJGS’s size 

and amount of NOx emissions, a more stringent emission limit than PNM's proposal is not only 

achievable, but it will provide for greater reduction in NOx emissions. 

Response: We agree with the NPS that PNM has underestimated the ability of SCR to 

reduce emissions. As discussed elsewhere in our response to comments, we are requiring that 

the units of the SJGS meet an emission limit of 0.05 lbs/MMBtu on the basis of a 30 day rolling 

BOD average. 

Comment: PNM asks Region 6 to reconsider its assumption that SCRs would enable 

SJGS to achieve an emission rate of 0.05 lb/MMBtu because that emission limit would be 

unachievable on a continuous basis. PNM also asks Region 6 to reevaluate the cost effectiveness 

of SCRs at SJGS. By incorporating the incorrect assumption that SCRs at SJGS would achieve 

0.05 lb/MMBtu into her cost effectiveness calculations, Region 6’s consultant overestimated the 

emission reductions that the SCRs would achieve, thus underestimating the cost per ton of 

pollutant removed. In addition, since Region 6’s analysis overestimates the emission reductions 

associated with installing SCRs at SJGS, PNM also asks Region 6 to reevaluate the visibility 

improvement that it assumed the SCRs would provide. At an emission limit more appropriate 

for the retrofit context under consideration, the SCRs would not achieve nearly the level of 

visibility improvement that Region 6 expects. In short, Region 6’s incorrect assumption that 

SJGS could achieve 0.05 lb/MMBtu with SCRs skewed its entire cost-effective and visibility 

analysis. As a result, the Region’s proposed FIP is unachievable and it should be rejected. 

Response: As explained elsewhere in our response to comments, we believe the units of 

the SJGS can achieve a NOx emission limit of 0.05 lbs/MMBtu on the basis of a 30 day BOD 

average. Therefore, we do not believe there is any need to revise either the visibility modeling or 

the cost analysis on that basis. 

Comment: The USFS feels that PNM has underestimated the achievable emission limit 

that would result with Low-NOx burners with overfire air, combined with SCR. Based on data 

from EPA's Clean Air Markets, SCR usually meets an annual average emission limit of 0.05 

lbs/MMBtu or lower. Based on the same data, 26 electric generating units have met this 

emission limit, eleven of which are similar in design as the SJGS. NOx emissions can be 

reduced by 90% with SCR installed at 0.05 lbs/MMBtu emission limit. Given the SJGS’s size 

and amount of NOx emissions, a more stringent emission limit than PNM's proposal is not only 

achievable, but it will provide for greater reduction in NOx emissions. 
62 

Response: We agree with the USFS that PNM has underestimated the emissions 

reductions achievable with the addition of SCR. However, we draw a distinction between units 

that have met an emission limit of 0.05 lbs/MMBtu and those that have reliably demonstrated the 

ability to continuously meet that emission limit. Therefore, although we agree there are many 

SCR installations that are capable of meeting an annual NOx emission limit of 0.05 lbs/MMBtu, 

we extended our analysis. As we discuss elsewhere in our response to comments, we also 

analyzed the ability of some of the better controlled SCR retrofits to meet this same limit on a 30 

BOD average and found that it was feasible for the SJGS to do so. 

Comment: EPA proposes to require the SJGS to meet a NOx emission limit of 0.05 

lb/MMBtu individually at each of the plant's four units. EPA's own BART rules, however, 

expressly authorize application of BART emission limits on a plant wide basis, and the proposal 

offers no justification for deviating from that established and reasonable practice. See 70 Fed. 

Reg. at 39115 (indicating that it is appropriate "to allow sources to 'average' emissions across a 

set of BART-eligible emission units within a fence line, so long as the amount of emission 

reductions from each pollutant being controlled for BART would be at least equal to those 

reductions that would be obtained by simply controlling each unit"); id. at 39172 (same). 

Because it makes no difference, in terms of visibility impact or visibility improvement, as 

to which unit or units within a facility the emissions - or the emission reductions - occur at, there 

is no rational basis for the Agency to preclude the plant wide averaging that is contemplated in 

EPA’s own BART rules. Indeed, as noted above, the proposal makes no attempt to offer any 

justification for its refusal to allow plant wide averaging. Such a significant deviation from an 

established practice, a practice that is provided for by EPA rule, should at a minimum be subject 

to a demonstration that some substantial visibility benefit would result. No such benefit is 

afforded by this approach, and EPA must revise its proposal to remove this arbitrary constraint. 

Response: On July 6, 2005, we published the Guidelines for BART Determinations 

Under the Regional Haze Rule (‘‘BART Guidelines’’) to assist states in determining which of 

their sources should be subject to the BART requirements and in determining appropriate 

emission limits for each applicable source.155 Section 51.308(e)(1)(ii)(B) requires that BART 

determinations for fossil fuel-fired electric generating plants with a total generating capacity in 

excess of 750 megawatts, must be made according to the BART Guidelines. The commenter is 

correct in that the BART Guidelines (70 FR 39172) do state, “You should consider allowing 

sources to ‘‘average’’ emissions across any set of BART-eligible emission units within a 

fenceline, so long as the emission reductions from each pollutant being controlled for BART 

would be equal to those reductions that would be obtained by simply controlling each of the 

BART-eligible units that constitute BART-eligible source.” As the following discussion 

clarifies, we have concerns over the practical enforceability of a plant wide averaging scheme. 

We received another comment requesting that we abandon our proposed NOx BART 

limit, which was calculated on the basis of a rolling 30 day calendar average, in favor of a limit 

calculated on the basis of a rolling 30 day Boiler Operating Day (BOD) average. The definition 

we have adopted for BOD complies with the BART Guidelines, being, “any 24-hour period 

 155 70 FR 39104. 
63 

between 12:00 midnight and the following midnight during which any fuel is combusted.”156 A 

BOD averaging scheme has the effect of smoothing out the data peaks that occur due to boiler 

start up and shut down. As explained in our response to that comment, we intend to comply with 

that request. As a consequence of the BOD averaging scheme, days in which a unit is shut in for 

the full 24-hour period don’t count in calculating the 30 day average. Therefore, during periods 

when one or more of the four units of the SJGS are idled, the 30 days used in the average will be 

offset from that used by the units that are not idled. Once idled, a unit’s 30 days will continue to 

be offset from that used by the other units. In fact, under the BOD averaging scheme, it is likely 

after an initial period of time passes, that all four units will be using different 30 days of time in 

calculating their individual 30 day BOD averages. This adds an additional level of complexity to 

the calculation of a plant wide average. 

Just after the language appears in the BART Guidelines concerning a plant wide average, 

we advise, “In addition, emissions limits must be enforceable as a practical matter (contain 

appropriate averaging times, compliance verification procedures and recordkeeping 

requirements).” We believe it is possible to combine the 30 day BOD and plant wide averaging 

concepts, but due to our consent decree deadline, we do not have the time to construct the 

algorithm that could be used to guarantee enforceability. Therefore, as we discuss elsewhere in 

our response to comments, we will conditions the NOx limit for the units of the SJGS on the 

basis of a rolling 30 day BOD average. We leave the issue of a plant wide average to a possible 

future SIP revision that includes a verifiable, workable and enforceable algorithm that ensures 

the resulting emissions are equal to those reductions that would be obtained by simply 

controlling each of the BART-eligible units that constitute BART-eligible source. 

Comment: One commenter requested we exclude emissions occurring during startup, 

shutdown, and malfunctions events from having to comply with our proposed NOx limit of 0.05 

lbs/MMBtu because post-combustion controls equipment such as SCRs cannot operate 

effectively during those events. Alternatively, this commenter requested we consider setting a 

different standard that is more representative of the emission characteristics of the units during 

those events or consider requiring work practice standards to minimize such emissions. Another 

commenter requested that we specifically include startups and shutdowns in this language, 

making clear that any emission in excess of an applicable emission limit during any such event 

constitutes a violation of the applicable emission limit. That commenter also requested that we 

clarify that this provision applies to all pollutants controlled by this FIP, including, NOx, SO2, 

H2SO4, ammonia, and particulate matter (PM). 

Response: As we have discussed in our response to other comments, we are changing the 

rolling averaging period for our proposed NOx emission limit of 0.05 lbs/MMBtu from one 

based on 30 calendar days, to one based on a 30 BODs. The CEMS data indicate that our 

proposed NOx BART limit can be achieved without separately limiting startups, shutdowns, and 

malfunctions. Further, the startup, shutdown, and malfunction events cited in this comment are a 

characteristic of current SCR operating modes, i.e., under trading programs with no incentive to 

optimize design and operation to achieve a permit limit. These spikes result when flue gas 

temperatures fall below the operating temperature range of the SCR catalyst, or when the 

ammonia injection system malfunctions. We believe that startup and shutdown spikes are 

 156 70 FR 39172. 
64 

minimized by using the BOD metric, which we assume was why it was requested that we 

employ it. As there is no explicit provision for the exclusion of start up, shut down, or 

malfunction events for NOx, SO2, and H2SO4, all data will be used in determining compliance 

with this limit. As explained elsewhere in our response to comments, we are not setting an 

emission for PM for the units of the SJGS at this time, and we have determined that neither an 

ammonia limit, nor ammonia monitoring is warranted. We do not see a need to further clarify 

that the limits we are finalizing must be continuously met. 

We also agree with the comment that work practice standards should be developed and 

used to minimize such emissions. These should include proactive measures such as SCR reactor 

preheating during a cold start; selecting catalyst to maximize ramp rates and NOx reduction at 

low temperatures; and use of both tunable ammonia injection grids (AIGs) and static mixers. We 

encourage PNM to develop and employ those measures. 

Comment: Specific technical errors aside, the ultimate conclusions reached by Region 6 

are far different from those that have been made in other states in determining NOx BART for 

other electric generating units. Enclosed as Attachment A is a table of the other NOx BART 

determinations that have been made by 13 different states as they have developed the proposed 

regional haze SIPs that are awaiting EPA approval. In comparison to the determinations made 

by every other state, the Region 6 proposal concludes that SJGS must be required to install, (i) 

the most effective SCR in the nation, (ii) at the cheapest price, and (iii) in the shortest amount of 

time. These unrealistic expectations do not reflect the significant site-specific challenges SJGS 

must face to install SCR, particularly within the proposed 3-year deadline. 

First, the FIP is overly optimistic about the effectiveness of SCR retrofit technology – 

although newly constructed units may be capable of achieving 0.05 lb/MMBtu with SCR, an 

emission limit that stringent has never been imposed on a unit with a retrofit SCR by any state, 

as illustrated by the attached table. Second, SJGS will not be able to install SCR on all four units 

for the price calculated by Region 6 and its consultant, based on the cost estimates developed by 

other states. Third, SJGS will not be able to install all four SCRs in three years without 

significant additional costs, engineering, and construction feasibility challenges, and much more 

significant interruptions in operation of the plant. Taken together, these assumptions are 

unrealistic and undermine the Region’s cost-effectiveness calculation, particularly when 

compared to the results of the other BART determinations that have been made by the states for 

other electric generating units. The FIP proposed by Region 6 also includes a variety of 

measures never before considered relevant to a NOx BART determination in any other state, 

including the ammonia and sulfuric acid emission limits and the requirement to install a 

continuous emissions monitoring system for ammonia. 

The proposed FIP offers no explanation of how or why its conclusions appear to 

represent such a strident departure from the determinations reached by every other state. If the 

analysis undertaken by Region 6 with regard to SJGS is a true indication of EPA’s interpretation 

of the regional haze program, EPA will be faced with disapproving every other state regional 

haze implementation plan in the country and replacing those plans with FIPs. That approach 

would directly contradict the design of the visibility provisions of the Clean Air Act, which 

grants to the states significant discretion in choosing their own means of meeting the national 
65 

visibility goal. As part of these comments, PNM has provided a list of the other NOx BART 

determinations for electric generating units to demonstrate the stark contrast between Region 6’s 

approach and other states. PNM requests Region 6 take a more realistic look at its conclusions in 

light of this additional information and the additional technical information provided in the 

remainder of these comments. 

Another commenter asks whether the cost of retrofitting the SJGS with SCR is exorbitant 

or fair. The commenter also asks why the SJGS is being held to a higher standard or a more 

costly standard than other similar power plants. 

Response: As explained in our responses to other comments, we have made adjustments 

in our NOx BART determination for the SJGS that pertain to this comment. We have adjusted 

our cost basis for the installation of SCR on the units of the SJGS, which slightly increased the 

cost of the controls versus the tonnage of NOx removed. In addition, we have modified the 

schedule for compliance with the emission limits to now require compliance within 5 years – 

rather than 3 years -- from the effective date of our final rule. Also discussed in our responses to 

other comments, although we find that our proposed NOx BART emission limit should remain at 

0.05 lbs/MMBtu, we have modified the averaging time from a straight 30 day calendar rolling 

average, to a 30 day BOD average. 

We disagree with the statement that our conclusions regarding NOx BART for the SJGS 

are far different from those that have been made in other states in determining NOx BART for 

other electric generating units. As the commenter’s own table indicates, other states and EPA 

regions have made NOx BART determinations that will be met or are proposed to be met with 

the addition of SCR, including the Four Corners Power Plant (EPA Region 9), Hayden Units 1 & 

2 (CO), Otter Tail Big Stone 1 (although this is a cyclone boiler) (SD), and Naughton Unit 2. 

Also, we initially note two points regarding the costs of the controls, while accepting the 

values listed on the chart at face value. First, the cost effectiveness of all the BART controls, 

which depending on the facility range from combustion (e.g., OFA, LNB) to post combustion 

(e.g., SCR, SNCR), are frequently much worse (more expensive) than the cost effectiveness we 

calculated for SCR on the units of the SJGS. Second, the cost effectiveness values listed for 

SCR, are frequently similar to the cost effectiveness we calculated for SCR on the units of the 

SJGS (especially if compared to our revised cost effectiveness). 

Lastly, although we strive to ensure that the regulated community is treated equitably 

with regard to the RHR, the nature of the BART five factor analysis is designed to consider sitespecific issues. For instance, we note that the chart does not contain any information, nor is any 

presented elsewhere, concerning a visibility impact analysis. As required by the BART 

Guidelines, this must be included in a BART analysis.157 Without such an analysis, there is no 

way to justify any control even if it has a very low cost. Conversely, even controls that have 

either a relatively high capital cost or cost effectiveness in terms of dollars per ton may be 

justified if they result in a significant visibility benefit. In the case of the SJGS, our BART FIP 

NOx emission limit of 0.05 lbs/MMBtu is predicted to result in a combined visibility 

improvement on 16 Class I areas of 21.69 dv, which we consider very significant. 

 157 70 FR 39104, 39163. 
66 

C. Comments on our Proposed SO2 Emission Limit 

Comment: One commenter stated an SO2 emission rate of 0.15 lbs/MMBtu on a 30 day 

rolling average is not appropriate and does not ensure that SO2 emissions from SJGS will not 

interfere with visibility in New Mexico or other states. This commenter believes an SO2

emission rate of 0.15 lbs/MMBtu does not reflect the level of emissions reductions achievable 

under BART for wet limestone scrubbers. This commenter also points out that the units of the 

SJGS are all currently achieving SO2 limits significantly under 0.15 lbs/MMBtu on a 30 day 

rolling average and concludes we should not set SO2 emission rates in a Section 110 FIP that 

exceed the historic SO2 emission rates at SJGS. The commenter requests that if we do set a nonBART SO2 limit in our Section 110 FIP, we set unit-specific limits at least consistent with the 

recent historic SO2 emission identified in the table the commenter references, or issue formal 

SO2.BART determinations for each unit at SJGS under a Section 308 FIP. 

Response: We believe the SO2 emission rate of 0.15 lbs/MMBtu is appropriate to meet 

the requirements of section 110(a)(2)(D)(i)(II) to ensure that these emissions from SJGS will not 

interfere with visibility in other states. As discussed in our proposal, we believe that emissions 

reductions consistent with the assumptions used in the WRAP modeling will ensure that 

emissions from New Mexico sources do not interfere with the measures designed to protect 

visibility in other states. We are aware that the SO2 controls currently installed on the SJGS are 

in fact achieving greater control than would be evidenced by an emission limit of 0.15 

lbs/MMBtu. The commenter’s observation of the SJGS’s current SO2 emissions simply means 

that the SO2 emissions from the SJGS are better controlled than what we require to prevent 

interference with visibility under section 110(a)(2)(D)(i)(II). We agree with the commenter that 

the 0.15 lbs/MMBtu emission limit does not reflect the level of emissions reductions achievable 

through the use of a wet limestone scrubber and that a source specific BART determination for 

the SJGS might well result in a determination requiring the installation of scrubber to meet a 

more stringent limitation. We did not propose to address the BART requirements for SO2 from 

the SJGS in this action because SJGS will not be installing new control equipment to meet the 

0.15 lbs/MMBtu emission limits. As a result, the issue of requiring different capital expenditures 

to meet the requirements of section 110(a)(2)(D)(i)(II) as compared to those of the RH program’s 

BART requirement does not arise. Since we did not propose the S02 emission rate under the 

RHR requirements, the comments concerning BART are outside the scope of this action. 

Comment: In declining to find that its asserted SO2 limits satisfy BART, EPA’s proposal 

improperly relies on a RH trading program under 40 CFR 51.309 that does not yet exist. Putting 

aside EPA’s legal obligation to make a formal BART determination in its proposed FIP at this 

time, any emissions trading program that is proposed to replace a BART limit “must achieve 

greater reasonable progress than would be achieved through the installation and operation of 

BART.” 40 CFR 51.308(e)(2). Because EPA cannot make the required demonstration that New 

Mexico’s future, theoretical trading program will be “better than BART,” EPA is illegally 

sidestepping its current BART obligations under 40 CFR 51.308 (e)(2)(i). 

Response: We disagree with the commenter. In accordance with our proposal, we are 

finalizing SO2 limitations under section 110(a)(2)(D)(i)(II), not under the RHR. We disagree 
67 

with commenter’s view that we are sidestepping our BART obligations by not proposing to 

establish SO2 BART emission limits. Our rationale for not proposing BART requirements for 

SO2 in this action appears in our response just prior to this comment. Moreover, we note that the 

established SO2 limits do not rely upon a nonexistent trading program. We will address New 

Mexico’s obligation to address SO2 under the RHR in a future separate action. 

D. Comments on our Proposed H2SO4 and Ammonia Emission Limits and other Pollutants 

Comment: The League of Women Voters, Montezuma County, Colorado supports the 

EPA determination that SCR is cost-effective for all units of the SJGS. They defer to our 

judgment on the proposed final limit for sulfuric acid emissions. They request that we choose 

the lower limit of 2 ppmvd, adjusted to 6 percent oxygen for the regulation of ammonia 

emissions. Their justification for this request is the deterioration in visibility at Class I areas 

such as Mesa Verde National Park, and the imperative to achieve improvements in visibility as 

rapidly as possible. 

Response: We appreciate the support of the League of Women Voters, Montezuma 

County, Colorado. As explained elsewhere, we have determined that neither an ammonia limit, 

nor ammonia monitoring is warranted. 

Comment: One commenter stated the same pollutants, including PM 2.5, NOx, and 

VOCs (contributing to ground level ozone) that contribute to visibility impairment also harm 

public health. This commenter also noted that ozone concentrations in parks in the Four Corners 

region approach the current health standards, and likely violate anticipated lower standards. In 

fact, ozone levels in many parts of New Mexico, Colorado, and Utah are already in the range of 

ozone levels deemed to be harmful to human health. 

Response: We agree that the same pollutants that contribute to visibility impairment can 

also harm public health. Although we note public health benefits, we did not rely on these 

benefits in establishing controls necessary to meet BART in today’s action. 

Comment: For the reasons stated in EPA’s proposed rule, we also fully support EPA 

setting emission limits for H2SO4 and ammonia at the SJGS, and the corresponding installation 

of CEMs to accurately document the continuous emission rate of these pollutants. We also 

request that EPA set BART emission limits for PM at SJGS in the final rule or as part of a 

regional haze FIP under section 308. With regard to H2SO4, we support EPA’s determination to 

set emission limits. We urge EPA to set the emission rate at the lowest rate of 1.06 x 10-

4lb/MMBtu for each unit at the SJGS. We agree that this rate is supportable based on use of low 

reactivity catalyst and the most current information from the Electric Power Research Institute 

(“EPRI”). If continuous emission monitors are truly unavailable for this pollutant, we also urge 

EPA to require stack test monitoring for H2SO4 on a more frequent basis than annual monitoring. 

EPA should clarify in this final rule that the emission limit being set is being required under the 

regional haze program as part of a BART determination for the facility and must be complied 

with within 3 years of the date of the final rule. If EPA does not set BART limits in the final 

rule, it should conduct a BART analysis for H2SO4 in a Section 308 FIP. With regard to 

ammonia, we also support EPA setting the lowest emission rate considered at the SJGS. NH3 
68 

emissions are important in that they react with SO2 and NOx to form ammonium sulfate and 

ammonium nitrate particles, which are very effective in impairing visibility. Thus, we support 

EPA setting the ammonia emission limit at the lower range of 2.0 parts per million. We also 

support requiring installation of CEMs to monitor this pollutant. If EPA does not set BART 

limits in the final rule, it should conduct a BART analysis for ammonia in a Section 308 FIP. 

With regard to PM, EPA did not set any emission limits in the proposed rule. We urge EPA to 

set BART emission limits for PM at SJGS either in the final rule, or as part of a regional haze 

FIP under section 308. PM is an important visibility impairing pollutant that must be controlled 

at the SGJS. Based on the reasoning and analysis in the November 20, 2009 comments 

submitted by the National Park Service for the Four Corners power plant BART determination, 

we urge EPA to likewise set a PM limit of 0.012 lb/MMBtu on a 6-hour block average, 

applicable to each unit individually, with compliance determined by PM CEMS. This limit is 

also supported by a 2008 report submitted by ENSR for the Four Corners BART determination. 

We also urge EPA to follow the lead of Region 9 for the Four Corners power plant PM BART 

determination by setting a 10% opacity limit at each unit at SJGS to control PM emissions. 

Compliance with PM emission limit should likewise be required within three years of the final 

rule. 

Another commenter questioned our authority to regulate ammonia through the RH rule. 

Response: In our response to comments on the assumed ammonia slip level used to 

estimate sulfuric acid emissions, we have recalculated the expected sulfuric acid emissions rate 

with no ammonia slip. The sulfuric acid emission rate was recalculated to be 2.6 X10-4

lb/MMBtu based on an ammonia slip value of 0 ppm, compared to our original value of 1.06 

X10-4 lb/MMBtu at 2ppm ammonia slip. The actual ammonia slip will vary over the life of a 

catalyst layer. We conclude an assumption of ammonia slip up to 2.0 ppm as the catalyst ages is 

reasonable for an SCR system that is designed to achieve a NOx emission limit of 0.05 

lbs/MMBtu on a rolling 30 BOD basis, considering the coal the SJGS burns. We also note PNM 

assumed an ammonia slip of 2.0 ppm in its SCR cost estimation. As the ammonia slip increases, 

the sulfuric acid emissions will decrease. This revised sulfuric acid emission rate remains 

significantly lower than that estimated by NMED and is a minimal level of sulfuric acid 

emissions. Based on these updated calculations and in response to comments, we are requiring 

the SJGS to meet an H2SO4 emission limit of 2.6 X10-4 lb/MMBtu. 

Our intention in our proposal regarding the regulation and monitoring of ammonia was, 

like H2SO4, to minimize the contribution of this compound to visibility impairment. After 

careful consideration of the comments we received concerning our proposal to require the SJGS 

to meet an hourly average emission limit of 2.0 parts ppmvd for ammonia, we have determined 

that neither an ammonia limit, nor ammonia monitoring is appropriate. Instead, we will 

approach the issue of the impact of ammonia slip on visibility impairment though proper upfront 

design, rather than after-the-fact regulation. We are requiring that the NOx control device 

(presumably, but not required to be SCR) must be designed to achieve a NOx emission limit of 

0.05 lbs/MMBtu on a rolling 30 BOD basis with an ammonia slip of 2.0 ppm. We believe this 

strikes the proper balance between the additional cost of ammonia monitoring and reporting and 

the need to have a reasonable expectation of the amount of ammonia emitted by the SJGS. 
69 

The H2SO4 emission limit is being required under the RH program as part of a BART 

determination for the SJGS and must be complied with at the same time as the NOx limits for 

each unit. With regard to the commenter’s request that if emission monitors are truly unavailable 

for this pollutant, we should require stack test monitoring for H2SO4 on a more frequent basis 

than annual monitoring, we do not believe that an adequate continuous emissions monitor is 

available for H2SO4 and will continue to rely on stack testing. We do not agree that more 

frequent stack testing is appropriate, due to a consideration of the cost of that testing in 

comparison to the value of having a greater certainty of the H2SO4 emissions that may result. As 

we discussed in our proposal158, we have concluded that the low sulfur coal burned at the SJGS 

generates very little sulfur trioxide (SO3), and hence H2SO4, which is formed when SO3 

combines with water in the flue gas to form H2SO4. In addition, SCR catalysts are available with 

a low SO2 to SO3 conversion of 0.5%, further limiting the production of H2SO4. Therefore, we 

conclude we have struck the right balance. 

 

E. Comments on the Emission Limit Compliance Schedule 

Comment: The League of Women Voters, Montezuma County, Colorado opposed 

extending the proposed three year deadline to a period of five years for achieving the proposed 

emission limits. They stated SCR was first patented in the U .S. in 1957 and has been an 

operational pollution control technology for over 30 years at large scale facilities like the SJGS. 

They believe allowing an extra two years may provide the opportunity for ambiguity and 

technological changes to enter into arguments about engineering solutions and controls, which 

potentially could feed appeals and litigation by the operator of the SJGS, and thus delay cleanup 

efforts. The operators of the SJGS have had several decades of largely unrestricted air -shed use 

with essentially no controls on regional haze 

The Navajo Nation expressed concern that the proposed compliance schedule is too 

stringent for SJGS to reasonably meet and could result in a reduction-in-force of a significant 

number of employees, including Navajo workers, thereby contributing to family hardships and 

limiting the ability of affected employees, contractors, and subcontractors to meet their financial 

obligations. 

Another commenter asked if there is a smarter way to phase the installation of controls 

over a longer period of time. This commenter expressed concern that regulations are moving 

way too fast with businesses and residents of San Juan County, who are ultimately facing the 

cost of the impacts. 

Another commenter stated any proposed truncation of the five-year compliance period 

should be persuasively justified by a specific analysis of the feasibility and cost-effectiveness of 

such a schedule in light of the circumstances at the facility in question. No such justification, the 

commenter argued, appears in the proposed rule. The proposal simply asserts that a three year 

compliance deadline would be applicable because similar compliance schedules have been met at 

some other facilities, according to EPA. 

 158 76 FR 499. 
70 

Another commenter stated that a compliance deadline of three years will result in 

significant additional costs that we did not account for in our analysis, compounding the errors 

made in its unrealistic cost analysis. They stated the proposed FIP attempts to justify a threeyear compliance deadline by citing two studies, but those studies do not reflect a realistic 

schedule for installing SCRs at SJGS. This commenter made several points: first, Region 6 cites 

to the installation timelines provided in a whitepaper prepared in 2002 by the Institute of Clean 

Air Companies (ICAC) entitled “Typical Installation Timelines for NOx Emissions Control 

Technologies on Industrial Sources.” As stated in the paper’s introduction, “[t]he information 

below can be used as a general guide for the typical time required to complete a typical NOx 

control project....” However, as explained throughout these comments, the installation of SCRs 

at SJGS would be anything but typical. In addition, the ICAC study cited by Region 6 only 

addresses SCR installations for industrial applications, not electric utility coal-fired boilers, 

which are much larger, and therefore, require significantly more time to build. The second 

reference is a document prepared for the U.S. EPA Office of Research and Development in 

October 2002, titled “Engineering and Economic Factors Affecting the Installation of Control 

Technologies for Multipollutant Strategies.” The introduction notes that “projections beyond 

2010 are of limited value as market conditions could change significantly between now and 

2010....” Thus, by its own terms, the 2002 document should be considered to be of “limited 

value” at this point in time, particularly given the tumultuous market conditions in recent years. 

The commenter then cites another report it believes is more representative, which it alleges we 

neglected to consider, which is the recently published “Implementation Schedule for Selective 

Catalytic Reduction (SCR) and Flue Gas Desulfurization (FGD) Process Equipment” October 1, 

2010, prepared by J. Edward Cichanowicz for the Utility Air Regulatory Group. The report is 

based on a review of numerous FGD, SCR, and LNB retrofits actually completed at coal-fired 

power plants during the last ten years. Particularly relevant is Section 4.1.2 of that report, which 

discusses several examples of multiple SCRs installed at a single location. The commenter 

presents a chart which it states demonstrates multiple SCR system installations took between 31 

and 62 months, depending upon site-specific factors. The commenter concludes that the site 

congestion and other site-specific challenges at SJGS will demand an implementation schedule 

that is similar to SCR installations at Units 6 and 7 of First Energy’s Sammis facility, which 

required 60 and 62 months to complete, respectively. 

Another commenter stated that a compliance deadline of three years will result in 

significant additional costs that we did not account for in our analysis. They stated the proposed 

FIP attempts to justify a three-year compliance deadline by citing two studies, but those studies 

do not reflect a realistic schedule for installing SCRs at SJGS. This commenter made several 

points concerning two studies on SCR timelines we cited in our proposal that the commenter 

feels call our use of the information into question. The commenter then cites another report it 

believes is more representative and concludes the site congestion and other site-specific 

challenges at SJGS will demand an implementation schedule that is similar to SCR installations 

at Units 6 and 7 of First Energy’s Sammis facility, which required 60 and 62 months to 

complete, respectively. 

Response: We have decided, based on our review of several comments, to finalize a 

schedule for compliance with the emission limits of 5 years – rather than 3 years – from the 

effective date of our final rule. We view the Black & Veatch cost analysis as being a very 
71 

preliminary, low-level estimate, that is missing much of the information required to develop a 

site-specific schedule. This estimate does not include, for example, plot plans, a diagram 

showing SCR layout, an analysis of constructability, construction site plan, or an implementation 

schedule, which are required to develop a site-specific schedule. Thus, we selected an average 

compliance time, based on a review of a number of sources, including the following: 

• 13 months for 675 MW Somerset Station; 159 

• 18 month for Harding Street, which was used to cost the SJGS catalyst;160 

• 19 months for two 900 MW units at Keystone. 161 

• 26 months for Asheville Power Station with a reported normal range of 27 to 30 

months.162

• 30 months for 4 units based on 21 months typical for 1 unit, each additional unit at same 

facility adds 2-3 months.163 

• 36 months for St John River Power Park, from contract award to startup. This facility 

was used to estimate most of the SJGS SCR costs.164

• 42 months for 14 SCRs installed to comply with the Texas Nonattainment SIP.165 

• 60 months estimated by Black & Veatch for 5 units at Four Corners.166

• 69 months estimated by Sargent & Lundy for 3 units at Navajo.167

 The median of these estimates is 33 months and the average is 37 months. The 

UARG (Utility Air Regulatory Group) report cited in this comment was published around the 

 159 ClearSkies: http://www.epa.gov/clearskies/03technical_package_sectiong.pdf. See also: Walter Nischt and 

others, Update of Selective Catalytic Reduction Retrofit on a 675 MW Boiler at AES Somerset, ASME International 

Joint Power Generation Conference, July 24-25, 2000, Available at: http://www.babcock.com/library/pdf/br1703.pdf. 

160 Black & Veatch Brochure, Building a World of Difference, Available at: B&V Brochure, 

http://www.bv.com/Downloads/Resources/Brochures/rsrc_ENR_CoalSelectiveCatalyticReduction.pdf. 161 ClearSkies: http://www.epa.gov/clearskies/03technical_package_sectiong.pdf. 162 Case Histories: Asheville Power Station's Retrofit First to Meet North Carolina's Clean Smokestacks Act. 163 ClearSkies: http://www.epa.gov/clearskies/03technical_package_sectiong.pdf. 164 http://www.bv.com/wcm/press_release/05312006_5169.aspx. This press release indicates B&V was awarded the 

contract for SJRPP in May 2006 and at that time, projected the SCR would be on line in May 2008. The CEMS data 

reported to CAMD indicates startup of the SCR on Unit 1 occurred June 1, 2009 and of Unit 2 on February 1, 2009. 

Thus, it took 36 months to design, build, and commission the two SJRPP SCRs, which served as the basis for the 

San Juan cost estimates. 

165 J.A. Hines and others, Reliant Energy SCR Construction Implementation Plan, ICAC Forum '02: Cutting NOx, 

February 12-13, 2002, Available at: http://www.babcock.com/library/pdf/BR-1728.pdf 166 2/10 B&V Four Corners NOx Compliance Report, Appendix F. 167 8/17/10 S&L Navajo Cost Analysis, Appendix G. 
72 

same time (October 1, 2010) that we did most of our SCR analysis and was unknown to us at that 

time. PNM and Black & Veatch did not identify this report in discussions with us in October - 

November 2010. The UARG report confirms the information we found through independent 

investigation, summarized above. The UARG report indicates that it took 28 to 62 months to 

design and install the 14 SCRs in its sample (compared to 18 - 69 months for the 9 facilities 

(greater than 33 units) in our sample). The average design/build time for the units in the UARG 

report is 43 months, compared to an average of 37 months for the Region's retrofit SCRs. None 

of the units in these two collections overlap. We agree, based on our site visit, that site 

congestion will require a longer total installation time for all four units than the average found in 

both of these collections. 

However, we do not believe there is basis in the record for concluding that installation of 

SCRs would require a timeframe as long as claimed for Sammis Units 6 and 7. The seven 

Sammis units were subject to an enforcement action,168 and the SCRs were installed pursuant to 

a Consent Decree.169 The Consent Decree allowed 5+ years, from the date of the Decree in 

March 2005, to install SCR on two units, SNCR on five units, low NOx burners, and new 

scrubbers on seven units. The Consent Decree schedule was beat, however, and all of the 

controls were operating by May 2010. 

The Sammis retrofit project at this 2,200 MW plant is generally recognized as the largest 

air quality control retrofit in the history of the United States and is considered to be "the most 

difficult in the country because of the extremely limited space for installation of the new air 

emission control equipment and systems."170 This project involved 1,400 workers; 5 million 

hours of labor; 9,000 feet of new duct work; 480,000 lineal feet of support pilling; 52,400 cubic 

yards of concrete; 15,000 tons of structural steel; and 580 miles of electrical cable.171 Significant 

duct modifications were required to route the flue gas from the seven boilers through three 

scrubbers as well as balance of plant modifications.172 Thus, significant additional work was 

underway at the same time that the SCRs were being designed and installed. 173 This project is 

not comparable to SCR retrofits at SJGS. Compare photographs in Figure 4 and elsewhere174

 168 U.S., et al., v. Ohio Edison Company, et al., Opinion and Order, Case No. 2:99-CV-1181, In the U.S. District 

Court for the Southern District of Ohio, Eastern Division, Available at: http://www.4cleanair.org/OhioEdison.pdf. 

169 U.S. et al. v. Ohio Edison and Pennsylvania Power Company, Consent Decree, March 18, 2005, Available at: 

http://www.epa.gov/compliance/resources/decrees/civil/caa/ohioedison-cd.pdf. 170 Michael D. McElwain, Sammis Energy Plant Project Wins Award, Herald-Star, December 13, 2010. Available 

at: http://www.hsconnect.com/page/content.detail/id/552039/Sammis-energy-plant-project-winsaward.html?nav=5010. 

171 Linda J. Hutchinson, W.H. Sammis Plant in Ohio Being Retro-Fitted to Scrub Air Pollutants, Construction 

Equipment Guide, October 17, 2009, Available at: http://www.constructionequipmentguide.com/WH-SammisPlant-in-Ohio-Being-Retro-Fitted-to-Scrub-Air-of-Pollutants/13485/. 172 Brian Wheeler, Retrofitting Air Handling Equipment at W.H. Sammis, Power-Gen Worldwide, April 1, 2011 

("Sammis was an extensive and complex retrofit for emissions control, including substantial air handling and 

ductwork modifications."), Available at: 

http://www.gslb.powergenworldwide.com/index/display/articledisplay/6243020871/articles/powerengineering/volume-115/issue-4/features/retrofitting-air-handling-equipment-at-w-h-sammis.html 173 Anthony J. Alexander, Bank of America/Merrill Lynch 2010 Power & Gas Leaders Conference, Available at: 

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deck constructed over four lanes of Ohio State Route 7, due to the extreme site congestion.179 

Existing facilities are located to the north and south of the plant. Photographs of these units and 

engineering analyses indicate Sammis Units 6 and 7 are more congested than the SJGS units.180 

We proposed a compliance schedule of 3 years and solicited comments on alternative 

timeframes up to 5 years.181 The BART Guidelines require documentation of any "unusual 

circumstances" that would affect cost effectiveness, such as the implementation schedule.182 We 

do not believe the record in this case contains an estimate of SCR installation time, any of the 

information required to develop a site-specific schedule, nor any demonstration that it would take 

longer than an average SCR. 

Based on an examination of site conditions and available data on historical SCR 

installation timeframes as described above, we find that a change to our proposed compliance 

schedule is appropriate. We believe that a longer time frame than the median time frame for 

construction identified in our survey of SCR retrofits is justified due to site congestion. We do 

not believe a timeframe as long as that allowed for the Sammis units is warranted, nor is it 

allowed by the RHR. Consequently, we are finalizing a schedule which requires compliance 

with the emission limits within 5 years – rather than 3 years -- from the effective date of our final 

rule. 

Comment: A commenter objected to the proposed compliance schedule of 3 years and 

was concerned that SCR installations often trigger PSD permitting requirements because they 

constitute physical changes to an existing emission unit that may result in increased emissions of 

sulfuric acid mist. The commenter stated that obtaining a PSD permit for an SCR can take up to 

18 months or more and even if the SCRs do not trigger PSD permitting requirements projects 

could still trigger state permitting requirements, which can require several months to satisfy. The 

commenter further stated that the installation of an SCR will involve a significant capital 

expenditure that will require approval from the New Mexico Public Regulation Commission. 

The commenter alleged that we failed to take these requirements into account resulting in an 

unachievable deadline for compliance. 

Response: As stated elsewhere in our response to comments, we have modified the 

compliance schedule. We are finalizing a schedule which requires compliance with the emission 

limits within 5 years – rather than 3 years -- from the effective date of our final rule. We 

conclude this is adequate time for the inclusion of any possible permitting requirements. 

Comment: A commenter stated that our compliance schedule of three years from the 

effective date of our final rule did not allow time for competitive bidding. To meet a three-year 

schedule, the commenter argued, PNM would have to simply offer the work to a single vendor, 

eliminating the opportunity to identify other qualified vendors or provide any incentive to 

 179 See photograph in Wikipedia article at: http://en.wikipedia.org/wiki/W._H._Sammis_Power_Plant. 180 See, e.g., Coal-Fired Plants in Ohio, Available at: http://www.4cleanair.org/OhioEdison.pdf; Hans Hartenstein, 

Control Technologies for the W.H. Sammis Plant, Stratton, Ohio, Expert Report on Behalf of the United State, New 

York, New Jersey, and Connecticut, October 2003, Sec. 7.9; Brian Wheeler, Retrofitting Air Handling Equipment at 

W.H. Sammis, Power-Gen Worldwide, April 1, 2011. 

181 76 FR 504. 182 70 FR 128 p. 39168. 
76 

encourage competitive pricing. Therefore, the failure to account for this renders the three-year 

compliance date unrealistic, and calls into question the underlying cost estimates, which are 

based on contracts entered into by other utilities that most likely were allowed sufficient time to 

complete a proper competitive bidding process. 

Response: We believe this comment is incorrect. The 3 year schedule we proposed did 

include time to prequalify bidders. However, as stated elsewhere in our response to comments, 

we have extended the compliance schedule to 5 years. 

Comment: The cost estimate prepared by EPA for its FIP does not appear to account for 

the need to have two units offline at the same time to install the SCRs, but PNM would not be 

able to meet a three‐year deadline for compliance without taking two units offline at once. A 

project of this magnitude (estimated to be over $900 million for the entire plant) would typically 

require 12 to 18 months of engineering and vendor procurement. Then catalysts need to be 

ordered and manufactured, and finally, the construction on each unit needs to take place during 

an outage. By comparison, the recent environmental upgrades at SJGS were phased in over five 

years. In addition, a three‐year deadline would likely eliminate the ability of PNM to plan the 

outages for off‐peak seasons, when the demand for power and the cost for replacement power are 

lower. In contrast to a five‐year compliance period, the three‐year period would require PNM to 

prefabricate as much of the SCRs as possible, which would require extremely large 

pre‐fabrication yards and prefabrication crews. Due to the physical layout of the site and units, 

independent, simultaneous fabrication and installation activities would also be required. In 

addition, a three‐year deadline would also require significant overtime hours, expedited material 

costs, double “heavy long‐lift” crane costs, and a larger construction workforce overall. Because 

these costs would never be incurred in the normal course of installing SCRs, PNM indicates they 

did not include these costs in its analysis, but they would be unavoidable in the event a three‐year 

deadline is required. Such a short construction deadline would also exacerbate the shortage of 

skilled labor caused by the significant number of similar projects that are either ongoing or 

planned for the near future in the region. In addition, installation of SCR could trigger air 

permitting requirements and the need for approval from the Arizona Corporation Commission. 

These pre-construction activities could add 18 months to two years (if a Prevention of Significant 

Deterioration [PSD] permit is required) to the construction schedule. During those outages the 

SJGS’s owners may be required to purchase electricity, at higher prices than the electricity 

produced at SJGS, from the open market for at least some of the energy that would have been 

produced by SJGS. Those higher costs, along with the increased capital cost mentioned 

previously, will ultimately be borne by customers, further exacerbating our customers and the 

community's economic woes. Further, such outages could place a significant strain on our other 

generating assets, which could affect service reliability to customers. EPA Region 6 should 

consider these costs and constraints in its setting a three‐ to five‐year, compliance schedule, 

which does not appear to allow sufficient time for permitting, engineering, and construction of 

the controls, without significantly increasing the costs associated with the installation of SCRs at 

SJGS. Therefore, EPA should set the deadline for compliance to the five years allowed by law, 

or even longer of [sic] PNM is required to respond with a “Better than BART Alternative.” 

Response: As stated elsewhere in our response to comments, we have modified the 

compliance schedule. We find that compliance with the emission limits must be within 5 years 
77 

of the effective date of our final rule. A longer schedule will allow PNM to tie in the SCRs 

during routinely scheduled maintenance outages and to plan outages for off-peak seasons. We 

have not received any request from PNM that we consider a “better than BART alternative.”

F. Comments on the Conversion of the SJGS to a Coal-to-Liquids Plant with Carbon 

Capture as a Means of Satisfying BART 

Comment: We received a comment encouraging us to consider coal-to-liquids (CTL) 

technology with integrated power generation as an option in determining BART for SJGS. The 

commenter states that our BART determination proposal would reduce NOx emissions, but 

would do little to reduce SOx or carbon dioxide (CO2) emissions, leaving SJGS far from 

compliance with new or future standards. The commenter states our BART proposal could cost 

$750 million or more (based on PNM’s figures), and would have an adverse effect on the cost of 

electricity. Based on 2006-generation numbers of 12.5 million MWh’s, amortized over a 20-year 

period at 8% interest, and a $750 million modification price, the commenter calculates the cost 

of electricity would increase by approximately $6 per MWh or 0.6 cents per kWh. 

The commenter states that although natural gas fired combined cycle and integrated 

gasification combined cycle have merit, no option offers more benefits than a CTL plant with 

integrated power generation. According to the commenter, the synthetic fuels produced are 

drop-in replacements for diesel and jet fuel, and contain virtually no sulfur. The US military has 

conducted extensive tests on these fuels, and finds that they produce far lower emissions than 

conventional petroleum-based fuels. 

According to the commenter, the conversion of the SJGS into a CTL plant with 

integrated power generation would retain jobs in the mining and plant operations, will create 

ultra-clean biodegradable synthetic fuels in the CTL process, and will use the waste heat and 

byproduct gases from the process to cogenerate electric power. The commenter states that 

emissions of criteria pollutants from the CTL plant manufactured by his company approach those 

of a NGCC plant and emissions of CO2 are half those of a NGCC plant. The commenter 

calculates that a 50,000 barrel per day CTL plant can co-produces 1200 MW of clean, efficient, 

low carbon power. This would be baseload generation, the commenter argues, that would be 

produced 24/7 and could be sold into the California marketplace. The size of the facility could 

be scaled to meet greater energy needs. The commenter states a plant of this size would 

consume approximately 30,000 tons per day of coal, which is nominally twice as much coal as is 

currently consumed, so more jobs will be needed at the mine. 

According to the commenter, NOx emissions would be reduced by 50 to 1, SOx 

emissions would be reduced by 20 to 1, and CO2 emissions would be reduced by 5 to 1. The 

commenter points out that KinderMorgan has an existing CO2 pipeline in the vicinity. The CO2 

from the plant could be sold to KinderMorgan and used for enhanced oil recovery. The 

commenter also notes that ash in the coal is melted in the gasification process, and can be used as 

an aggregate for paving roadways. In addition, the sulfur from the process can be collected as 

elemental sulfur, and sold as a byproduct. Water consumption would be reduced by about 1⁄2 in 

comparison to a conventional power plant of the same MW output, due to the use of a hybrid 

cooling system (air-cooled condenser in conjunction with a cooling tower). 
78 

A plant of this scale, according to the commenter, would cost approximately $8 billion to 

construct, assuming all new equipment. However, this cost could be substantially reduced by reutilization of much of the plant, including coal handling equipment, steam turbines, condensers, 

cooling towers, and transmission lines. The re-utilization of existing equipment could reduce the 

capital cost by an estimated 25 to 35% as compared to a totally new facility. The commenter 

suggests this could be a BART (retrofit) solution. The commenter argues the revenues from this 

plant would provide a return on investment that exceeds all other considered options by a wide 

margin. The commenter encourages us to consider conversion to a CTL plant with integrated 

power generation to be BART for SJGS. 

Response: We appreciate the commenter’s suggestion that we consider CTL technology 

with integrated power generation as an option in determining NOx BART for the SJGS. 

Although we encourage PNM and the other owners of the SJGS, and the Navajo Nation to 

examine this concept in detail, we cannot consider it as a potential NOx BART technology as it 

would involve a complete redesign of the plant. We note the BART guidelines state that “[w]e 

do not consider BART as a requirement to redesign the source when considering available 

control alternatives.” 

We agree with the commenter that the NOx BART determination in our proposal would 

reduce NOx emissions, yet would do little to reduce SO2 and CO2 emissions from the SJGS. 

SO2 emissions under the RHR are covered by the New Mexico submittal, which we received on 

July 5, 2011. We will address the adequacy of that submission in a future action. As discussed 

in our proposal, we disagree with PNM’s cost estimate for installing SCR on the four units of the 

SJGS. Although PNM estimated the total cost to be in excess of $900 million, we estimated that 

cost to be approximately $250 million. As discussed elsewhere in our response to comments, in 

light of information provided by commenters, we have refined our estimate to be $344,542,604. 

We note that this estimate, being about one-third that of PNM’s, will result in significantly lower 

costs being passed on to rate payers than what has been estimated by PNM. 

G. Comments on Health and Ecosystem Benefits, and other Pollutants 

Comment: We received several comments regarding the negative effects current 

emissions from the SJGS have on human health and ecosystems. Several conservation 

organizations jointly submitted a comment letter pointing out that the same pollutants that 

contribute to visibility impairment also harm public health and have negative ecosystem impacts. 

They note that these same pollutants also harm terrestrial and aquatic plants and animals, soil 

health, and moving and stationary bodies of water by contributing to acid rain, ozone formation, 

and nitrogen deposition. Another commenter, a retired pediatrician, notes that NOx as a 

precursor to ozone, causes numerous respiratory problems and adversely affects children in 

particular; he supports our action. Another commenter urges us to take into consideration the 

health impacts of toxic emissions from the SJGS. Two commenters state there are high levels of 

mercury pollution originating from the SJGS. A commenter also points out that nitrous oxide 

(N2O) is a greenhouse gas (GHG) that contributes to climate change. According to the 

commenter, PNM has accumulated many air quality violations, and no amount of money is 

worth the poisoning of our air, water, and soil. Another commenter points out that a recent study 
79 

of the 2010 health impacts of the SJGS estimated 33 deaths, 50 heart attacks, 600 asthma attacks, 

and over 30 hospital admissions, resulting in an estimated $255 million in health care costs in 

2010. A commenter also expresses concern that if EPA lowers the ozone standard in 2011, La 

Plata County, CO, would not be attaining the standard. 

 

Response: We appreciate the commenters’ concerns regarding the negative health 

impacts of emissions from the SJGS. We agree that the same PM2.5 emissions that cause 

visibility impairment can be inhaled deep into lungs, which can cause respiratory problems, 

decreased lung function, aggravated asthma, bronchitis, and premature death. We also agree that 

the same NOx emissions that cause visibility impairment also contribute to the formation of 

ground-level ozone, which has been linked with respiratory problems, aggravated asthma, and 

even permanent lung damage. We agree that these pollutants can have negative impacts on 

plants and ecosystems, damaging plants, trees, and other vegetation, and reducing forest growth 

and crop yields, which could have a negative effect on species diversity in ecosystems. 

Therefore, although our action concerns visibility impairment, we note the potential for 

significant improvements in human health and the ecosystem. 

Although we appreciate the commenter’s concern regarding the negative health impacts 

of toxic emissions from the SJGS, we note that toxic emissions are not considered to be visibility 

impairing pollutants. Similarly, mercury is not a visibility impairing pollutant, and N2O – a 

GHG – does not belong to the NOx family, nor is it considered a visibility impairing pollutant. 

Comment: One commenter states that power plants are responsible for approximately 

one-quarter of the NOx emitted in the U.S. each year, and therefore urges us to adopt a plan with 

stricter standards to regulate the toxic air emissions from the SJGS to protect public health, 

decrease emergency room visits and asthma. According to the commenter, the SJGS is one of 

the greatest NOx polluters in the nation, contributing to the formation of harmful particulate 

matter, ground level ozone smog, and acid rain. 

Response: We appreciate the commenters’ concerns regarding the NOx emissions from 

power plants such as the SJGS. We agree that these emissions are detrimental to human health 

and the environment, with NOx being a precursor to ground-level ozone and also leading to the 

formation of acid rain. Although we appreciate the commenter’s encouragement that we adopt 

even stricter standards, after considering all the comments we received, as we have stated 

elsewhere in this notice, we believe that the standards proposed in our proposal establish BART 

and will prevent visibility impairment from the SJGS. 

H. Miscellaneous Comments 

Comment: A commenter stated that it is appropriate and necessary for us to promulgate a 

FIP that addresses interstate transport of air pollutants from New Mexico, pointing out that the 

SJGS is located a short distance from several state boundaries. They also state we should have 

presented a clearer explanation of the events that have taken place related to New Mexico’s work 

on the SIP in the 2003-2010 timeframe. The commenter believes including more detail in the 

background section of the proposal about the intermediate actions taken by us and NMED in the 

given timeframe in regards to New Mexico’s SIP would have added clarity for the public. 
80 

Response: We believe the level of detail we included in the “Background” section of our 

proposal is appropriate and sufficient to give the public a clear picture of the events leading up to 

our proposal. In particular, the subsection titled Statutory and Regulatory Framework 

Addressing Interstate Transport and Visibility provides detailed information to give the public a 

clear picture of what we received from New Mexico in terms of the RH SIP and the Interstate 

Transport SIP. 

Comment: A commenter is concerned with degradation of visibility in Mesa Verde 

National Park over the last decade. The commenter believes that in the Interstate Transport SIP 

we received on September 17, 2007, New Mexico’s statement that no sources in New Mexico 

impact the protection of visibility in neighboring states seems to be unsupported by the evidence 

presented by NMED. 

Response: We note that it appears that the commenter may have a misconception of what 

NMED submitted in terms of the Interstate Transport SIP. As explained in our proposal, we 

received a SIP from New Mexico to address the interstate transport provisions of CAA section 

110(a)(2)(D)(i) for the 1997 8-hour ozone and PM2.5 NAAQS on September 17, 2007. New 

Mexico did not state in this Interstate Transport SIP that no sources in New Mexico impact the 

protection of visibility in neighboring states. Instead, New Mexico’s Interstate Transport SIP 

stated that the requirement under section 110(a)(2)(D)(i)(II) that the state not interfere with the 

visibility programs of other states would be addressed by the submittal of a RH SIP by December 

2007. As we state elsewhere in our response to comments and in our proposal, because New 

Mexico had not submitted a RH SIP or an alternative means of demonstrating that emissions 

from its sources would not interfere with the visibility programs of other States at the time of our 

proposal, we proposed disapproval of the September 17, 2007 SIP, and proposed a FIP to fill that 

gap. We are now finalizing our proposed FIP to ensure that emissions from New Mexico do not 

interfere with the visibility programs of other States. We received New Mexico’s RH SIP under 

section 51.309 on July 5, 2011, long after statutory and regulatory deadlines. We will review 

that submission, and address it in a future action. 

Comment: A commenter generally agrees with our proposed determination that all the 

air pollution sources in New Mexico are achieving the emission levels assumed by the WRAP 

modeling except for the SJGS, but would like to know what data and modeling supports it. 

Response: We based our conclusion that all sources in New Mexico are achieving the 

emission levels assumed by the WRAP in its modeling except for the SJGS by reviewing the 

WRAP photochemical modeling emission projections used in the demonstration of reasonable 

progress towards natural visibility conditions and comparing these emission projections to 

current emission levels from sources in New Mexico. 

Comment: A commenter stated that there must be balance in the proposals and 

regulations that are presented by the federal and state governments. The commenter indicated 

that although this is an issue of visibility, he is sure we have somehow taken health impacts into 

consideration in formulating our proposal The commenter also expressed his belief that our 

proposal is counter-productive and has a better than average potential to harm the local and state 
81 

economies. The commenter stated that the technology we are proposing is costly and seems 

unnecessary, as PNM recently completed a project that put it in compliance with all current 

health requirements, and only considers visibility in the surrounding national parks and 

wilderness areas while ignoring the economic impact to the local community. The commenter 

expressed his belief that cost estimates from the private sector tend to be more accurate than 

government estimates. The commenter stated that our proposal calls into question the continued 

viability of the SJGS as an asset to the Public Service Company of New Mexico. The 

commenter stated that this is not an issue that requires emergency action, and suggests allowing 

tomorrow’s technology provide a solution to today’s problems. 

Response: We understand the commenter’s concern regarding the need for balance in the 

regulations promulgated by state and federal governments. This decision is based on the RH 

requirements of the CAA. We have not relied on any potential health impacts in reaching our 

decision, although we note the potential for significant improvements in public health. The 

SJGS is one of the largest sources of NOx in the western U.S. and is within 300 kilometers of 16 

Class I areas. Finalizing our proposal is necessary to satisfy CAA requirements, including 

section 110(a)(2)(D)(i)(II) with respect to preventing emissions from New Mexico sources from 

interfering with other states’ measures to protect visibility. As previously stated, we have an 

obligation to promulgate a FIP to address the requirements of section 110(a)(2)(D)(i) with 

respect to visibility and a FIP to address the requirements of RH. The purposes and requirements 

of these programs are intertwined. As such, we consider it appropriate to promulgate one FIP 

that addresses the requirements of section 110(a)(2)(D)(i) with respect to visibility and the 

BART requirements for NOx for SJGS. 

We disagree with the commenter’s belief that our proposal is counter-productive. As 

presented in our proposal, our modeling analysis demonstrates significant visibility improvement 

at numerous Class I areas from installation of SCR at the SJGS. As we discuss elsewhere in our 

response to comments, our estimate of the cost of installing SCR is approximately 1/3 what PNM 

estimated. Regarding the commenter’s belief that the technology we proposed seems 

unnecessary since PNM recently completed a project that “put it in compliance with all current 

health requirements,” we note that as part of our visibility impairment and BART evaluation, we 

did consider the controls previously installed by PNM as a result of its consent decree with the 

Grand Canyon Trust, Sierra Club, and NMED on March 10, 2005. These controls included the 

installation of low-NOx burners with overfire air ports, a neural network system, and a pulse jet 

fabric filter. 

However, as we discuss elsewhere in our response to comments, these controls were not 

sufficient to prevent New Mexico sources from interfering with measures required in the SIP of 

any other state to protect visibility, pursuant to section 110(a)(2)(D)(i)(II) of the CAA. The 

reduction in NOx from our NOx BART determination and the SO2 emission limits will serve to 

ensure there are enforceable mechanisms in place to prohibit New Mexico NOx and SO2 

emissions from interfering with efforts to protect visibility in other states. In addition, the RHR 

requires us to examine additional retrofit technologies. We have determined that SCR is cost 

effective and results in significant visibility improvements at a number of Class I areas, over and 

above the existing pollution controls currently installed. With regard to the commenter’s belief 

that cost estimates from the private sector tend to be more accurate than government estimates, 
82 

we note that we take our duty to estimate the cost of controls very seriously and make every 

attempt to make a thoughtful and well-informed determination. With regard to the commenter’s 

belief that this is not an issue that requires emergency action and that we should allow 

tomorrow’s technology provide a solution to today’s problems, we note that Congress added the 

BART requirements to the CAA in 1977 to focus attention on the visibility impacts from sources 

such as SJGS. We therefore believe it is appropriate to take action now, and our FIP is necessary 

to satisfy the requirements of CAA section 110(a)(2)(D)(i)(II) with respect to visibility for the 

1997 8-hour ozone standard and the 1997 PM2.5 standard, and to satisfy certain related RH 

requirements. We also note that as described elsewhere in this preamble, New Mexico has only 

recently submitted a RH plan that addresses the interstate provisions of the CAA with respect to 

visibility, and as also explained we cannot review it as part of this action. The FIP clocks of both 

statutory requirements have expired and we therefore have an obligation to act now under the 

CAA. 

Comment: An owner participant of Units 1 and 2 at the SJGS indicates that our proposal 

presents significant challenges and risks to its resource planning by handicapping its ability to 

cost effectively respond to changing conditions. The commenter states that uncertainties such as 

the impact of potential future regulations, future fuel prices, and customer load growth/decline, 

have the potential to change the economic viability of their generating resources. The 

commenter points out that implementation of our proposal would require it to make a significant 

capital investment in the plant, the cost of which could only be recovered through long-term 

operation of that asset. This would likely have the effect of “locking” SJGS into the generation 

portfolio for a considerable period of time or risk stranding those investments. According to the 

commenter, this loss of flexibility would hamper its ability to respond to future scenarios such as 

changes in the economic viability of coal resources, changes in acceptance of coal resources by 

State utility commissions, and reduced demand for coal resources. The commenter states that 

this loss of flexibility is completely unnecessary given that the RH program is intended to make 

gradual reductions in emissions over a decades-long period of time. The commenter asks us to 

recognize the significant reductions already made at SJGS or to defer to the SIP submitted by 

NMED to the Environmental Improvement Board. The commenter suggests that further 

reductions could be made at the plant, including the possible installation of SCR, over 

subsequent planning periods. Such an approach would reduce the immediate financial burden on 

the power plant’s customers, allow time for greater certainty in terms of potential carbon limits 

and customer demand, and retain greater flexibility in future resource decisions. 

Response: Regarding costs, EPA reevaluated projections based on comments received to 

increase them to $344,542,604, which is still much less than industry projections and cost 

effective. Cost is one of the five factors considered in making BART determinations. 

Regarding the utility’s loss of flexibility, the emission limits we select today are the result of a 

schedule in the 1977 Clean Air Act to make gradual reductions in emissions over a decades-long 

period of time 

With regard to the commenter’s request that we recognize the emissions reductions 

already made at SJGS or to defer to the SIP recently that was submitted by NMED to the 

Environmental Improvement Board near the time of the comment, we note that as part of our 

NOx BART evaluation for SJGS, we did consider the controls previously installed by PNM as a 
83 

result of its consent decree with the Grand Canyon Trust, Sierra Club, and NMED on March 10, 

2005. However, in making the NOx BART determination, we were obligated by the RHR to 

examine additional retrofit technologies. EPA will give priority to the review of New Mexico’s 

recently submitted Haze SIP; however, it was received too late to be taken into consideration in 

this rule making. 

Comment: The Navajo Nation submitted comments stating that the Navajo Nation 

Environmental Protection Agency is concerned that non-air quality impacts have not been 

adequately considered in the proposed rule. The commenter states that 20% of the plant workers 

at the SJGS and 41% of the mine workforce at the San Juan Mine are Navajo Nation tribal 

members. The commenter is concerned that we have provided no information or analyses to 

explain how the SJGS will fund the SCR installation costs within the limited timeframe without 

resorting to a reduction-in-force that would potentially impact Navajo workers, contractors, and 

subcontractors. 

Response: Because SJGS has not proposed to shut down, we do not believe that jobs at 

the facility will be threatened. EPA’s decision to lengthen the compliance deadline from 3 to 5 

years should also provide some increases in local employment during that time associated with 

the installation of pollution controls. The RHR requires that the costs of compliance and the 

non-air quality environmental impacts of compliance be considered [40 CFR 

51.308(e)(1)(ii)(A)]. As described in our proposal, we found that PNM did not identify any 

significant or unusual environmental impacts associated with the control alternatives that had the 

potential to affect the selection or elimination of that control alternative. For SCR and 

SCR/SNCR hybrid technologies, the non-air quality environmental impacts EPA evaluated 

included the consideration of water usage and waste generated from each control technology. 

Comment: A commenter argues that things like wood burning stoves, wood burning 

fireplaces, and natural occurrences such as dust, wind, fires, and humidity, impair visibility just 

as much as utilities. The commenter asks us to explain how we propose to control those events 

that affect air quality. 

Response: Natural haze factors are recognized in the current degree of visibility 

impairment in Class 1 areas. The purpose of this decision is to significantly decrease impairment 

from the largest man made sources. In addition, the emissions resulting from wood burning 

stoves and fireplaces are typically included in the emission inventory, which is part of the RH 

SIP New Mexico recently submitted to us under 40 CFR 51.309. We will review the adequacy 

of this SIP submission in a separate future proposal. 

Comment: The commenter asks us to explain how we intend to analyze the cost benefits 

to businesses and individuals. 

Response: The CAA requires us to consider the cost of installing controls and the 

visibility benefits as part of the BART analysis, and we have done that. The commenter may 

wish to consult the Statutory and Executive Orders Review section of this action, which includes 

our determination that the FIP does not contain a Federal mandate that may result in 

expenditures that exceed the inflation-adjusted Unfunded Mandates Reform Act of 1995 
84 

(UMRA) threshold of $100 million by State, local, or Tribal governments or the private sector in 

any 1 year. 

I. Comments in Favor of our Proposal 

Comment: Overall, we received more than 12,000 comment letters in support of our 

rulemaking from members representing states, tribes, local governments, various organizations 

and concerned citizens in support of this rulemaking: These comments were received at the 

Public Hearing in Farmington, New Mexico, by internet, and through the mail. Each of these 

commenters was generally in favor of our proposed decision for the SJGS. These comments 

include urging us to require appropriate retrofit technology at the SJGS for emission control, and 

limiting NOx, SO2, sulfuric acid and ammonia currently or potentially released by the facility. 

A number of representative comments from this group are summarized below. Please see the 

docket associated with this action for representative comments received in support of this 

rulemaking. 

 

We received many letters which were similar in content and format, and are represented 

by thirteen types of positive comment letters in the docket for this rulemaking. Each of these 

comment letters supports our proposed decision for the San Juan Generation Station in New 

Mexico. More than 7,000 of these letters specifically urge us to keep or lower our proposed 

numeric limits on nitrogen oxides, ammonia, and sulfuric acid pollution in our final decision and 

urge us to require compliance with the limits within three years. 

We received a letter from the State of Colorado in support of this rulemaking. These 

comments include support for our careful evaluation of NOx emission control costs for the 

SJGS, and our proposed promulgation of cost effective emission control for this facility to 

improve visibility and provide other environmental benefits. The State of Colorado also 

encouraged us to work closely with the State of New Mexico in selecting the most appropriate 

NOx control technology. 

We received a letter from the Southern Ute Indian Tribe in support of this rulemaking. 

The Tribe’s comments include support for our proposed action to prevent emissions from New 

Mexico sources from interfering with other state’s measures to protect visibility, and to 

implement NOx and SO2 emissions limits at the SJGS to prevent interference. In addition, the 

Tribe supports our proposal to regulate emissions sources in neighboring areas that could 

undermine the Tribes’ efforts to maintain air quality on the Reservation. The Tribe is concerned 

about the impacts of emissions from SJGS on visibility on the Reservation; therefore the Tribe is 

in favor of reducing the regional transport of ozone and ozone precursors such as NOx. 

We received two resolutions which generally support this rulemaking, one from the City 

of Durango, Colorado, and another from the Town of Ignacio Colorado. These resolutions 

include support for requiring the use of BART at the San Juan Generating Station. 

Another commenter expressed support of our proposal. The commenter states that for the 

past 30-40 years, the SJGS has had a largely unrestricted use of the large common air-shed 

shared by Montezuma County, Colorado and San Juan County, New Mexico. During this 
85 

timeframe, the residents of Montezuma County and their neighbors have been continually 

exposed to the air pollution arising from the SJGS, yet the residents of Montezuma County 

receive no benefit from operation of the plant in terms of electricity (aside from40 MW 

purchased from SJGS), tax revenues, and community support. 

Another commenter supported all aspects of our proposed rule. The commenter 

volunteers at Mesa Verde National Park and mentions that many park visitors express 

disappointment over the degraded air quality and limited vistas from the Park. The commenter 

states that the 2.88 deciview of visibility improvement we predicted at Mesa Verde National 

Park with SCR installed at SJGS, would be readily noticed by both residents and visitors to the 

region. The commenter notes that PNM’s website claims that SCR is “unnecessary” and would 

“raise electricity prices for the SJGS’s two million customers,” yet PNM offers no data or other 

support for its conclusion. The commenter also notes that no significant improvement in Four 

Corners RH has been seen since PNM completed installation of emission controls pursuant to the 

2009 consent decree. The commenter also states that it is legally, socially, and economically 

appropriate for PNM’s customers to pay the full costs of the power they consume, including the 

air pollution created while generating it. The commenter also states that although PNM 

characterizes the SJGS as a “low cost” producer of power, it fails to acknowledge that a 

substantial cost of its power, in the form of regional air quality degradation, is borne by the 

people of the Four Corners region, many of whom do not consume SJGS power and derive no 

economic benefit from the facility. The commenter believes a three-year implementation 

schedule for SCR at the SJGS is both appropriate and achievable at a reasonable cost. 

Letters of support were also received from representatives of the following organizations: 

New Mexico Interfaith Power and Light, the Sierra Club, San Juan College, San Juan Basin 

Health Department, San Juan Citizens Alliance, LaPlata County Board of Commissioners, 

League of Women Voters of La Plata County, PNM home and business customers, Mesa Verde 

Nation Park volunteers, Wild Earth Guardians, Green Think Dine Power, Northern Dine Youth 

Committee, and Dooda Desert Rock. Each of these commenters was generally in favor of our 

proposed pollution control technology for the SJGS in New Mexico. These comments include 

urging us to require appropriate retrofit technology at the SJGS for emission control, and limiting 

NOx, SO2, sulfuric acid and ammonia released by the facility. 

Response: We appreciate the support of these commenters for this action. We note that 

several of the specific emissions and timeframe limitations supported by these commenters in the 

proposal have been modified slightly in this final action based on all of the information received 

during the comment period. Please see the docket associated with this action for additional 

detail. 

J. Comments Arguing our Proposal Would Hurt the Economy and/or Raise Electricity 

Rates 

The preamble to the finalized FIP has identical responses to the ones provided in this section. As 

stated in the preamble, we found there to be significant overlap between many comments. EPA 

has summarized and provided responses to each significant argument, assertion and question 

contained within the totality of these comments. 
86 

Comment: A commenter stated that if the FIP is adopted, the owners of the SJGS will 

have three options: compliance, plant shutdown, or plant modification. The commenter states 

that compliance would result in a capital expense not justified by the likely results of that 

investment, and would be a terrible, indefensible waste of resources. Plant shutdown would 

result in the loss of hundreds of jobs in direct plant employment, coal mining, and other support 

and service sectors. The commenter also points out that plant shutdown would result in the 

SJGS customers losing their investment in the plant, which they have paid for through rate 

payment. SJGS customers would have to pay for the development of new generation facilities 

and fuel contracts or would have to buy power on the open market, and they would also be 

responsible for the reclamation of the plant site and any coal mine that might be abandoned as a 

result of plant closure. The commenter states that plant modification would likely take the form 

of conversion from coal-fired to natural gas-fired, which would also result in loss of jobs, as 

there would be no need for coal. The commenter indicates that all three options would result in 

an increase in the cost of electricity to customers, which should be avoided or eliminated in light 

of the weakened and unstable economic conditions at the national, state, and local levels. 

Another part owner of Unit 4 at the SJGS, submitted comments stating that the impact 

from imposing its share of the costs of installing SCR at the SJGS, may require it to raise electric 

rates, cut back on planned clean energy investments, or both, all for what appear to be 

insignificant benefits. 

Response: EPA’s evaluation of capital expenses by the implementation of the FIP shows 

them to be justified by the degree of improvement in visibility in relationship to the cost of 

implementation. The FIP calls for NOx and SO2 emission limits at the SJGS to prevent 

interference with other states’ visibility SIPs as well as requiring BART for NOx at this source. 

BART requires that we evaluate (1) cost of compliance, (2) the energy and non-air quality 

environmental impacts of compliance, (3) any existing pollution control technology in use at the 

source, (4) remaining useful life of source, and (5) degree of improvement in visibility which 

may reasonably be anticipated to result from the use of such technology. 

After careful cost review EPA has determined that the significant benefits in visibility 

resulting from the implementation of the FIP outweigh the increase in costs for the facility. 

K. Comments Arguing our Proposal Would Help the Economy 

The preamble to the finalized FIP has identical responses to the ones provided in this section. As 

stated in the preamble, we found there to be significant overlap between many comments. EPA 

has summarized and provided responses to each significant argument, assertion and question 

contained within the totality of these comments. 

Comment: We received several comments stating that the proposed FIP would help local 

economies by creating new and different jobs in the Region and by increasing tourism. In 

particular, one commenter stated reducing visibility-causing pollutants have far-reaching impacts 

on local economies, human health, and ecosystems. The commenter stated that decreasing these 

pollutants will benefit all of these important areas of concern. This commenter noted that 
87 

tourism is critical to the economy of New Mexico and the Four Corners region, and made several 

points: Utah’s five Class I areas, all of which are national parks, generate a significant portion of 

this sustainable tourism economy: in 2008, these areas were responsible for 5.7 million 

recreation visits, over $400 million in spending, and nearly 9,000 jobs. Parks attract businesses 

and individuals to the local area, resulting in economic growth in areas near parks that is an 

average of 1 percent per year greater than statewide rates over the past three decades. National 

parks also generate more than four dollars in value to the public for every tax dollar invested. 

Therefore, this commenter concluded, improving visibility at these national parks improves the 

local economies around them. 

This commenter also noted that an additional economic incentive behind protecting air 

quality is the necessary investment in pollution control technologies as they are a job-creating 

mechanism in itself. Each installation creates short-term construction jobs as well as permanent 

operations and management positions. 

Response: We agree with the comments. Although we did not consider the potential 

positive benefits to local economies in making our decision today, we do expect that improved 

visibility would have a positive impact on tourism-dependent local economies. Also, retrofitting 

the SJGS with SCR is a large construction project that we expect to take 3 to 5 years to complete. 

This project will require well-paid, skilled labor which can potentially be drawn from the local 

area, which would seem to benefit the economy. 

L. Comments Requesting an Extension to the Public Comment Period 

The preamble to the finalized FIP has identical responses to the ones provided in this section. As 

stated in the preamble, we found there to be significant overlap between many comments. EPA 

has summarized and provided responses to each significant argument, assertion and question 

contained within the totality of these comments. 

Comment: We received comments requesting that the comment period be extended, with 

most requesting an additional 60 days. We also received comments requesting additional public 

hearings. 

Response: Originally the comment period for our proposal was due to close on March 7, 

2011. In response to requests we extended the public comment period to April 4, 2011. In doing 

so, we took into consideration how an extension might affect our ability to consider comments 

received on the proposed action and still comply with the terms of a consent decree we have with 

WildEarth Guardians.183 We do note that our February 17, 2011, public hearing in Farmington, 

New Mexico was well attended and provided an opportunity for people to comment on our 

proposal. 

M. Comments Requesting we Defer Action in Favor of a New Mexico SIP Submittal 

Comment: Various commenters have stated that the NMED should take the lead in 

implementing the RH requirements of the CAA based on the fundamental principle that the CAA 

 183 WildEarth Guardians v. Lisa Jackson, Case No. 4:09-CV-02453-CW. 
88 

and the RHR emphasize that states, not EPA, are to take the lead in implementing the RH 

program, and we should wait taking action until NMED submits to the Agency their revised RH 

SIP and adopt such submittal instead of promulgating a FIP. Some of these comments make 

specific reference to a regional haze proposal that was sent to the NMED on February 11, 2011 

(later submitted to EPA on July 5, 2011), while others makes non-specific calls for approvals of 

the New Mexico SIP and request deference to NMED. 

Response: Congress crafted the CAA to provide for States to take the lead for 

implementing plans, but balanced that decision by requiring EPA to approve the plans or 

prescribe a federal plan should the State plan be inadequate. Our action today is consistent with 

the statute. As explained in our proposal, we received a SIP from New Mexico to address the 

interstate transport provisions of CAA section 110(a)(2)(D)(i) for the 1997 8-hour ozone and 

PM2.5 NAAQS on September 17, 2007. New Mexico’s September 17, 2007 submittal addressed 

the requirement that the state not interfere with the visibility programs of other states by stating 

that it would submit a RH SIP by December 2007. 

On January 15, 2009, EPA published a ‘‘Finding of Failure to Submit State 

Implementation Plans Required by the 1999 Regional Haze Rule.’’ 74 FR 2392. We found that 

New Mexico and other states had failed to submit for our review and approval complete SIPs for 

improving visibility in the nation’s national parks and wilderness areas by the required date of 

December 17, 2007. We found that New Mexico failed to submit the plan elements required by 

40 CFR 51.309(g), the reasonable progress requirements for areas other than the 16 Class I areas 

covered by the Grand Canyon Visibility Transport Commission Report. New Mexico also failed 

to submit the plan element required by 40 CFR 51.309(d)(4), which requires BART for 

stationary source emissions of NOx and PM under either 40 CFR 51.308(e)(1) or 51.308(e)(2). 

This notice initiated a 2-year deadline, referred to as the “FIP clock,” for New Mexico to submit 

a SIP or for EPA to issue a FIP. The FIP would provide the basic program requirements for each 

State that has not completed an approved plan of their own by January 15, 2011. The CAA 

requires EPA to promulgate a FIP if a State fails to make a required SIP submittal or if we find 

that the State's submittal is incomplete, does not meet the minimum criteria established in the 

CAA or we disapprove in whole or in part the SIP submission. CAA section 110(c)(1). 

In addition, WildEarth Guardians sued EPA alleging that we failed to perform the nondiscretionary duty to either approve a SIP or promulgate a FIP for New Mexico, among other 

States, to satisfy the requirements of CAA section 110(a)(2)(D)(i) with regard to the 1997 

National Ambient Air Quality Standards for 8-hour ozone and fine particulate matter. We have 

entered into a consent decree with WildEarth Guardians to resolve this matter. 

This consent decree specifically requires us—no later than August 5, 2011—to sign a 

notice either approving a SIP, promulgating a FIP, or approving a SIP in part with promulgation 

of a partial FIP, for New Mexico to meet the requirement of 42 U.S.C. § 7410(a)(2)(D)(i)(II) 

regarding interfering with measures in other states related to protection of visibility. As required 

by the consent decree, since New Mexico did not submit a complete proposed SIP to address the 

visibility requirement by May 10, 2010, then by November 10, 2010, EPA was required to 

propose one of three actions: a FIP; approval of a SIP (if one has been submitted in the interim); 

or partial promulgation of a FIP and partial approval of a SIP. In the absence of a SIP, EPA 
89 

proposed a FIP on January 5, 2011. We received the New Mexico submittal on July 5, 2011, 

after the close of the record for the proposed FIP EPA will give priority to the review of New 

Mexico’s SIP but we cannot consider it and meet the consent decree deadline. 

N. Comments Generally Against our Proposal 

Comment: Various commenters generally stated they do not support the proposed 

rulemaking. Their reasons included: it will affect the town’s economy, affect the coal power 

plant industry, electricity costs will increase, they have no direct health problems from actual 

emissions, direct and indirect jobs/businesses would be affected, current air pollution control 

equipment meet EPA and health standards. Others commented that our decision is arbitrary as 

no other similar facilities have the same requirements imposed by the FIP and that there will be 

no benefit to the community. One commenter argues that SJGS already meets the visibility 

standards required by the CAA. 

Response: While we appreciate the effort and time of the commenters, the comments did 

not include documentation, rationale, or data for EPA to respond beyond our responses provided 

elsewhere. 

O. Comments on Legal Issues 

The preamble to the finalized FIP has identical responses to the ones provided in this 

section. As stated in the preamble, we found there to be significant overlap between many 

comments. EPA has summarized and provided responses to each significant argument, assertion 

and question contained within the totality of these comments. 

1. EPA’s Authority 

Comment: Various commenters argued that combining Interstate Transport and RH 

BART requirements in the proposed action exceeds our authority and does not satisfy the 

regulatory requirements of each program, and each program has different requirements and 

purposes. 

Response: We do not agree that it exceeds our authority to combine action on RH BART 

requirements as part of our action on the required State submittal to meet section 110(a)(2)(D) of 

the CAA. EPA has two separate sources of authority and obligations to take this action, i.e., a 

statutory obligation to promulgate a FIP to meet the requirements of section 110(a)(2)(D)(i)(II) 

and a statutory obligation to promulgate a FIP to meet RH program requirements of the CAA. 

Nothing in the CAA precludes EPA from addressing both requirements simultaneously, and 

indeed, to address both in the same action is rational to ensure the most efficient use of resources 

by both the Agency and the affected source. The SJGS is subject to both provisions of the CAA, 

and both provisions concern emissions of NOx (among other pollutants). To separate our actions 

could potentially lead to the same source needing to install two successive levels of control 

measures, the first in order to meet the requirements of section 110(a)(2)(D)(i), and then the 

second in order to meet the requirements of the RH program. 
90 

The CAA requires each state to develop a SIP that provides for the implementation, 

maintenance, and enforcement of the NAAQS. CAA section 110(a)(1). The statute explicitly 

requires that each state’s SIP shall include, among other things, adequate provisions prohibiting 

any source from emitting any air pollutants in amounts which will interfere with measures 

required to be included in the applicable implementation plan for any other State to protect 

visibility. CAA section 110(a)(2)(D)(i)(II). 

On April 25, 2005, we published a “Finding of Failure to Submit SIPs for Interstate 

Transport for the 8-hour Ozone and PM2.5 NAAQS.” 70 FR 21147. This notice included a 

finding that New Mexico and other states had failed to submit SIPs to address any of the four 

prongs of section 110(a)(2)(D)(i), including the provisions relating to interstate transport of air 

pollution affecting visibility, and started a 2-year clock for us to promulgate a FIP, unless a State 

made a submission to meet the requirements of section 110(a)(2)(D)(i) and we approved the 

submission. CAA section 110(c)(1). That two year period has expired. 

The CAA also requires each state to develop a SIP to protect visibility. CAA section 

169. On January 15, 2009, we published a “Finding of Failure to Submit State Implementation 

Plans Required by the 1999 Regional Haze Rule.” 74 FR 2392. In that notice we found that New 

Mexico and other states had failed to submit complete SIPs for improving visibility in the 

nation’s national parks and wilderness areas by the required date of December 17, 2007. 

Specifically, we found that New Mexico failed to submit the plan elements required by 40 CFR 

51.309(g), the reasonable progress requirements for areas other than the 16 Class I areas covered 

by the Grand Canyon Visibility Transport Commission Report. In addition, we also found that 

New Mexico had failed to submit the plan element required by 40 CFR 51.309(d)(4), which 

requires BART for stationary source emissions of NOx and PM under either 40 CFR 

51.308(e)(1) or 51.308(e)(2). This finding of failure to submit started a 2-year clock for us to 

promulgate a FIP, unless the State made a RH SIP submission and we approved it. That two 

year period has also expired. 

On September 17, 2007 we received a SIP from New Mexico to address the interstate 

transport provisions of CAA 110(a)(2)(D)(i) for the 1997 8-hour ozone and PM2.5 NAAQS. In 

that submission, the state indicated that it intended to meet the requirements of section 

110(a)(2)(D)(i) with respect to visibility by submission of a timely RH SIP. Those RH SIPs 

were due no later than December 17, 2007. 

As of the time of our proposal for this action on January 5, 2011, the state had not make 

the RH SIP submission as represented in its section 110(a)(2)(D) submission, and had not make a 

RH SIP submission or alternate section 110(a)(2)(D) submission indicating that the state 

intended to meet visibility prong by any other means. 

We received a RH SIP submittal from the state on July 5, 2011. Unfortunately, due to the 

timing of that submittal, we cannot evaluate it as part of this action. We note that this RH SIP 

submittal arrived approximately 3-1/2 years past the due date of December 17, 2007, and well 

past January 15, 2011, the date by which we were obligated either to approve a RH SIP 

submission or to promulgate a RH FIP, as a result of the 2009 finding of failure to submit the RH 

SIP. Moreover, the July 5, 2011, submission also occurred more than four years after the date by 
91 

which we were obligated either to approve a SIP submission or to promulgate a FIP to address 

the state’s failure to submit a submission for section 110(a)(2)(D)(i)(II). 

We are under a consent decree deadline with WildEarth Guardians that requires the 

Agency to take action by August 5, 2011, either to approve the New Mexico section 

110(a)(2)(D) SIP, or to promulgate a FIP, to address the 110(a)(2)(D)(i)(II) visibility prong. 

Because of the lateness of the July 5, 2011 submission, it is not possible to review and 

potentially fully approve the July 5, 2011, SIP submission by proposing a rulemaking and 

promulgating a final action by August 5, 2011, as required by the consent decree. 

The CAA requires us to promulgate a FIP if a State fails to make a required SIP submittal 

or if we find that the State's submittal is incomplete, does not meet the minimum criteria 

established in the CAA or we disapprove in whole or in part the SIP submission. CAA section 

110(c)(1). As previously discussed, we have made findings related to the New Mexico SIP 

submission needed to address interstate transport and the requirement that emissions from New 

Mexico sources do not interfere with measures required in the SIP of any other state to protect 

visibility, pursuant to section 110(a)(2)(D)(i)(II) of the CAA. 

Therefore, as New Mexico failed to submit an approvable SIP that addresses the 

interstate provisions of the CAA with respect to visibility, and has made a very late RH SIP 

submission giving us no time to complete the regulatory process necessary to evaluate that 

submission in light of the deadlines imposed by the above-mentioned consent decree, we have 

the statutory authority and the obligation to promulgate a FIP that meets one or both 

requirements. 

In addition, we think that it is appropriate to take action on the visibility requirements of 

section 110(a)(2)(D)(i)(II) and RH program requirements simultaneously in these circumstances 

because the purposes and requirements of the interstate transport provisions of the CAA with 

respect to visibility and the RH program are intertwined. The requirements of CAA section 

110(a)(2)(D)(i)(II) explicitly provide that states must have SIPs with adequate provisions to 

prevent inference with the efforts of other states to protect visibility, which includes the 

protections contemplated by the RH program. This section of the CAA requires each SIP “to 

include adequate provisions prohibiting any source from emitting any air pollutants in amounts 

which will interfere with measures required to be included in the applicable implementation plan 

for any other State ... to protect visibility.” These required SIP measures to protect visibility are 

set forth in sections 169A & 169B of the CAA and EPA’s implementing regulations for the RH 

program. 

Section 110(a)(2)(D)(i)(II) does not explicitly define what is required in SIPs to prevent 

the prohibited impact on visibility in other states. However, because the RH program requires 

measures that must be included in SIPs specifically to protect visibility, EPA’s 2006 Guidance184

 184 See, “Guidance for State Implementation Plan (SIP) Submissions to Meet Current Outstanding Obligations 

Under Section 110(a)(2)(D)(i)for the 8-Hour Ozone and PM 2.5 National Ambient Air Quality Standards,” from 

William T. Harnett, Director Air Quality Policy Division, OAQPS, to Regional Air Division Director, Regions I-X, 

dated August 15, 2006 (the “2006 Guidance”). 
92 

recommended that RH SIP submissions meeting the requirements of the visibility program could 

satisfy the requirements of CAA section 110(a)(2)(D)(i)(II) with respect to visibility. 

Subsequently, when some states did not make the RH SIP submission, in whole or in 

part, or did not make an approvable RH SIP submission, we have evaluated whether states could 

comply with section 110(a)(2)(D)(i)(II) by other means. Thus, we have elsewhere determined 

that states may also be able to satisfy the requirements of CAA section 110(a)(2)(D)(i)(II) with 

something less than an approved RH SIP, see e.g. Colorado (76 FR 22036 (April 20, 2011)) and 

Idaho (76 FR 36329 (June 22, 2011)). In other words, an approved RH SIP is not the only 

possible means to satisfy the requirements of CAA section 110(a)(2)(D)(i)(II) with respect to 

visibility; however, such a SIP could be sufficient. Given this reasoning, we do not agree with 

commenters’ contentions that the two programs have completely different requirements and 

purposes and that it is unreasonable for EPA to seek to address these issues in the same action. 

Comment: Various commenters have stated that we proposed to act on an interstate 

transport SIP requirement, while borrowing portions of the RH SIP requirements, and that such 

partial implementation of programs is inappropriate and conflicts with the structure and purpose 

of the CAA. 

Response: We disagree with the premise of the commenters that we cannot address more 

than one statutory requirement in the same notice and comment rulemaking. See response to 

comments, above, regarding our general authority and obligation to act on section 

110(a)(2)(D)(i)(II) and RH SIP requirements. We also specifically disagree that acting on 

portions of the RH SIP requirements in this action is inappropriate and conflicts with the 

structure and purpose of the CAA. We have authority to act on submissions, or portions of 

submissions, as appropriate to meet the requirements of the CAA, in accordance with section 

110(k)(3). In this instance, we have determined that it is appropriate to take action addressing 

the NOx BART requirements for an individual source, and thereby to meet a portion of our 

outstanding statutory FIP obligation for the RH program, at the same time as acting on the 

section 110(a)(2)(D)(i)(II) SIP submission with respect to the visibility prong to meet that 

statutory FIP obligation. 

We note that we have previously acted on other portions of the section 110(a)(2)(D)(i) 

SIP submission from the state. In prior actions, we approved the New Mexico SIP submittal for: 

(1) the “significant contribution to nonattainment” prong of section 110(a)(2)(D)(i) (75 FR 

33174, June 11, 2010); and (2) the “interfere with maintenance” and “interfere with measures to 

prevent significant deterioration” prongs of section 110(a)(2)(D)(i). (75 FR 72688, November 

26, 2010). Were it in fact “inappropriate” to act on portions of SIP submissions, or were it 

contrary to the structure and purpose of the CAA to do so, as the commenters argue, we would 

not have taken such prior actions on portions of the state’s section 110(a)(2)(D)(i) submission. 

Moreover, no one objected to those actions on these grounds. 

We also contend that promulgating FIPs to address specific CAA requirements is 

consistent with the purposes of the statute. One of the primary goals of the CAA is to protect 

and enhance the quality of the Nation’s air resources so as to promote the public health and 

welfare. CAA section 101(b)(1). Failing to submit an approvable SIP submission, as required 
93 

by section 110 of CAA, is contrary to the purposes and goals of the CAA. The CAA requires us 

to promulgate a FIP if a State has failed to make a required submission or finds that a plan does 

not satisfy the minimum established criteria, or disapproves a SIP submission in whole or in part. 

CAA section 110(c)(1). 

In this action, we are disapproving a portion of the New Mexico Interstate Transport SIP 

with respect to the requirement that emissions from New Mexico sources do not interfere with 

measures required in the SIP of any other state to protect visibility. On September 17, 2007 we 

received a SIP from New Mexico to address the interstate transport provisions of CAA 

110(a)(2)(D)(i) for the 1997 8-hour ozone and PM2.5 NAAQS. In this submission, the state 

indicated that it intended to meet the requirements of section 110(a)(2)(D)(i) with respect to 

visibility by submission of a timely RH SIP. As previously explained above, we received a RH 

SIP submission from the state on July 5, 2011. Because of the lateness of the submission, and in 

light of our obligations under the WildEarth Guardians consent decree to have completed 

rulemaking on the visibility prong of Section 110(a)(2)(D)(i), it is not possible to review such 

SIP submission, propose a rulemaking, and promulgate a final action prior to the August 5, 2011 

deadline. 

Therefore, as previously stated, we have both a statutory obligation to promulgate a FIP 

to address the requirements of section 110(a)(2)(D)(i) with respect to visibility and a statutory 

obligation to promulgate a FIP to address the requirements of RH. As also previously stated, the 

purposes and requirements of these programs are intertwined. As such, we consider it 

appropriate to promulgate one FIP that addresses both the requirements of section 

110(a)(2)(D)(i) with respect to visibility and the BART requirements for NOx from SJGS. 

Although there are additional RH SIP requirements to be addressed, and we intend to address 

these requirements in the near future, there is no requirement in the CAA that we take action to 

address a state’s failure to submit an approvable RH SIP in only one action. 

Comment: Some commenters argued that the proposed FIP is too all encompassing, 

exceeds the authority vested in EPA under Section 110 of the CAA because it provides too 

stringent a control for attaining visibility standards, and will have broader impact than the 

purpose of the CAA to not interfere with neighboring state implementation plans. 

Response: In general, for the reasons we have outlined elsewhere in our responses to 

comments, we disagree that our FIP is too all encompassing or exceeds our authority under 

section 110(a)(2)(D)(i) of the CAA. Under that provision, we may not approve the SIP 

submission from the state unless the SIP contains provisions adequate to prohibit emissions from 

sources in that state from interfering with measures required to protect visibility in other states. 

As explained in this action, we have determined that emissions sources in New Mexico meet this 

requirement, except for the SJGS. For this source, we have determined that additional and 

federally enforceable controls are required in order to meet the NOx emissions used in the 

WRAP photochemical modeling and that federally enforceable emission limits are required in 

order to meet the SO2 emissions used in the WRAP photochemical modeling, as part of this 

action in order to be in compliance with section 110(a)(2)(D)(i). Our action is also based in part 

on our authority to address the NOx BART requirements for the SJGS. To meet this separate 

requirement, we have determined that specific NOx controls are required for the SJGS. 
94 

Comment: Various commenters argued that EPA failed to present “a coherent or 

defensible justification” for its interpretation of section 110(a)(2)(D)(i)(II) in the proposal, and 

that EPA failed to explain adequately its interpretation of CAA section 110(a)(2)(D)(i)(II) and 

the relationship between that provision, as interpreted by the Agency, and CAA sections 169A 

and 169B. In addition, the commenter asserted that EPA has no basis to disapprove the state’s 

section 110(a)(2)(D) submission with respect to the visibility prong, because the state’s 

submission was consistent with EPA’s 2006 guidance to states for these SIP submission. 

Response: We disagree with these assertions. First, in the proposal we explained our 

views as to the proper interpretation of section 110(a)(2)(D)(i)(II). We explained that section 

110(a)(2)(D(i)(II) requires states “to have a SIP, or submit a SIP revision, containing provisions 

‘prohibiting any source or other type of emissions activity within the state from emitting any air 

pollutant in amounts which will ... interfere with measures required to be included in the 

applicable implementation plan for any other State under part C [of the CAA] to protect 

visibility. 76 FR 493 (January 5, 2011). We explicitly stated that “[b]ecause of the impacts on 

visibility from the interstate transport of pollutants, we interpret the ‘good neighbor’ provisions 

of section 110 of the Act described above as requiring states to include in their SIPs measures to 

prohibit emissions that would interfere with the reasonable progress goals set to protect Class I 

areas in other states.” Id. 

In the proposal, we expressed our view that section 110(a)(2)(D)(i)(II) “does not 

explicitly specify how we should ascertain whether a state’s SIP contains adequate provisions to 

prevent emissions from sources in that state from interfering with measures required in another 

state to protect visibility” Id. at 496. We clearly stated that the statute is thus ambiguous and 

that the Agency must interpret that provision in this action. Id. We are explaining our reading of 

the ambiguity in the statute in this notice and comment rulemaking. 

Thereafter, we articulated in detail the underlying premise for our 2006 guidance, and the 

recommendations that states address this requirement through submission of the RH SIP. We 

specifically explained the basis for our belief that the development of those SIPs would provide 

an appropriate forum in which states would have evaluated the need for emission controls to 

protect visibility, and in particular would have considered emissions from sources in other states 

and their degree of control as part of developing their respective programs to protect visibility. 

The proposal articulated our basis for proposing to interpret the requirement of section 

110(a)(2)(D)(i)(II) to mean that the state’s SIP must contain at least those emission reductions 

that other states would have relied upon from New Mexico sources in the development of their 

reasonable progress goals in their respective visibility programs. Moreover, our proposal 

articulated that evaluation of the analysis conducted by the WRAP is one means of gauging 

whether New Mexico has adequately controlled its sources for this purpose. 

We also disagree with the assertion that we have failed to explain adequately our 

interpretation of the visibility prong of section 110(a)(2)(D)(i) in light of the requirements of 

section 169A and 169 B of the Act. As explained in our proposed action, the CAA establishes a 

visibility protection program that sets forth “as a national goal the prevention of any future, and 

the remedying of any existing, impairment of visibility in mandatory class I Federal areas which 
95 

impairment results from manmade air pollution.” CAA section 169A(a)(1). In section 

169A(a)(1) of the 1977 Amendments to the CAA, Congress created a program for protecting 

visibility in the nation’s national parks and wilderness areas. This section of the CAA 

establishes as a national goal the “prevention of any future, and the remedying of any existing, 

impairment of visibility in mandatory Class I Federal areas which impairment results from 

manmade air pollution.” In 1980, we promulgated regulations to address visibility impairment in 

Class I areas that is “reasonably attributable” to a single source or small group of sources, i.e., 

“reasonably attributable visibility impairment.” 45 FR 80084 (December 2, 1980). These 

regulations represented the first phase in addressing visibility impairment. We deferred action 

on RH that emanates from a variety of sources until monitoring, modeling and scientific 

knowledge about the relationships between pollutants and visibility impairment were improved. 

Id. 

Congress added section 169B to the CAA in 1990 to address RH issues, and we 

promulgated regulations addressing RH in 1999. 64 FR 35714 (July 1, 1999), codified at 40 

CFR part 51, subpart P (the RHR). The RHR revised the existing visibility regulations to 

integrate provisions addressing RH impairment and established a comprehensive visibility 

protection program for Class I areas. The requirements for RH, found at 40 CFR 51.308 and 

51.309, are included in our visibility protection regulations at 40 CFR 51.300-309. States were 

required to submit the first SIP addressing RH visibility impairment no later than December 17, 

2007. 40 CFR 51.308(b). 

We disagree with the argument that because section 169A and B create a specific 

program for protection of visibility, that compels the conclusion that section 110(a)(2)(D)(i)(I) 

could not have any substantive bearing on this issue. Such an argument is at odds with the clear 

provisions of the statute, and with the structure of the CAA. Section 110(a)(2)(D)(i)(II) of the 

CAA requires that SIPs shall include adequate provisions “prohibiting . . . any source . . . within 

the State from emitting any air pollutant in amounts which will . . . interfere with measures 

required to be included in the applicable implementation plan for any other State under part C . . 

. to protect visibility.” (Emphasis added). Because sections 169A and 169B establish the 

national goal for visibility protection, including RH issues, we infer that when Congress included 

protection of required visibility programs in other states as part of section 110(a)(2)(D)(i), it was 

a conscious reference to the sections in the CAA that address that matter. Indeed, in section 

110(a)(2)(D)(i)(II), Congress directed us to prevent interference with the “measures required to 

be included in the applicable implementation plan for any other State under part C of this chapter 

... to protect visibility,” and the RH program is unequivocally among those required measures to 

protect visibility. Thus, it is reasonable for EPA to evaluate whether the SIP of a given state 

prohibits emissions, consistent with what other states will have developed their own visibility 

programs in reliance upon. 

 

It is illogical to conclude that Congress would have explicitly directed us to assure that 

state SIPs contain provisions to protect visibility programs in other states, but that we not have 

the authority to require such provisions as part of a section 110(a)(2)(D)(i)(II) SIP submission, or 

if necessary to supply them as part of a FIP. Such an argument is also clearly inconsistent with 

the other prongs of section 110(a)(2)(D)(i). The mere existence of other statutory programs to 

provide for attainment and maintenance of the NAAQS required in part D of the Act, does not 
96 

negate the requirement that states also meet the requirement of the “significant contribution to 

nonattainment” and “interference with maintenance” prongs of section 110(a)(2)(D)(i)(I), and 

the authority of EPA to require substantive provisions in the SIP, or to promulgate a FIP to 

provide them, as may be necessary. We have exercised such authority and issued SIP calls or 

promulgated FIPs to assure that state SIPs meet the requirements of section 110(a)(2)(D)(i).185 

Because of the impacts on visibility from the interstate transport of pollutants, we thus interpret 

the “good neighbor” provisions of section 110 of the Act described above as requiring states to 

include in their SIPs measures to prohibit emissions that would interfere with the reasonable 

progress goals of the RH program set to protect Class I areas in other states of the RH program. 

Finally, we disagree with the commenter’s views concerning the state’s September 2007, 

submission complying with the Agency’s 2006 guidance, and even if it had complied with that 

guidance, the purported legal significance of that fact for purposes of this action. As the 

commenters themselves conceded, the state’s 2007 submission stated that it would make a timely 

RH SIP submission by December of 2007 as its intended means of meeting the requirements of 

section 110(a)(2)(D)(i)(II) for visibility, but due to intervening events the state did not in fact do 

so prior to our proposed action. Contrary to the commenter’s views, that submission was not 

factually consistent with the recommendations of the guidance.186

More importantly, however, our 2006 guidance reflected our recommendations for how 

states could potentially meet the section 110(a)(2)(D)(i)(II) requirement at that point in time. As 

of August 2006, we stated our belief that it was “currently” premature for states to make a more 

substantive SIP submission for this element, because of the anticipated imminent RH SIP 

submissions. We explicitly stated that “at this point in time” in August of 2006, it was not 

possible to assess whether emissions from sources in the state would interfere with measures in 

the SIPs of other states. As subsequent events have demonstrated, we were mistaken as to the 

assumption that all states would submit RH SIPs in December of 2007 and mistaken as to the 

assumption that all such submissions would meet applicable RH program requirements and 

therefore be approved shortly thereafter. Thus the premise of the 2006 Guidance that it would be 

appropriate to await submission and approval of such RH SIPs before evaluating SIPs for 

compliance with section 110(a)(2)(D)(i)(II) was in error. Our 2006 Guidance was clearly 

intended to make recommendations that were relevant at that point in time, and subsequent 

events have rendered it inappropriate in this specific action. 

In short, we must act upon the state’s submission in light of the actual facts, and in light 

of the statutory requirements of section 110(a)(2)(D)(i). Whereas our prior recommendations 

were prospectively anticipating the submission of the RH SIP as a means of the state imposing 

the controls necessary on New Mexico sources necessary to prevent interference with the 

required visibility programs of other states, those recommendations are inappropriate at this 

 185 See, e.g., “Finding of Significant Contribution and Rulemaking for Certain States in the Ozone Transport 

Assessment Group Region for Purposes of Reducing Regional Transport of Ozone; Final Rule,” 63 FR 57356, 

October 27, 1998, (the NOx SIP Call). 

186 Subsequent to the proposal for this action, and subsequent to the commenter’s comments, the state did make a 

RH SIP submission on July 5, 2011, one month before we have to finalize rulemaking either by promulgating a FIP 

or reviewing, proposing a rulemaking and promulgating a final action fully approving the SIP, as required by the 

August 5, 2011 consent decree deadline. Nevertheless, the commenter was clearly in error given that there was no 

submission purporting to meet the requirements of the RH program as of the time of its comments. 
97 

juncture. In order to evaluate whether the state’s SIP currently in fact contains provisions 

sufficient to prevent the prohibited impacts on the required programs of other states, we are 

obligated to consider the current circumstances and investigate the level of controls at New 

Mexico sources and whether those controls are or are not sufficient to prevent such impacts. 

We similarly disagree with the commenters’ argument that it is still “premature” to 

evaluate the compliance of the state’s SIP at this time, and that we “must await the date on which 

regional haze SIPs have been submitted and approved.” First, this approach is illogical, as it 

fails to address what would happen if a state were never to submit the required RH SIP, or were 

never to submit a RH SIP that was approvable. On its face, the commenter’s argument is simply 

inconsistent with the objectives of the statute to protect visibility programs in other states if a 

state never submits an approvable RH SIP. Second, this approach is flatly inconsistent with the 

timing requirements of section 110(a)(1) which specifies that SIP submissions to address section 

110(a)(2)(D)(i), including the visibility prong of that section, must be made within three years 

after the promulgation of a new or revised NAAQS. We acknowledge that there have been 

delays with both RH SIP submissions by states and our actions on those RH SIP submissions, 

but that fact does not support a reading of the statute that overrides the timing requirements of 

the statute. We believe that there are means available now to evaluate whether a state’s section 

110(a)(2)(d)(i)(II) SIP submission meets the substantive requirement that it contain provisions to 

prohibit interference with the visibility programs of other states, and therefore that further delay, 

until all RH SIPs are submitted and fully approved, is unwarranted and inconsistent with the key 

objective to protect visibility. 

Section 110(a)(2)(d)(i)(II) directs EPA to evaluate the SIP of a state for adequate controls 

on emissions from the state to prevent interference with measures “required to be included in the 

applicable state implementation plan” of other states. Thus, this evaluation is supposed to 

consider what other states should have in their SIPs as of this point in time, and is not limited by 

the fact that other states may or may not have made the required RH SIP submission, nor by the 

fact that we may or may not have approved those RH SIP submissions at this point in time. 

Instead, we must evaluate the state’s section 110(a)(2)(D)(i)(II) submission in light of the 

programs that states are required to have, and that clearly includes the RH program required in 

other states. As discussed above, we believe that one means to evaluate this issue is to determine 

whether the level of controls in the SIP are consistent with the expectations for controls at New 

Mexico sources relied upon by other states in the development of their own respective visibility 

programs and consistent with the needs for emissions reductions that we ourselves conclude are 

needed for purposes of the RH program. 

Comment: The proposed FIP requires exceedingly stringent and expensive compliance 

obligations that are not adequately legally supported because the proposed FIP fails to 

adequately satisfy the interstate transport provisions of Section 110(a)(2)(D)(i) of the CAA or the 

provisions of the RHR. 

Response: We disagree that the FIP is not legally supported. The FIP satisfies provisions 

in both section 110(a)(2)(D)(i)(II) of the CAA regarding interstate transport of pollutants 

affecting visibility in other states and for the NOx BART determination for the SJGS, the RHR. 
98 

We find that the emissions from the SJGS in New Mexico are interfering with the other 

states’ required measures to protect visibility. Therefore, we are imposing through the FIP, 

specific emission limits upon the SJGS to prevent such interference. We are imposing an SO2

limit and a NOx limit. To provide greater certainty to the SJGS that controls needed to prevent 

interference with other states’ visibility programs, as well as the controls needed to meet the 

RHR’s BART requirements, do not conflict with each other and end up imposing unnecessary 

greater costs upon the SJGS, we are imposing a BART NOx emission limit that meets both 

requirements at this time, rather than postponing action on this RH SIP requirement. We are 

only determining that the SJGS is subject to BART and promulgating the NOx BART FIP for the 

SJGS. We are not addressing whether New Mexico has met the requirements of the RHR for 

any other sources; we are not addressing whether the SJGS is meeting the RH BART 

requirements for any other pollutants; and we will address those requirements in later actions. 

We have the specific authority to promulgate a FIP imposing a NOx BART emission 

limitation upon the SJGS because we previously found that New Mexico had failed to submit a 

complete RH SIP by December 17, 2007. 74 FR 2392 (January 15, 2009). This finding started a 

two year clock for the promulgation of a RH FIP by EPA or the approval of a complete RH SIP 

from New Mexico. CAA section 110(c)(1). The FIP obligation imposed upon us became 

effective on February 15, 2011. Part of that FIP obligation includes making a NOx BART 

determination for the SJGS. To prevent a possible conflict between a NOx visibility transport 

emission limitation FIP for the SJGS and the NOx RH BART emission limitation FIP for the 

SJGS, we chose to promulgate now, rather than later, the NOx RH BART determination for the 

SJGS. We are combining the requirements of section 110(a)(2)(D)(i)(II) for NOx with a NOx 

BART evaluation (40 CFR 51.308) to be efficient and provide greater certainty to the source as 

to the appropriate NOx controls needed to meet those two separate but related requirements. 

This FIP also will impose a federally enforceable limit on the emissions of SO2 from the 

SJGS based upon the WRAP determination of each member state’s contribution to visibility 

impairment of SO2 emissions, of which New Mexico is a member. The SJGS’s existing SO2

permit does not provide the necessary emission limits and enforceable mechanisms to ensure the 

SO2 emissions used in the WRAP photochemical modeling for the SJGS units will be met. 

Therefore, we assumed the SO2 emission limit used in the WRAP modeling and, by this action, 

make it enforceable. This is necessary to ensure that New Mexico sources do not interfere with 

efforts to protect visibility in other states pursuant to the requirements of section 

110(a)(2)(D)(i)(II) of the CAA. 

Comment: One commenter argued that EPA took too narrow an interpretation of the 

term “interfere” in the visibility protection context of Section 110(a)(2)(D)(i)(II) for New 

Mexico, and that EPA should account for a broader range of causes of visibility impairment 

when considering regulating interference with other states’ visibility. According to the 

commenter, EPA’s action should consider future growth in emissions from area sources such as 

oil and gas development as part of evaluating interference with the visibility programs required 

in other states’ SIPs because the proposed New Mexico RH SIP already reduces NOx emissions 

sufficiently. The commenter also argued that pollutants other than NOx cause interference with 

other states’ visibility programs and should be considered instead of reducing NOx emissions 
99 

under BART because the commenter believes NOx emissions contribute a minor portion to 

overall visibility impairment. 

Response: We disagree with the assertion that we took too narrow a view of the term 

“interfere” in Section 110(a)(2)(D)(i)(II). In the FIP proposed and finalized in this action, we are 

concluding that the New Mexico SIP contains adequate provisions to prevent such impacts on 

the visibility programs of other states, except for the emissions from the SJGS. By promulgating 

a FIP to impose NOx and SO2 emission limits necessary at the SJGS to prevent such 

interference, as well as to meet the requirement for BART for NOx for this same source, EPA is 

addressing the requirements of the statute. In reaching this conclusion, we considered the term 

“interfere” based upon the facts, information, and data available to the Agency at this time. 

As we discuss in our proposal, we relied on WRAP modeling to determine the 

appropriate emission limits for sources in New Mexico in order to determine if New Mexico’s 

emissions were interfering with other state visibility SIPs. The states in the West, including New 

Mexico, worked together through the WRAP to determine their contribution to visibility 

impairment at the relevant federal Class I areas in the region and the emissions reductions from 

each State needed to attain the reasonable progress goals for each area. Western states are 

relying on the WRAP assumed reduction in emissions levels modeled for sources in New 

Mexico including the SJGS in order to meet their RH reasonable progress goals. All of the 

sources except for SJGS met the WRAP assumed reduction in emissions levels modeled for New 

Mexico’s assigned contribution to the region’s visibility impairment of federal class I areas. 

Thus, we proposed a FIP to prevent emissions from New Mexico sources from interfering with 

other states’ measures to protect visibility, and to implement NOx and SO2 emission limits 

necessary at one source, the SJGS, to prevent such interference, as well as BART for NOx for 

this source. 

We determined that enacting a NOx BART determination for SJGS was necessary 

because the WRAP analyses showed that NOx emissions in general and SJGS NOx emissions, 

specifically, contribute significantly to haze in the West. SJGS is by far the largest source of 

NOx emissions in NM. Our FIP requires substantial reductions in NOx emissions from this 

source. We agree that oil and gas development can result in emissions that could have an impact 

on visibility due to increases in NOx emissions. However, we are basing our evaluation of the 

potential impacts of emissions from New Mexico sources on the WRAP analysis, and 

consideration of the sources that other states would have assumed that New Mexico intended to 

control as part of that modeling. The state’s initial submission for section 110(a)(2)(D)(i) 

indicated that the state intended to meet its obligations with respect to the visibility prong by 

means of the RH SIP. Therefore, we have examined the issue in light of what other states would 

have assumed such a SIP would achieve. Moreover, even if the impacts from the oil and gas 

sector were significant, this fact would not justify a decision to not act on the BART 

requirements for NOx for the SJGS, because NOx emissions from SJGS are a significant source 

of NOx emissions that interfere with other state’s required visibility programs. In addition, 

based on the facts and information currently available, we believe the most effective means of 

ensuring that emissions from New Mexico do not interfere with other states’ visibility programs 

is to require further and federally enforceable NOx reductions and federally enforceable SO2

limits at SJGS. 
100 

We also specifically disagree with the commenter’s statement that NOx emissions 

contribute only a minor portion to overall visibility impairment. As we noted in our proposal, 

our modeling indicates that the visibility impairment due to the SJGS’s emissions is primarily 

dominated by nitrate particulates. As our NOx BART modeling demonstrates, reducing NOx 

emissions from the SJGS will result in a 21.69 dv, cumulative improvement, across 16 Class I 

areas. As the RHR states, “States should consider a 1.0 deciview change or more from an 

individual source to ‘‘cause’’ visibility impairment, and a change of 0.5 deciviews to 

‘‘contribute’’ to impairment.”187 Therefore, we do not view a cumulative visibility impairment 

of 21.69 dv as an insignificant contribution. The commenter suggests we consider future growth 

in emissions from area sources such as oil and gas development as part of our control strategy. 

We agree with the commenter that oil and gas activity in New Mexico produces NOx and other 

emissions. We understand the WRAP is currently reviewing and refining the emissions 

inventory for this sector. We will address this matter further in our review of New Mexico’s RH 

SIP. 

2. BART Requirements 

Comment: One commenter states “EPA’s BART determination for the San Juan 

Generating Station contravenes EPA’s rules and conflicts with the structure and purpose of CAA 

Section 169A.” Following this comment, there appears a parenthetical “see” reference to 

comments that had been submitted from two other commenters. 

Response: The comment does not give any underlying rationale or facts for its assertion 

that our action contravenes our rules and conflicts with CAA Section 169A. We disagree with 

the statement, because the NOx BART determination for the SJGS was made in accordance with 

our rules and CAA requirements. The references to subsections of other submitted comments do 

not appear to match with the comments we had received. We cannot further evaluate or respond 

to this comment. In any event, the other comments are separately addressed in this document. 

Comment: One commenter states that our proposed rule must be withdrawn because it 

fails to justify implementation of a SCR BART limit. This commenter cites to a portion of 

American Corn Growers v. EPA, 291 F.3d 1, 19 (D.C. Cir. 2002), where the D.C. Circuit wrote 

of state’s having “broad authority over BART determinations.” The commenter also points to 

that court’s discussion of legislative history, where it stated that “...Congress intended the states 

to decide which sources impair visibility and what BART controls should apply to those 

sources.” Id. at 8. From this, the commenter states that the authority of states to establish BART 

cannot be constrained by us. 

Response: While a State has broad authority over a BART determination when it is the 

decision maker, we similarly have broad authority when promulgating a FIP. Because, as 

discussed earlier in this notice, New Mexico did not timely formulate and submit its BART 

determinations, we have the authority and responsibility to make a NOx BART determination for 

SJGS. 

 187 70 FR 39104, 39120. 
101 

Comment: One commenter argues that an evaluation of the amount of reasonable 

progress expected to be achieved in the Class I areas by other control measures is required before 

the amount of reasonable progress needed from BART at the SJGS should be determined. Under 

the CAA, BART is not expected to be the maximum degree of emissions reduction 

technologically feasible. In fact, it may be lower if reasonable progress from other CAA 

programs is sufficient. 

Response: We believe BART to be a severable piece of the RHR that can be evaluated 

on its own. BART can be a part of a reasonable progress strategy, and controls imposed under 

other CAA requirements can be considered to be BART, In fact, as we discuss elsewhere in our 

response to comments, we did evaluate the existing controls at the SJGS, but found them 

inadequate to satisfy NOx BART. However, there is not any requirement in the RHR that would 

require we first make an evaluation of reasonable progress prior to conducting a BART 

evaluation, nor is there any consideration of lessening the degree of a potential BART control in 

light of other CAA programs. 

Comment: One commenter alleges our proposed rule improperly requires BART for the 

San Juan Generating Station under Section 110 of the CAA and not Section 169A. While we 

propose to act under the “good neighbor” provision in Section 110 of the CAA, the commenter 

alleges, EPA “appears to selectively borrow” the BART requirement from the RH program 

established under Section 169A to do what “neither section could do alone.” One commenter 

states Congress intended BART to be one part of a “comprehensive, long-term strategy for 

addressing RH in Class I areas. The commenter asserts that BART is more stringent than 169A 

requires, because it is being used “out of context” in a limited Section 110 program designed to 

ensure one state does not interfere with another state’s air quality plans. The commenter feels 

the approach we use is a partial or piecemeal implementation of the RH program, which is 

contrary to the integrated, comprehensive decision-making that 169A envisions. Because 

requirements of Section 110 and the Section 169A were not kept separate from each other, the 

commenter feels our proposal is substantively and procedurally flawed and fails to properly 

implement the programs under both sections. 

Response: We are not requiring NOx BART for the SJGS under section 110 of the CAA. 

We are requiring NOx BART for the SJGS under section 169A and the RHR. Further, we 

disagree with the statement that BART requirements were selectively borrowed from the RH 

program or that any provisions were selectively borrowed or considered out of context. In 

making the BART determination, we first looked to RHR requirements and determined SJGS is 

BART eligible for NOx at each affected emissions unit. We then established BART for those 

units under the RH Rule and the Guidelines for BART Determinations found in Appendix Y of 

40 CFR Part 51. Because our BART determination is in accordance with the guidelines, it is not 

any more stringent due to the additional action under Section 110. Moreover, as discussed 

elsewhere, we do not agree our determination is procedurally or substantively flawed because it 

is not comprehensive enough. While other commenters have suggested that we should proceed 

to determine BART for other pollutants, we are finalizing a NOx BART determination for the 

SJGS and will address other RH requirements in a separate future action. Therefore, we do not 

agree that the action under Section 110 and the determination under Section 169A have created 

any conflict or flaw in the implementation of either program. 
102 

Comment: A commenter states that although a similar analytical approach is appropriate, 

the outcome of the BART analysis for the SJGS should differ from the proposed BART 

determination for the Four Corners Power Plant. Commenter agrees that a consistent method of 

analysis should apply. However, it disagrees that the outcomes of the analyses must be the same, 

given the meaningful differences between the two facilities. For example, the site congestion is 

a much greater concern at the SJGS than at Four Corners. EPA should reconsider the emission 

limit it assumed for San Juan in the site-specific, plant-wide manner employed by Region 9. 

Another commenter states the proposal fails to consider other BART-eligible sources or 

other emission control strategies. In addition, the commenter is concerned that our proposed FIP 

for the SJGS may have been inappropriately influenced by the FIP proposed for Four Corners 

Power Plant by Region 9. Although the overall analytical approach must be consistent, the 

commenter argues, the final determinations should be different to reflect the differences between 

those two facilities. 

Response: We agree with the commenters that a consistent method of analysis should 

apply for all BART evaluations, and we believe the use of the BART Guidelines ensures that 

occurs. However, we see no reason to conclude the outcomes of these analyses should be 

prejudged to necessarily have any relationship to each other. We note that the differences the 

first commenter mentions, such as existing pollution control equipment and site congestion, were 

factored into our SJGS NOx BART visibility modeling (baseline emissions) and cost evaluation, 

respectively. Also, concerning the amount of review time (e.g., comment period), our consent 

decree deadline prevents us from extending the comment period more than we already have, 

which was almost a month over our initial 60 day period. We disagree with the first commenter 

that we failed to properly consider the NOx emission limit the units of the SJGS can reliably 

attain. Elsewhere in our response to comments, we present detailed information that documents 

these units can reliably meet a NOx BART emission limit of 0.05 lbs/MMBtu. In our analysis, 

we see no information in the record that causes us to conclude there are any site specific issues 

that would prevent the units of the SJGS from attaining this emission limit. Lastly, as we discuss 

elsewhere in our response to comments, we have modified the compliance schedule. We find 

that compliance with the emission limits for the SJGS should be within 5 years of the effective 

date of our final rule. We note that the compliance schedule for the Four Corners Power Plant is 

now being analyzed under a “better than BART” scenario according to section 51.308(e)(2)-(3), 

which provides for a possibly longer time period for the installation of controls.188

Comment: The proposed FIP for SJGS is entirely inconsistent with the FIP proposed for 

six units in Oklahoma by EPA. Given the similarity of the BART determinations made by the 

state of Oklahoma and the BART determination prepared for San Juan by PNM’s consultant, and 

the significant difference between those determinations and EPA’s proposed FIP, commenter 

asks EPA to reconsider its BART analysis for SJGS using the method of analysis applied in 

Oklahoma. 

 188 Supplemental Proposed Rule of Source Specific Federal Implementation Plan for Implementing Best Available 

Retrofit Technology for Four Corners Power Plant: Navajo Nation, 76 FR 10530 
103 

Response: We disagree that the results (e.g., emission limits and controls) of our 

proposed NOx BART determinations for Oklahoma189 and the NOx BART determination we 

proposed for the SJGS should be similar. The cost of controls must be compared to the expected 

visibility benefits, and those benefits from the potential installation of SCR on sources in 

Oklahoma were predicted to be much less than what we expect to result from the installation of 

SCR at the SJGS. In fact, the visibility benefit (or lack thereof) from the installation of SCRs on 

the Oklahoma BART sources is so small that we did not see the need to refine the cost estimate 

by investigating the feasibility of a lower NOx emission limit. Our conclusion in no way implies 

we accepted the SCR cost estimate at face value— only that we did not see the need to refine it. 

With regard to the different BART compliance schedules between our proposals, we believed in 

SJGS’s case that the expected visibility benefits were so significant that the controls should be 

installed “as expeditiously as practicable.” 40 CFR 51.308(e)(1)(iv). As we discuss elsewhere 

in our response to comments, we have modified the compliance schedule. We are finalizing a 

schedule which requires compliance with the emission limits within 5 years – rather than 3 years 

– from the effective date of our final rule. 

Comment: Some commenters have stated that the proposed FIP does not satisfy other 

requirements of the RH Program. 

Response: We are acting on a portion of the State’s SIP revision addressing Interstate 

Transport requirements, specifically visibility. We are not acting upon a state RH SIP submittal. 

The only RH requirement on which we are acting is to make a NOx BART determination for the 

SJGS and promulgate a NOx BART FIP for the SJGS under the RHR. We have made clear in 

our proposal that we will later act on the rest of the RH requirements. 

Comment: One commenter states that the requirement to install SCR at the SJGS is a 

fatally flawed and unnecessary approach to RH reduction, and that the FIP is not consistent with 

the law, science, economics, or prudent engineering practice. 

Response: While we appreciate Commenter’s general concern about the control 

equipment for RH reduction, the Commenter did not provide any specific examples in the record 

to be able to adequately respond to this generalized statement. It should be noted that EPA’s 

action establishes emission limits that may be met with SCR but it does not mandate specific 

control equipment. 

Comment: A commenter states that our BART analysis should be only about visibility 

and not public health concerns, which can be misleading. 

Response: We agree with the commenter that our action should be, and in fact is, about 

protecting visibility. We derive our authority for this action both under section 

110(a)(2)(D)(i)(II) of the CAA and the RHR. In so doing, although we do note the ancillary 

public health benefits resulting from controlling the same pollutants that cause visibility, we have 

not considered those benefits in arriving at our decision. 

 189 Id. 
104 

3. Executive Orders Comments 

Comment: The MSR Public Power Agency (MSR) disagrees with our findings under the 

Unfunded Mandates Reform Act of 1995 that the proposed FIP does not contain a federal 

mandate that may result in expenditures by state, local, or tribal governments that exceed the 

inflation-adjusted threshold of $100 million ($100 million in 1995 dollars) or more in any one 

year thus triggering a written assessment of the costs and benefits of the proposed FIP. MSR 

believes that the cost of retrofitting the four units at the SJGS is closer to PNM’s estimated cost 

of $908 million. 

 

Response: The Unfunded Mandates Reform Act (UMRA) requires that Federal agencies 

assess the effects of Federal regulations on State, local, and tribal governments and the private 

sector. In particular, UMRA requires that agencies prepare a written statement to accompany 

any rulemaking that "includes any Federal mandate that may result in the expenditure by State, 

local, and tribal governments, in the aggregate, or by the private sector, of $100,000,000 or more 

(annually adjusted for inflation) in any one year" (Section 202(a)). Our revised cost estimate 

indicates that the Total Annual Cost is $39,265,670.190 Therefore, we have determined that we 

are below this threshold, even without adjusting it for inflation. In other words, even if the entire 

Total Annual Cost of the installation of SCRs on the units of the SJGS were ascribed to one 

entity, we do not believe the UMRA threshold would be triggered. 

Comment: Once commenter states that we should not ignore Executive Order 12866. 

Response: This action is not a “significant regulatory action” under the terms of 

Executive Order 12866, (58 FR 51735, October 4, 1993) as it only applies to one facility and is 

not a rule of general applicability. Therefore, this action is not subject to review under the 

Executive Order. 

Comment: One commenter states that the proposed rulemaking is contrary to Executive 

Order 13563 (Improving Regulation and Regulatory Review) of January 18, 2011 and as such 

we should consider the cost of promulgating the rule and take the least burdensome path among 

different options. 

Response: Executive Order 13563 is supplemental to and reaffirms the principles, 

structures, and definitions governing contemporary regulatory review that were established in 

Executive Order 12866 of September 30, 1993. The President issued the referenced Order on 

January 18, 2011, after we issued our proposed rulemaking. In general, the Order seeks to 

ensure the regulatory process is based on the best available science; allows for public 

participation and an open exchange of ideas; promotes predictability and reduces uncertainty; 

identifies and uses the best, most innovative, and least burdensome tools for achieving regulatory 

ends; and takes into account benefits and costs, both quantitative and qualitative. However, 

nothing in the Order shall be construed to impair or otherwise affect the authority granted by law 

to the Agency. Although this Order was issued after our proposed rulemaking, in our review 

process the cost of compliance was one of the elements addressed to ensure that the requirements 

to achieve the goals stated in the CAA were beneficial and not burdensome to the regulated 

 190 See Exhibit 1 RTC Revised Cost Analysis, lines 91, Cost Analysis Fox. 
105 

entity. Please refer elsewhere in our response to comments for a detailed analysis of the 

elements required by our regulations for BART determinations. 

Comment: The Navajo Nation EPA commented that the FIP proposal has tribal 

implications as specified in Executive Order 13175, and that consultation is required because of 

the impacts to Navajo workers, contractors, and subcontractors at San Juan Generating Station 

and the San Juan Mine. 

Response: Executive Order 13175, entitled ‘‘Consultation and Coordination with Indian 

Tribal Governments’’ (65 FR 67249, Nov. 9, 2000), relates to consultations with tribal 

governments by federal agencies. As directed by the Executive Order, EPA has recently issued a 

new policy entitled EPA Policy for Consultation and Coordination with Indian Tribes (May 4, 

2011), which re-establishes and clarifies EPA's process for consulting with tribes. We have 

concluded that this final rule does not have tribal implications, as specified in Executive Order 

13175, because this action does not impose federally enforceable emissions limitations on any 

source located on tribal lands, and neither imposes substantial direct compliance costs on tribal 

governments, nor preempts tribal law. However, in response to this comment, we engaged in 

government-to-government consultation at the request of the Navajo Nation regarding this rule 

and the Nation's previously submitted comments. 

4. Other General Legal Comments 

Comment: A number of commenters have requested that we should approve the New 

Mexico Interstate Transport SIP previously submitted in 2007 as it satisfies both our policy and 

our Consent Decree with WildEarth Guardians. Another commenter states that we have no 

sound basis in any event for disapproving New Mexico's SIP revision under the visibility clause 

of section110(a)(2)(D)(i)(II), as that SIP revision simply carries out our own guidance to the 

states. 

Another commenter stated that our proposal to adopt a FIP before NM completes its 

ongoing rulemaking process to adopt a RH SIP is premature and deprives the state of its 

significant discretion to establish and administer its own RH program. 

Response: We disagree that we should approve the SIP submitted in 2007 because it 

satisfies both our policy and the WEG Consent Decree. Our consent decree with WEG requires 

that by August 5, 2011, we must approve a SIP, promulgate a FIP, or approve a SIP in part with 

promulgation of a partial FIP for New Mexico to meet the requirement of section 

110(a)(2)(D)(i)(II) regarding interfering with measures in other states related to protection of 

visibility. As stated elsewhere in this notice, New Mexico’s 2007 submittal fails to meet this 

requirement. That SIP anticipated the timely submission of a substantive RH SIP, which was 

due by December 17, 2007, as the means of meeting this requirement. Because until recently 

that RH SIP was not submitted, we had no choice but to seek other means of satisfying our WEG 

consent decree deadline of August 5, 2011. 

Because states were late in their RH SIP submissions, on January 15, 2009, we published 

a ‘‘Finding of Failure to Submit State Implementation Plans Required by the 1999 regional haze 
106 

rule.’’ 74 FR 2392. In New Mexico’s case, this finding included sections 40 CFR 51.309(g) and 

40 CFR 51.309(d)(4). Section 51.309(d)(4)(vii) states: 

The implementation plan must contain any necessary long term strategies and BART 

requirements for stationary source PM and NOx emissions. Any such BART provisions may be 

submitted pursuant to either §51.308(e)(1) or §51.308(e)(2). 

This finding started a 2-year clock, which expired on January 15, 2011, for the 

promulgation of a RH FIP by us, unless those states, including New Mexico, made a RH SIP 

submission and we approved it. Therefore, we had full authority to promulgate a FIP for the 

State of New Mexico that included a NOx BART determination for the SJGS. In response to the 

second commenter, we do not view it as premature to take action on one element of the RH 

requirements at this time. We chose to exercise this authority to conduct a NOx BART review of 

the SJGS, as a partial route forward in satisfying our consent decree with WEG. 

Although we subsequently received the New Mexico submittal on July 5, 2011, we 

simply have arrived at a point where we do not have the time to stop our action, review that SIP, 

propose a rulemaking, take and address public comment, and promulgate a final action as 

defined in the consent decree. 

Comment: One commenter alleges that our statement that the SJGS is more than 30 

years old and needs to update its control equipment is inaccurate. 

Response: As explained elsewhere in this notice and our proposal, our data supports the 

need for the SJGS to retrofit their sources of emissions to meet the requirements of the CAA. 

Comment: One commenter argues that the Administrative Procedures Act is not 

adequate regarding impacts on small governmental entities. 

Response: This final rulemaking only addresses the disapproval of a portion of the SIP 

revision submitted by the State of New Mexico for the purpose of addressing the visibility prong 

of the Interstate Transport rule. See elsewhere in our response to comments for a detailed 

description of what is addressed in this Final Action. Therefore, comments related to the 

Administrative Procedures Act and how is not adequate regarding the impacts to small 

businesses are outside the scope of our proposed action. 

Comment: One commenter alleges that “Federal forces” create air regulations to solve a 

problem that doesn’t exist and threatens our county's livelihood. 

Response: This rulemaking is the result of CAA requirements that a SIP must have 

adequate provisions to prohibit emissions from adversely affecting another state’s air quality 

through interstate transport and that certain facilities install BART to protect visibility in national 

parks and wilderness areas. The visibility problem in these areas of great scenic importance has 

been recognized as a significant issue by policymakers from Federal, State and local agencies, 

industry and environmental organizations.191 Technical data, that are part of the record, evidence 

 191 See RHR, 64 FR 35714 (July 1, 1999). 
107 

that emissions of SO2 and NOx from the SJGS are interfering with efforts to protect visibility in 

other states, as well as impacting Class I areas within NM. 

P. Modeling Comments 

Comment: The San Juan Coal Company (SJCC) commented that EPA compared the 

emission levels of both New Mexico’s 2018 projected emissions and New Mexico’s current 

emissions that were developed for the WRAP photochemical modeling. EPA relied upon that 

comparison to determine that all of the sources in New Mexico are achieving the emission levels 

assumed by WRAP in its modeling except for the SJGS. SJCC alleged that EPA’s summary of 

that analysis presents no relevant data to support the Agency’s conclusion. Because the WRAP 

inventories are so extensive and difficult to research and review, EPA at a minimum should have 

provided copies of the State’s emissions inventories that were reviewed and the specific 

emissions data for SJGS that supports EPA’s conclusion. SJCC stated that EPA should not have 

put the burden of interpreting the WRAP technical support documents on the reader. 

Furthermore, in light of the substantial number and different types of emission sources 

throughout New Mexico, our conclusion is suspect. EPA must produce the specific emissions 

information for SJGS and for all other emission sources in the State, which isolates SJGS as the 

only reason for New Mexico’s interstate interference with visibility protection. 

Response: While we did point in the proposed rule to the WRAP website as a reference 

for the emission data that we reviewed and compared, we also developed a complete TSD, and 

included some of the spreadsheets for 2002, i.e., the “current” emissions and for the projected 

2018 emissions, in the docket for the proposed rule. Specifically, in Chapters 2 (BART Eligible 

Determination), 3 (Subject-to-BART Determination) and 4 (BART Guidelines and Modeling 

Protocols) of the TSD we discussed the WRAP’s CALPUFF screening modeling and why we 

identified SJGS as the only source in New Mexico that was not sufficiently controlled to 

eliminate interference with the visibility programs of other states. 

Our review and the State’s first focused on BART eligible sources because these are 

sources first considered for control in State Regional Haze Plans. In May 2006, NMED 

conducted an internal review of sources that met the regulatory definition “BART-eligible” 

source set forth in 40 CFR 51.301.192 The State identified 11 facilities that were BARTeligible. The WRAP performed the initial BART CALPUFF screening modeling for the state of 

New Mexico. The modeling was performed for each of the 11 sources and their combined SO2, 

NOx, and PM emissions. The purpose of this BART CALPUFF screening modeling was to 

determine whether any of these 11 sources “emits any air pollutant which may reasonably be 

anticipated to cause or contribute to any impairment of visibility” in any Federal Class I area. 

Consistent with the BART Guidelines, this WRAP initial BART CALPUFF screening modeling 

evaluated the 98th percentile visibility impacts at any Class I area from each of these 11 sources. 

Using 0.5 dv as the significance threshold, of the 11 sources, only one source’s visibility impacts 

at any Class I area due to its combined SO2, NOx, and PM emissions was above the 0.5 dv 

significance threshold (i.e., PNM’s SJGS Boilers #1-4). Of the 10 other sources, none were 

 192 BART-eligible sources are those sources, which have the potential to emit 250 tons or more of a visibilityimpairing air pollutant, that were put in place between August 7, 1962 and August 7, 1977, and whose operations 

fall within one or more of 26 specifically listed source categories. 
108 

above a 0.33 dv impact. Consequently, only the PNM’s SJGS Boilers #1-4 were determined by 

NMED to be emitting pollutants contributing to impairment of visibility in any Federal Class I 

area and therefore were subject to BART. We note in the BART Guidelines that states (and by 

extension EPA when promulgating a FIP) have flexibility in determining an appropriate 

threshold for determining whether a source contributes to any visibility impairment for the 

purposes of BART. However, this threshold should not be higher than 0.5 dv. As discussed in 

the TSD, based on modeling sensitivities, even if we re-ran the BART CALPUFF screening 

modeling for the other 10 sources, the conclusion reached by both New Mexico and EPA would 

be unlikely to change. Therefore, these facilities are not subject to BART. As such, New 

Mexico did not propose additional controls for these facilities nor did the WRAP modeling 

include additional reductions for these 10 sources. These 10 sources are sufficiently controlled 

to eliminate interference with other states’ visibility programs. 

Our review and the States’ particularly focused on sources potentially subject to BART 

because in developing RH plans, sources subject to BART were a particular focus for States in 

projecting emission reductions. After the running of the WRAP initial BART CALPUFF 

screening modeling that identified the one source subject to BART, the WRAP ran 

photochemical modeling for all the sources in the entire region for the base year (2002) and the 

future year (2018). The WRAP participating states based their RH reasonable progress goals 

and long-term strategies upon this photochemical modeling and its inputs, particularly the future 

year projections for all of the sources in the region. All the participating WRAP states agreed to 

the emissions input for the base and future years. These states are relying upon the WRAP 

photochemical modeling’s future year projected emissions from all the sources in the region to 

establish their Reasonable Progress Goals. In consultation with New Mexico, the WRAP 

photochemical modeling included anticipated reductions in emissions at the SJGS. Through the 

WRAP consultation process, New Mexico provided the anticipated future year projected 

emissions from SJGS a to be 0.27 lb/MMBtu for units 1 and 3 and 0.28 lb/MMBtu for units 2 

and 4. Other WRAP states are relying on the levels modeled for the SJGS units, developed in 

consultation, in their demonstration of reasonable progress plans towards natural visibility 

conditions. New Mexico, however, did not adopt limits to insure that the levels assumed for 

SJGS in the WRAP modeling would be achieved. This discrepancy from what other States 

assumed is a particular concern because, as discussed previously, SJGS, was found in the BART 

modeling to, by itself, contribute significantly to visibility impairment. 

Our review of the WRAP BART CALPUFF screening modeling and analysis for sources 

potentially subject to BART in New Mexico is well documented in the TSD as described above. 

In addition, as part of our review, we evaluated the methodologies used by WRAP in developing 

their future year emissions projections for the WRAP photochemical modeling. The 

spreadsheets on the WRAP website document the future year projections used by the WRAP in 

their photochemical modeling. Except for SJGS, the WRAP projections in the photochemical 

modeling were supported by accepted and agreed upon emissions inventory projection 

methodologies in combination with regulations or other limitations and were based on the data 

available at the time. This information was publicly available for review on the WRAP website. 

Therefore, we adequately explained why our action is limited to the SJGS. In addition, 

the information we relied on to reach our conclusions is available to the public and was validated 
109 

by a voluntary group of state, federal and local air agencies dealing with regional air quality 

issues. Relying on WRAP data provides consistency of analyses throughout the Western states, 

and assures that our decisions are not arbitrary. Thus, EPA’s decision is based on data to support 

that the SJGS is the only source that requires the enforceable measures in this action to ensure 

reductions needed to meet the anticipated level of emissions relied upon in the WRAP modeling. 

 Comment: SJCC contests EPA’s conclusion that SJGS is the only source in New 

Mexico continuing to contribute to visibility impairment in other states because EPA reached 

this conclusion without comparing all the New Mexico sources’ current emissions in the WRAP 

modeling with their projected 2018 emissions. In addition, EPA did not use the annual 

emissions value in the “core emission inventories” presented in the WRAP modeling for the 

SJGS reported in tons per year (tpy). The commenter states that EPA performed its comparison 

by using emission rates in terms of units of pounds per British thermal unit (lbs/MMBtu) for the 

SJGS. The commenter continues to allege that in addition to using lbs/MMBtu rather than the 

annual emissions, EPA apparently, further adjusted SJGS’s current emissions that were in the 

WRAP modeling to account for a shorter averaging time because the WRAP averaging periods 

were unenforceable. This methodology was not applied to any other source. SJCC claims that if 

EPA had applied this methodology to the other New Mexico sources, it is extremely likely that 

EPA would have needed to adjust their current levels as well. Therefore, EPA’s comparison 

analysis is flawed, and EPA cannot assume that the SJGS is the only source in the State (or 

within the WRAP region for that matter) whose current emissions have not been specified on a 

basis that is consistent with how projected 2018 emissions were expressed for the WRAP 

modeling. 

Response: As discussed in our proposal and elsewhere in this notice, the analysis 

conducted by the WRAP provides an appropriate means for evaluating whether emissions from 

sources in a state are interfering with the visibility programs of other states, as contemplated in 

section 110(a)(2)(D)(i) of the Act. In developing their visibility projections using 

photochemical grid modeling, the WRAP states assumed a certain level of emissions from 

sources within New Mexico. The visibility projection modeling was in turn used by the states to 

establish their own respective reasonable progress goals. We evaluated the planned emission 

reductions from point sources in New Mexico assumed in the WRAP 2018 modeling. But for 

SJGS, the WRAP projections were supported by accepted and agreed upon emissions inventory 

projection methodologies and/or regulations or other limitations and were based on the data 

available at the time. As a result of the initial BART analysis performed by the WRAP, 

identifying SJGS as subject-to-BART, and consultation with New Mexico, the WRAP 

photochemical modeling included anticipated reductions in emissions at the SJGS. The 

reductions at SJGS were the only additional reductions that other states relied upon occurring 

that NMED would require in their RH/BART SIP. The WRAP’s photochemical modeling that 

was performed to yield daily (24-hour) visibility impairment impacts adjusted the future year 

NOx emissions from SJGS after input from NMED and PNM to 0.27 lb/MMBtu for units 1 and 

3 and 0.28 lb/MMBtu for units 2 and 4. 

PNM has subsequently indicated that they cannot meet these relied-upon emission rates 

without installing additional control equipment and the actual achievable emission rate is 
110 

approximately 0.30 lb of NOx/MMBtu on a longer-term basis (30 day rolling average) as 

currently reflected in their permit and 0.33 lb of NOx/MMBtu on a shorter-term basis. Clearly, 

the difference between what was assumed by the WRAP and what is actually being achieved and 

is enforceable should not be ignored. 

We disagree that our use of lbs/MMBtu versus the annual emissions rate compromised 

our evaluation. There is no compromise in integrity using the lbs/MMBtu versus using an annual 

emission rate, since the annual NOx emission rate for each EGU in the WRAP photochemical 

modeling is calculated using the short term emission rate of lbs/MMBtu multiplied with the heat 

input and hours of operation. In the future case photochemical modeling for most sources, the 

actual base emissions from 2002 were projected to the future using differing techniques to 

project the amount of growth and yield an estimate of the future emissions, taking into account 

the source type, any applicable regulations and limitations, and data available at the time.. As 

discussed in another response to comment, the WRAP modeling was conducted in a 

collaborative effort, and the participating states agreed with these methodologies for generating 

the future year emission inventories. To apply the same exact procedures in calculating future 

emissions that were applied to the SJGS to all other sources in New Mexico would be 

inconsistent with the methodology that the WRAP used. We used the same methodology to 

calculate emissions for EGU’s that were installing controls as the WRAP did for other EGUs 

installing controls. We used the short-term 0.33 lb/MMBtu emission rate as it directly relates to 

the averaging period for evaluating the visibility impairment, which is daily. For EGUs, the 

WRAP utilized a forecasting technique to yield 2018 emission estimates by applying a growth 

factor to the 2002 firing rate up to a capacity threshold of 0.85193 For NOx and SOx emissions 

from EGUs, the WRAP also used data from 2004 to be representative of emission rates for 2018. 

However, for EGU sources where the installation of controls was anticipated, such as the SJGS, 

they utilized the short-term emission factor that would result from the addition of controls (lb of 

pollutant per MMBtu) and then multiplied by the heat input to yield an annual tpy value that was 

reported in the WRAP’s emission spreadsheets. While the commenter is correct that the 

WRAP’s spreadsheets for photochemical modeling report data is in tpy, the WRAP calculation 

method uses the same basis for calculation that we used in our analysis, a lb of pollutant per 

MMBtu. We did our emission calculations for the SJGS using the same methodologies as the 

WRAP for other EGUs installing controls and, therefore, disagree with the commenter’s 

allegation that the SJGS were calculated unfairly. 

We disagree with the characterization that we adjusted the SJGS current emissions in the 

WRAP. From the comment it is unclear if the commenter’s concerns were just about emission 

rate/calculations for the photochemical modeling or the CALPUFF modeling. Because the 

comment is unclear, we have addressed their comment for both types of modeling. At issue is 

the emission rate that needs to be calculated from the SJGS in order to determine visibility 

impacts from the facility. For the CALPUFF modeling, the July 2005 BART rules recommend 

using the actual 24-hour maximum emission rate over the last several years as the basis for the 

baseline emissions, and when a source is controlled in the future the emission rate that would 

represent a maximum 24-hour potential emission rate after install of controls is used for the 

 193 Document that was included in our proposal docket, “Developing the WRAP Point and Area Source Emissions 

Projections for the 2018 Reasonable Progress Milestone for Regional Haze Planning”, Paula G. Fields, Martinus E. 

Wolf, Tom Moore, Lee Gribovicz. 
111 

future control scenario. Therefore, the values used in the CALPUFF modeling pursuant to EPA 

regulation and guidance are a short-term (24-hour) emission rate to reflect visibility impairment 

impacts. For the baseline, we took the existing enforceable permit level, which is a 30-day 

average and converted it to a 24-hour maximum emission rate to use in CALPUFF to determine 

the visibility impacts from the SJGS. PNM and NMED’s CALPUFF modeling, conducted to 

estimate daily visibility impairment at Class I areas for the baseline conditions, utilized an 

emission factor rate of 0.33 lb/MMBtu as the level that they could show compliance on a shortterm basis.194 We utilized the same emission rate in our CALPUFF modeling of the base case 

visibility impacts. 

In the photochemical modeling, the emission rate used in the baseline inventory was 

based on a NOx emission rate of 0.27 or 0.28 (depending on the boiler Unit) and a 0.33 

lb/MMBtu based rate as the maximum 24-hour emission rate in the CALPUFF modeling. We 

also note that these baseline emission rates were used by the state in consultation. In summary 

on this issue, EPA believes the commenter did not fully understand how emission rates were 

modeled for the two modeling platforms in comparison to how the WRAP calculated future year 

emission rates for EGUs, and we believe we have followed our regulations and guidance in 

accurately assessing the impacts with appropriate emission rates. 

As part of our action for 110(a)(2)(D)(i) of the CAA, we are also setting a SO2 limit in 

our action to be protective of the 0.15 lb/MMBtu limit for SJGS units that was included in the 

WRAP photochemical modeling and relied upon by WRAP states. SJGS has installed control 

equipment that is achieving below this level currently, but does not have an enforceable limit that 

limits the SJGS units to 0.15 lb of SO2/MMBtu. 

Comment: The SJCC found the wording of EPA’s conclusion comparing New Mexico’s 

current emissions and projected 2018 emissions to be confusing. If all sources in New Mexico, 

other than SJGS are currently achieving projected 2018 emissions, as EPA asserts, then that 

means the only emissions reductions that will occur during the first RH planning period from all 

emission sources in New Mexico will be from SJGS, which SJCC asserts is incorrect. To 

support this interpretation, the SJCC turned to the New Mexico emissions inventories used in the 

WRAP modeling and noted that the WRAP modeling projects a reduction in NOx emissions of 

about 10,500 tpy from the SJGS by 2018. The SJCC notes that in comparison, the State’s (then) 

proposed RH SIP estimated that statewide NOx emissions will decrease by 64,814 tpy by 2018. 

Based upon these numbers and comparing them, the SJCC concludes that the statement that all 

sources in New Mexico, except SJGS, are achieving the emission levels assumed by the WRAP 

modeling is incorrect. Rather, the SJCC asserts, information shows that other New Mexico 

sources besides the SJGS could be “interfering” with other states’ measures to protect visibility. 

The SJCC concludes that although EPA’s interpretation of “interference” may be reasonable on 

its face, the application of its explanation of its meaning indicates otherwise. EPA’s explanation 

provides no credible justification for singling out the SJGS as the only New Mexico source of 

emissions that is interfering with other states’ visibility-protection measures. 

 194 NMED Proposed Regional Haze SIP, available at AppxA_NM_SJGS_NOxBARTDetermination_06212010.pdf 

and modeling files provided by NMED to EPA for Review June/July 2009 
112 

Response: The statement that other sources were achieving the necessary reductions may 

have been unclear. In developing its emissions inventory, WRAP states estimated the emissions 

growth and all reductions that were expected to occur from point, area, and other sources, from 

all regulatory requirements. For New Mexico point sources other than the SJGS, the current 

federally enforceable emission limits for these sources are consistent with those relied upon in 

the WRAP modeling. For the SJGS, the WRAP states considered the impact of the RH BART 

requirements. As discussed in our proposal and elsewhere in this notice, we evaluated the 

planned emission reductions from point sources in New Mexico assumed in the WRAP modeling 

and concluded that the SJGS was the only source in New Mexico that was expected to get 

reductions beyond the current, i.e., baseline levels, because that source was determined to be 

subject to BART. The 10,500 tpy NOx reduction mentioned by the commenter refers to the 

reduction in NOx emissions at the SJGS anticipated by the WRAP and included in the future 

case photochemical modeling. 

For other sources, such as the ones the SJCC points to as accounting for the remainder of 

their 64,814 total reduction of NOx emissions in New Mexico, the WRAP states considered 

other rules on the books, projected reductions from other federal rules (including those 

addressing mobile sources), national consent decrees, and mobile source fleet turnover, among 

other things. These projections were reviewed and agreed to by the WRAP states as a part of 

their joint development of a complete WRAP emission inventory in support of their RH SIPs, 

and were relied upon by the WRAP states as a part of the reasonable progress goals. The 

commenter is correct that other sources in New Mexico are projected to reduce their emissions as 

well. Those projections are based on the states’ best estimate of the growth of emissions from 

some sources and the future impact of all combined regulatory programs. We conclude, for the 

purpose of satisfying section 110(a)(2)(D)(i)(II), those projections were reasonable and 

adequately incorporated into the WRAP modeling. 

As to the comment on how we defined “interference” in the context of CAA 

§110(a)(2)(D)(i)(II), please refer to our response to comments to legal issues (Section O.1 of this 

notice), where we have a full response as to how we view the term “interfere” in the context of 

the interstate transport requirements of the CAA. In that response we state that by promulgating 

a FIP to impose NOx and SO2 emission limits necessary at the SJGS to prevent such 

interference, as well as to meet the requirement for BART for NOx for this same source, EPA is 

addressing the requirements of the CAA. In reaching this conclusion, we considered the term 

“interfere” based upon the facts, information, and data available to EPA at this time. 

Comment: PNM commented that our choice of an SO2 baseline and future emission rate 

of 0.15 lbs/MMBtu was incorrect, and that an SO2 emission rate of 0.18 lbs/MMBtu is more 

appropriate. PNM alleges that this is based on the current, federally enforceable emission limit. 

PNM asserts that our justification for using the lower SO2 rate is that the lower rate is expected 

in the future. The commenter argues that utilizing the current SO2 limit is the more appropriate 

modeling method even though the use of the current limit would actually result in higher 

expected visibility improvements. 

Response: We conducted CALPUFF visibility modeling to analyze the impacts on 

visibility impairment from the NOx BART proposed controls. Due to the nonlinear nature and 
113 

complexity of atmospheric chemistry and chemical transformation among pollutants, all relevant 

pollutants should be modeled together to predict the total visibility impact at each Class I area 

receptor. 195 In order to estimate the benefits from the NOx BART proposed controls, we 

included the SO2 emissions as relied upon in the WRAP modeling in our CALPUFF modeling. 

The SO2 emission limit of 0.15 lb/MMBtu that we input into the NOx BART visibility modeling 

is based upon what was relied upon in the WRAP modeling. Our FIP makes this WRAP-relied 

upon SO2 limit of 0.15 lb/MMBtu federally enforceable. PNM’s requested baseline emission 

rate of 0.18 lb/MMBtu of SO2 is not what was relied upon in the WRAP modeling. 

Per EPA’s BART Guidelines, maximum actual emissions should be utilized in the 

visibility modeling of the base case, and all installed control technology should be considered. 

Future case modeling should include post control maximum emission rates. 196 We note that the 

SJGS currently has SO2 control technology installed and has current actual SO2 emissions below 

our proposed FIP limit. As a result, the facility will not have to install additional controls to 

meet our SO2 FIP limit. As we are setting the 0.15 lb/MMBtu SO2 emission limit in the FIP for 

SJGS, we modeled an emission rate of 0.15 lb/MMBtu for SO2 for both the baseline (current) 

and control (future) cases in estimating the anticipated visibility improvement due to installation 

of the NOx BART proposed controls. By holding the SO2 emissions constant in the revised 

baseline (current) and future (control) cases, the modeled predicted improvements in visibility 

due to the NOx BART proposed controls are kept separate from any potential changes in 

visibility due to changes in SO2 emissions. This means the final CALPUFF analysis reflects 

only the benefits due to the additional NOx reductions beyond the baseline. This also reflects the 

SJGS’s flexibility to increase its SO2 emissions up to the SO2 FIP limit of 0.15 lb/MMBtu. It 

provides a more representative estimate of anticipated visibility improvements from installation 

of NOx controls. 

Comment: A commenter disagrees with the general modeling approach and assumptions 

relied upon in EPA’s modeling analysis. The commenter contends that we performed numerous 

different visibility models and chose the one with the highest visibility improvements, even 

though the chosen model results are the least consistent and the least realistic of the modeling 

runs prepared. The commenter claims that EPA’s chosen value suggests that visibility 

improvements associated with installing SCRs at SJGS will be three times higher than the model 

that would assume more realistic, site-specific background ammonia concentrations and the 

Method 6 post-processing that has been relied upon by PNM, NMED, and WRAP and by EPA 

itself with regard to SO2 (by relying on the WRAP modeling). The commenter argues that 

EPA’s rejection of PNM’s modeling is unjustified and unnecessarily inflates the expected 

visibility improvements associated with SCRs. The commenter states that EPA did not raise any 

 195 Memo from Joseph Paisie (Geographic Strategies Group, OAQPS) to Kay Prince (Branch Chief EPA Region 4) 

on Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations, 

July 19, 2006 

196 Page 39129 of BART Rule, “We believe the maximum 24hour modeled impact can be an appropriate measure 

in determining the degree of visibility improvement expected from BART reductions (or for BART applicability)”, 

Pages 39107-3918 of BART Rule For assessing the fifth factor, the degree of improvement in visibility from 

various BART control options, the States may run CALPUFF or another appropriate dispersion model to predict 

visibility impacts. Scenarios would be run for the pre-controlled and post-controlled emission rates for each of the 

BART control options under review. The maximum 24-hour emission rates would be modeled for a period of three 

or five years of meteorological data. 
114 

of its concerns to PNM or NMED until the issuance of the proposed FIP despite discussions with 

NMED over several years regarding proper modeling techniques. 

Response: This comment is incorrect. In January 2010, NMED proposed as NOx 

BART, the installation of SCR on the four units at SJGS and relied upon modeling much of 

which was completed in the 2006-2007 timeframe. SCR is generally considered the most 

stringent control technology available for NOx. The Guidelines for BART Determinations under 

the Regional Haze Rule’s modeling guidelines in 40 CFR Part 51 App. Y, IV. D. 5 indicate that 

selection of the most stringent controls available may allow a source or the state agency to skip 

conducting visibility impairment modeling. Therefore, because NMED selected SCR, the most 

stringent control generally available, consistent with our RHR requirements (Step 1, Number 9 in 

the Guidelines), we did not perform a close review of the modeling in the State’s proposal during 

the State’s public process. Unfortunately, NMED decided not to finalize their proposal and then 

withdrew it from further state rulemaking in May 2010. 

When we developed the proposed FIP for NOx BART, we conducted our own visibility 

impact analysis (the degree of visibility improvement reasonably anticipated due to NOx BART 

at SJGS). In conducting modeling for our proposed NOx BART FIP, we utilized current 

practices and model versions that were acceptable to us at the time they were conducted in the 

latter half of 2010. In order to minimize technical concerns with the CALPUFF modeling 

system version, modeling options selected in CALMET, calculation of emissions (including 

sulfuric acid mist), and background ammonia levels employed by PNM, we remodeled visibility 

impacts using the CALPUFF version that we have determined to be appropriate for regulatory 

purposes. 

We used the EPA current acceptable versions of the CALPUFF (v. 5.8) modeling system 

which is composed of CALPUFF version 5.8, and CALMET version 5.8. We used CALPOST 

version 6.221 that was approved by the Federal Land Managers to allow for application of the 

revised IMPROVE equation (“Method 8”). Some problems have been identified in the 

CALPUFF modeling system (v6.2111) since the original WRAP CALPUFF screening modeling 

was conducted which is also the version used by PNM’s contractors and NMED. 197 A detailed 

discussion of CALPUFF model versions and the version approved for regulatory action is 

included in response to a separate comment. PNM’s CALMET modeling utilized radii of 

influence values inconsistent with EPA/FLM guidance, and did not follow the EPA/FLM 

guidance about including upper air observational data198. Refer to Table 4-5 of the TSD for an 

 197 “CALPUFF: Status and Update” , Dennis Atkinson, Presentation at Regional/State/Local Modelers Workshop, 

May 16, 2007. 

(http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/archive/2007/presentations/Wednesday%20-

%20May%2016%202007/CALPUFF_status_update.pdf); EPA report, “Assessment of the “VISTAS” Version of 

the CALPUFF Modeling System”, EPA-454/R-08-007, August 2008 available at 

(http://www.epa.gov/ttn/scram/reports/calpuff_vistas_assessment_report_final.pdf); “CALPUFF Regulatory 

Update”, Roger W. Brode, Presentation at Regional/State/Local Modelers Workshop, June 10-12, 2008, 

available at 

(http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/archive/2008/presentations/BRODE_CA.pdf

). 

198 Memorandum from Tyler Fox (EPA OAQPS) “Clarification on EPA-FLM Recommended Settings for 

CALMET,” August 31, 2009 (http://www.epa.gov/ttn/scram/CALMET%20CLARIFICATION.pdf) 
115 

overview of selected CALMET settings used by NMED/PNM compared to EPA. In estimating 

emissions of sulfuric acid from the facility, we used calculations by the NPS submitted to NMED 

in response to the proposed Regional Haze SIP and later revised that differed from certain 

assumptions and methodology used by NMED and PNM to calculate the sulfuric acid 

emissions.199, 200 In particular, the amount of sulfuric acid produced during combustion, the rate 

of SO2 to SO3 oxidation from the SCR catalyst and the amount of sulfuric acid that penetrates 

through (or is lost to) the downstream equipment differed from PNM and NMED’s estimates. 

Refer to Section 6.1.3 of the TSD for a detailed discussion on the methodology we used to 

estimate sulfuric acid emissions from the facility We remodeled the visibility impacts of SJGS 

to address these issues with PNM and NMED’s modeling, utilizing an acceptable version of 

CALPUFF. In doing so, we maintain consistency with the most current modeling guidance EPA 

and the FLM representatives have provided to the states. 

We performed numerous modeling runs in order to evaluate the sensitivity of model 

results to the chosen model inputs and post processing methods to generally inform the process. 

The justification for selecting the revised IMPROVE equation (“Method 8”) over the original 

IMPROVE equation (“Method 6”) is discussed in a separate response to comment. Background 

ammonia concentrations are also discussed further in a separate response to comments. We 

disagree with the commenter’s assertion we simply picked the modeling results that best 

supported our position, without regard to consistency and/or realism. Every parameter and 

model input was evaluated and selected separately, based on accepted methodology of EPA and 

the FLM representatives, guidance and available data. During selection of model versions and 

inputs, EPA R6 staff conferred with other EPA modeling experts and FLM representatives on 

these modeling issues to ensure that our modeling would be done in accordance with current day 

CALPUFF modeling practices for visibility impairment analyses. A discussion of model 

selection and inputs was presented in our proposal and in the TSD and further discussed in this 

document. 

Results for all modeling scenarios are provided in the Appendix 3 to the TSD, entitled 

“EPA’s CALPUFF Visibility Modeling Results.” These results demonstrate the sensitivity of 

the model to underestimation of background ammonia and the sensitivity to the use of the 

original IMPROVE equation. Utilizing the different methods and different ammonia levels does 

result in different predicted impact levels, but the overall change in visibility impairment, i.e., the 

net visibility improvement, due to the proposed NOx BART FIP emission limit is a significant 

value in all cases. In other words, while the ammonia levels affect visibility improvement, 

throughout the range of ammonia background being modeled, the NOx BART controls adopted 

here result in significant and important visibility improvement. For example, our sensitivity 

modeling predicted significant visibility improvement at Mesa Verde due to the proposed NOx 

BART emission limit, ranging from 38 to 56% improvement, depending on the background 

ammonia and post-processing method selected. 

 199 Comments of the National Park Service and US Fish and Wildlife Service Regarding the New Mexico Regional 

Haze State Implementation Plan August 17, 2010 (http://www.nmenv.state.nm.us/aqb/reghaz/documents/FWSNPS_Comments-NewMexicoRegionalHazeSIP-17AUG2010.pdf) 200 Don Shepherd to Michael Feldman, EPA Region 6 (electronic mail) dated Nov. 1, 2010 – revised NPS 

calculations to correct for errors in penetration factors. 
116 

Comment: We received comments that alleged that our CALPUFF modeling analysis 

failed to fully and appropriately account for the visibility improvement already achieved by 

recent SO2 and NOx emission reductions from SJGS. PNM contracted with B&V to perform a 

BART analysis for the SJGS. The commenters claim that this analysis used EPA's BART 

guidelines and showed that the low NOx burners installed on all four units at SJGS during the 

environmental upgrade project between 2007 and 2009 meet the requirements for NOx BART. 

Response: Our technical modeling analysis accounted for the visibility improvements 

achieved by existing controls at the SJGS by incorporating the SO2 and NOx enforceable permit 

limits established under the March 10, 2005 consent decree between PNM and the Grand 

Canyon Trust, Sierra Club, and NMED (2005 Consent Decree) into the baseline emissions 

modeling scenario. Our analysis of the visibility improvements due to the installation of NOx 

controls as part of our proposal reflected the visibility improvement due to installation of 

additional NOx controls beyond those installed as required by the 2005 Consent Decree 

(completed in 2009). Furthermore, we note that neither NMED nor EPA reviewed or approved a 

NOx BART analysis including a CALPUFF modeling analysis performed by B&V prior to the 

installation of controls under the 2005 consent decree. Low-NOx burners do not satisfy the 

requirements for NOx BART for the SJGS; they are not supported by the NOx BART five-factor 

analysis. 

Comment: We received comments suggesting that modeling should be performed using 

an emission rate of 0.07lbs NOx/MMBtu, for operation of SCR, rather than the 0.05 lbs/MMBtu 

emission rate. 

Response: Our modeling of the visibility impacts and benefits of the installation of SCR 

as being NOx BART are based on the determination of the emission limit technically feasible 

and achievable at the SJGS. This determination is discussed in response to additional comments 

received on the emission limit achievable by SCR at SJGS. 

Comment: We received comments that claim that the installation of SCR at the SJGS 

would result in imperceptible visibility improvements. 

Response: We performed visibility modeling as part of the NOx BART determination 

analysis. A change of 1 deciview is generally regarded as a perceptible change in visibility (70 

FR 39118; July 6, 2005). Our modeling indicates that significant improvements in visibility are 

anticipated from the installation of SCR to satisfy NOx BART requirements. As discussed in the 

TSD, our visibility modeling shows that improvement due to installation of SCR is significant 

and at a level that is certainly perceptible, including a 3.11 dv improvement at Canyonlands and 

2.88 dv at Mesa Verde and an improvement of 1 deciview or greater at 7 other Class I areas. 

Installation of SCR will result in significant and perceptible visibility improvements at a number 

of Class I areas. 

Furthermore, in a situation where the installation of BART may not result in a perceptible 

improvement in visibility, the visibility benefit may still be significant. “Failing to consider lessthan-perceptible contributions to visibility impairment would ignore the CAA’s intent to have 

BART requirements apply to sources that contribute to, as well as cause, such impairment” (70 
117 

FR 128; RH Regulations and Guidelines for Best Available Retrofit Technology (BART) 

Determinations, July 6, 2005). Installation of SCR will result in significant and perceptible 

visibility improvements at a number of Class I areas. However, a perceptible visibility 

improvement is not a requirement of the BART determination as a visibility improvement that is 

not perceptible may still be determined to be significant 

Comment: A commenter asserted that EPA’s proposed reductions of NOx emissions 

from the SJGS, to satisfy the requirements of section 110(a)(2)(d)(i)(II) of the CAA, are 

excessive and not supported by the record. The commenter claimed that EPA failed to provide 

quantitative details on how those emissions reductions were calculated. Furthermore, the 

emission reductions achievable by EPA’s proposed NOx BART appear to be substantially more 

than the amount of reductions required for New Mexico to comply with its visibility-related 

obligation under section 110(a)(2)(D)(i)(II). The commenter alleges that EPA did not provide 

information on the extent that SJGS’s emissions must be adjusted and did not provide a 

straightforward, side-by-side comparison of SJGS’s “current” emissions with and without those 

emissions being adjusted by the Agency; thus, the actual amounts of the emissions 

“discrepancies” that EPA stresses in its preamble are unidentified. 

The commenter challenges EPA’s statement that those discrepancies are “significant” 

based on “changes in visibility projections” and states that EPA failed to provide modeling 

results quantifying the visibility impact associated with those emission “discrepancies.” The 

commenter states our “discrepancies” are not differences between SJGS’s projected emissions 

used in the WRAP modeling and an EPA-adjusted level of “current” emissions. Rather, those 

emissions “discrepancies” are the differences between SJGS’s current levels of NOx and SO2

emissions used in the WRAP modeling and their EPA-adjusted counterparts, i.e., current levels 

of those emissions adjusted to values that EPA believes should have been used in the modeling. 

The commenter questioned how, if New Mexico’s 2002 NOx emissions were 312,193 tpy 

(Plan02d) and SJGS corresponding emissions were 30,353 tpy of NOx, only the amount of 

EPA’s adjustment could significantly impact out-of-state visibility impairment when the State’s 

total NOx emissions will likely be at least 10-100 times greater than the “adjustment” amount. 

The commenter then indicated that it is impossible to independently evaluate the strength of our 

conclusion regarding the extent to which emissions from SJGS must be “adjusted,” because the 

specific numbers, which purportedly support that Agency conclusion, have not been provided. 

The commenter then indicated that a judgment of whether EPA’s “discrepancies” are significant 

cannot be evaluated until EPA identifies (1) the magnitudes of those discrepancies and (2) the 

resultant modeled difference in visibility impairment due to those discrepancies. 

The commenter alleges that at no time have we specified the amount of emissions 

reductions that may be necessary to satisfy New Mexico’s obligation under section 

110(a)(2)(D)(i)(II) of the CAA. The commenter estimated the amount of NOx reductions in the 

WRAP modeling for the SJGS as 10,590 tpy and then approximated the amount of NOx 

emission reductions from SJGS under EPA’s scheme to prevent New Mexico’s “interference” as 

approximately 2,200 tpy of NOx after considering the consent decree reductions of 8,411 tpy 

since 2002. They then commented that if SJGS’s current (Plan02d) 2002 NOx emissions are 

“adjusted” in accordance with EPA’s approach, those required emission reductions to reach 

SJGS’s projected level used in the WRAP modeling would increase by an unknown quantity, but 
118 

they then assumed that the discrepancy is 100% greater than 2,200 tpy, yielding an additional 

4,400 tpy NOx reduction needed by 2018 to prevent interference. Commenter indicated that 

EPA’s proposal under § 110(a)(2)(D)(i)(II) to retrofit SJGS’s generating units with SCR could 

achieve roughly 4 times the amount of NOx emission reductions actually required and EPA’s 

proposed NOx emission reductions from the SJGS are excessive. 

Response: We disagree with the assertion that EPA must separate the required NOx 

emission reductions required by SJGS to meet section 110(a)(2)(D)(i)(II) requirements from the 

NOx emission reductions required to meet the NOx BART determination for SJGS. EPA also 

disagrees that we are required to conduct a modeling analysis to determine if the NOx reductions 

necessary for SJGS to meet the 110(a)(2)(D)(i)(II) visibility requirement would result in 

significant visibility improvement. As we discuss elsewhere in this notice, there is no necessity 

that we must evaluate these requirements separately and no requirement that we perform a 

110(a)(2)(D)(i)(II) visibility analysis. See Legal response to comments, above, regarding our 

general authority and obligation to act on section 110(a)(2)(D)(i)(II) and RH SIP requirements. 

The commenter takes issue with the fact that we did not specifically quantify the 

difference in emissions between the WRAP modeling and what is being achieved by SJGS, and 

explain why the discrepancy was believed to be significant. We disagree. We provided in the 

proposal and TSD a full discussion of how the NOx emissions in the WRAP modeling were not 

being achieved by SJGS, and how NOx emissions relied upon in the WRAP modeling for the 

SJGS, and agreed upon during consultation, are not federally enforceable. Therefore, we are 

establishing federally enforceable NOx emission limits that will eliminate interstate interference 

and at the same time address the RH BART requirement for NOx for SJGS. The commenter 

then asserts that a side by side comparison should have been provided in tons/year. We disagree 

that is necessary to quantify this comparison in tons/years. The modeling for electric generating 

units (EGUs) may have been reported out as tons/year (tpy) in the WRAP emission modeling 

summary tables, but the WRAP actual modeling itself used a short-term emission rate (i.e., 

lb/MMBtu). See our other response to comment that addresses tpy versus lb/MMBtu modeled 

emissions in more detail. 

In the case of SJGS, the WRAP’s photochemical modeling that was performed to yield 

daily (24-hour) visibility impairment impacts included future emission estimates based on 

emission rates of 0.27 and 0.28 lb of NOx/MMBtu and 0.15 lb of SO2/MMBtu. After NMED’s 

consultation with other states, PNM indicated to the State that SJGS could not meet the two 

future WRAP emission rates for NOx without installing additional NOx controls. PNM claims 

that the actual emission rate was approximately 0.30 lb of NOx/MMBtu on a longer-term basis 

as reflected in the permit and 0.33 lb of NOx/MMBtu on a short-term basis as reflected in 

PNM’s visibility impact modeling for SJGS. PNM and NMED’s CALPUFF modeling, 

conducted to estimate daily visibility impairment at Class I areas, utilized an emission factor rate 

of 0.33 lb/MMBtu for estimation of daily impact as the level that they could show compliance on 

a short-term basis.201 

We did not model the difference between the current enforceable emission limits and 

those emission limits relied upon in the WRAP modeling for SJGS. We find that New Mexico 

 201 Id. 
119 

sources, other than the SJGS, are sufficiently controlled to eliminate interference with the 

visibility programs of other states because the federally enforceable emission limits for these 

sources are consistent with those relied upon in the WRAP modeling. The SO2 and NOx 

emissions relied upon in the WRAP modeling for the SJGS, however, are not federally 

enforceable. Therefore, we are establishing federally enforceable emission limits for SO2 and 

NOx for the SJGS to eliminate interference with the visibility programs of other states. There is 

no requirement to perform a 110(a)(2)(D)(i)(II) visibility analysis. 

We note that the 98% largest deciview impact we modeled using 0.33 lb/MMBtu NOx 

and 0.15 lb/MMBtu SO2 was 5.15dv at Mesa Verde Class I area. We also modeled visibility 

impacts using 0.33 lb/MMBtu NOx and 0.18 lb/MMBtu SO2 in our initial modeling to compare 

model results with those presented by PNM and NMED. We note that reducing SO2 emissions 

from 0.18 to 0.15 lb/MMBtu resulted in a minimal change in visibility impacts at all Class I 

areas (0.03 dv at Mesa Verde), demonstrating a limited sensitivity to changes in SO2 emissions 

compared to the large changes in visibility due to decreasing NOx emissions at SJGS, as shown 

in our modeling of the 0.05 lb of NOx/MMBtu emission rate (SCR case). The use of 0.15 

lb/MMBtu SO2 emission rate is discussed in a separate response to comment. Considering that 

the 0.33 lb/MMBtu NOx value is approximately 20% greater than the 0.27/0.28 rate, the 

significant visibility impacts, and the NOx sensitivity demonstrated by the modeling, it is clear 

this difference in emission rates can have a significant impact on visibility. Even on a long-term 

basis, the difference between relying upon 0.30 lb/MMBtu compared to the 0.27/0.28 lb/MMBtu 

would have a significant impact. Although the atmospheric chemistry is not strictly linear in 

this case, if modeled, the combined difference in NOx and SOx emission rates would likely 

result in an impact between several tenths of a deciview and 1 deciview. Clearly, the difference 

between what was assumed by the WRAP and what is actually being achieved by the SJGS 

should not be ignored. Since we determined a much lower emission rate for BART, we did not 

need to directly evaluate the impacts of just achieving the emission rate levels included in the 

WRAP modeling. 

The commenter claims that the SJGS total emissions in 2002 were approximately 10% of 

the statewide New Mexico NOx emission total. The commenter implies that the reductions 

found to be needed at SJGS are exceedingly small in comparison to the total State emissions and 

therefore should not be singled out for control. The commenter fails to consider the proximity of 

SJGS to Class I areas and the fact that its emissions are concentrated relative to the more diffuse 

emissions of many sources in the State, such as area and mobile sources. We conduct modeling 

to quantify visibility impairment impacts because sources that are close to a Class I area and 

have elevated stacks result in greater plume impact on the Class I area, and will have a greater 

impact on visibility impairment per ton of NOx, compared to a much greater tonnage of NOx 

emissions from a variety of sources that are 100s of kilometers away. Much of the New Mexico 

NOx emissions are spread throughout the state and nearer to the metropolitan areas of 

Albuquerque and Santa Fe and over 200 kms from Class I areas in other states, in comparison to 

the SJGS which is just 42 km from the Mesa Verde Class I area. Our modeling indicated that the 

SJGS had a very large impact in our baseline emissions modeling (5.15 deciviews at Mesa 

Verde) which highlights why we conduct modeling instead of analyzing emission ratios, which is 

apparently what the commenter erroneously implies we should do. 
120 

The commenter did not provide specific details or cite any guidance as to how EPA erred 

in estimating emissions for modeling. We disagree with the comments that we have unfairly 

adjusted the emission calculations to overstate the benefit of our proposal. We have conducted 

our calculations consistent with EPA methods and guidance, and the WRAP EGU modeling 

projections.202 As documented in our TSD, we used the most recent materials, including EPRI’s 

spreadsheets, and current EPA guidance to estimate emissions for our analyses and disagree with 

the commenter’s vague comment that we unfairly adjusted the emissions to what we thought 

they should be.

Comment: We received comments from the NPS and USFS supporting the reporting of 

the cumulative visibility impact of SJGS and the cumulative benefits of SCR. NPS and USFS 

believe it is appropriate to consider both the degree of visibility improvement in a given Class I 

area as well as the cumulative effects of improving visibility across all of the Class I areas 

affected. The BART guidelines do not consider the geographic extent of visibility impairment. 

NPS and USFS believe the most practical approach to this problem is to consider the cumulative 

impacts of a source on all Class I areas affected, as well as the cumulative benefits from reducing 

emissions. They state that cumulative benefits have been a factor in the BART determinations 

by Oregon and Wyoming, as well as EPA in its proposals for the Navajo Generating Station and 

the Four Corners Power Plant. They also note that the improvements in visibility impairment 

due to reductions in NOx emissions in other analyses have been largest at Class I areas other 

than the closest Class I area, therefore evaluation of all Class I areas within the modeling domain 

is appropriate. 

 

Several commenters were opposed to the use of a “cumulative deciviews” or “total” 

visibility improvement metric. These commenters claim that the ”cumulative deciviews” metric 

is misleading and that the modeling impact improvements would take place at different locations 

within a Class I area, within different Class I areas, and probably on different dates so a 

"cumulative deciviews" result would not be observed by one viewer. They continued that one 

viewer would not perceive visibility impacts in more than one Class I area simultaneously, or 

even within relatively short periods of time, in nearly every case. Furthermore, the visibility 

impacts to a region should not depend on the number of Class I areas present. The commenters 

state it is improper to consider a "cumulative" deciview improvement over more than one Class I 

area. 

The commenters also suggest that the use of a “total dv” metric is inconsistent with 

BART guidelines (40 CFR Part 51 Appendix Y, IV.D.5). The guidelines state that it is 

appropriate to model impacts at the nearest Class I area as well as other nearby Class I areas to 

determine where the impacts are greatest. Modeling at other Class I areas may be unwarranted if 

the highest modeled effects are observed at the nearest Class I area. The commenters claim the 

analysis should be focused on the visibility impacts at the most impacted area, not all areas. The 

commenters add that states have already successfully dealt with this practice. To illustrate, they 

point to the Colorado Air Quality Control Commission declining to take a “cumulative” 

 202 Document that was included in our proposal docket, “Developing the WRAP Point and Area Source Emissions 

Projections for the 2018 Reasonable Progress Milestone for Regional Haze Planning”, Paula G. Fields, Martinus E. 

Wolf, Tom Moore, Lee Gribovicz 
121 

approach to deciviews, even though commenters had argued the concept should influence 

decision making about BART. 

Response: We agree with the NPS and the USDA Forest Service on the utility of a 

cumulative visibility metric in addition to the other visibility metrics we utilized and we do not 

agree that our approach is inconsistent with BART guidelines. Our visibility modeling shows 

that a number of Class I areas are individually and significantly impacted by emissions from the 

SJGS. The number of days per year significantly impacted by the facility’s NOx emissions is 

expected to decrease drastically at each Class I area (Table 6-8 of the TSD) as the result of 

installation of NOx BART emission controls at the SJGS. Clearly, the visibility benefits from 

NOx BART emission reductions will be spread among all affected Class I areas, not only the 

most affected area, and should be considered in evaluation of benefits from proposed reductions. 

The portion of the BART Guidelines (40 CFR 51 Appendix Y, IV.D.5) that the 

commenter referenced states: “If the highest modeled effects are observed at the nearest Class I 

area, you may choose not to analyze the other Class I areas any further as additional analyses 

might be unwarranted.”203 This section of the BART Guidelines addresses how to determine 

visibility impacts as part of the BART determination. Several paragraphs later in the BART 

Guidelines it states: “You have flexibility to assess visibility improvements due to BART 

controls by one or more methods. You may consider the frequency, magnitude, and duration 

components of impairment,” emphasizing the flexibility in method and metrics that exists in 

assessing the net visibility improvement. 

As discussed in a separate response to comment, for any CALPUFF visibility modeling 

in a SIP, a protocol addressing procedures and analyses should be determined with the 

appropriate reviewing authority and affected FLMs. As identified in the BART Guidelines, an 

important element of the modeling protocol is the choice of receptors used in the model, and the 

decision of when additional analyses including modeling the effects at Class I areas beyond the 

nearest area are warranted and necessary. As indicated in the TSD and other responses to 

comments in this section, we conferred with EPA OAQPS and FLM representatives on the 

details of conducting the CALPUFF modeling in this action, and concluded, like PNM and 

NMED previously concluded in their 2009 modeling, that because of the size of the source and 

the number of Class I area potentially affected, we should evaluate modeling receptors at all 

Class I areas within 300 km of the source. We also received comments from FLM 

representatives supporting the way we conducted our modeling including our evaluation of 

multiple Class I areas. 

Our baseline modeling indicated that visibility impacts from the SGJS were above 0.5 

deciviews at all 16 Class I areas within 300km of the SJGS and above 1 deciview at 14 of the 16 

Class I areas.204 These significant visibility impacts support the conclusion that further analyses 

were warranted. In this specific case, our analysis indicated the largest baseline impact was at 

the closest Class I area (Mesa Verde) but also indicated very large impacts at other Class I areas. 

In fact, we found that the largest overall decrease in visibility impact resulting from the proposed 

NOx emission reductions occurred at a much more distant Class I area (Canyonlands). 

 203 70 FR 39170. 204 70 FR 39118.Impacts of 1 deciview or greater are considered to cause a visibility impairment 
122 

Therefore, had we stopped our analysis after modeling the visibility improvement at Mesa 

Verde, we would not have discovered that the largest visibility improvement is predicted to 

occur elsewhere. 

In fully considering the visibility benefits anticipated from the use of an available control 

technology as one of the factors in selection of NOx BART, it is appropriate to account for 

visibility benefits across all affected Class I areas and the BART guidelines provide the 

flexibility to do so. One approach as noted above is to qualitatively consider, for example, the 

frequency, magnitude, and duration of impairment at each and all affected Class I areas. Where 

a source such as the SJGS significantly impacts so many Class I areas on so many days, the 

cumulative ‘total dv’ metric is one way to take magnitude of the impacts of the source into 

account. 

 

Therefore, under the BART Guidelines, and based upon these facts, we decided 

additional analyses were not only warranted but necessary. The BART Guidelines only indicate 

that additional analyses may be unwarranted at other Class I areas, and in no way exclude such 

analyses, as the commenter suggests. We concluded that a quantitative analysis of visibility 

impacts and benefits at only the Mesa Verde area would not be sufficient to fully assess the 

impacts of controlling NOx emissions from the SJGS. 

Again, nothing in the RHR suggests that a state (or EPA in issuing a FIP) should ignore 

the full extent of the visibility impacts and improvements from BART controls at multiple Class 

I areas. Given that the national goal of the program is to improve visibility at all Class I areas, it 

would be short-sighted to limit the evaluation of the visibility benefits of a control to only the 

most impacted Class I area. As noted previously, NMED and PNM’s BART analyses also 

presented visibility impact and improvement projections at all 16 Class I areas. We believe such 

information is useful in quantifying the overall benefit of BART controls. 

Comment: A commenter disagreed with our use of the revised IMPROVE equation 

(Method 8) post-processing methodology for the CALPUFF model results to calculate visibility 

impairment for the SJGS NOx BART determination from predicted pollutant concentrations. To 

be consistent with the WRAP modeling, the commenter claims we instead should have used the 

original IMPROVE equation (Method 6). The commenter further alleges that our use of Method 

8 resulted in much higher visibility impacts and improvements than would have been predicted 

using Method 6. The commenter also claims that our NOx BART modeling analysis is internally 

inconsistent because we rely on Method 6 for SO2 (using the WRAP modeling) and on Method 8 

modeling for NOx. Furthermore, the commenters assert that the use of Method 8 is generally 

justified by EPA by referring to the “regulatory version,” however, Method 8 processing is not 

supported by the “regulatory version” EPA used in its analysis. 

Response: Method 6 and Method 8 refer to two different versions of algorithms used to 

estimate visibility impairment from pollutant concentrations. Method 8 is a more recently 

available, more refined version of the original equation and is now considered by us and FLM 

representatives to be the better approach to estimating visibility impairment. Compared to the 

original IMPROVE equation, this revised IMPROVE equation has less bias, accounts for more 

pollutants, incorporates more recent data, and is based on considerations of relevance for the 
123 

calculations needed for assessing progress under the RHR.205 We are aware that Method 8 tends 

to show more improvement in visibility than Method 6 when reductions in very small particles 

are achieved, such as those that are formed by emissions of NOx. We believe that this, however, 

more accurately reflects real visibility conditions. 

We are also aware that at the time the States were working together in the WRAP to 

develop their RH SIPs, Method 6 was widely employed to develop RPGs and for initial BART 

analyses. By the time Method 8 was widely available, some States were far enough along in 

their SIP development that a switch to the newer method would have been disruptive. Because 

of this, we did not object to the use of Method 6 in the WRAP photochemical modeling or 

subject-to-BART screening modeling. In the case of New Mexico, Method 6 was used in 

WRAP modeling to determine which sources are subject to BART. Using Method 6, New 

Mexico determined that the SJGS was subject to BART because of its significant impact on 

Class I areas. We reached the same conclusion using either Method 6 or Method 8 in our 

modeling. New Mexico and the other WRAP States also used Method 6 to develop reasonable 

progress goals for the Class I areas in the region. 

For the purposes of ensuring that New Mexico’s emissions do not interfere with other 

States’ plans for visibility improvement, the choice of IMPROVE Method is not relevant. The 

commenter seems to imply that because the WRAP modeling largely used Method 6, we should 

use Method 6 for all our analyses, including our source specific analyses for NOx BART. 

However, regardless of which IMPROVE equation is used, New Mexico did not provide 

federally enforceable limitations on SJGS’ SO2 and NOx emissions to achieve the reductions 

expected by other States. Without these reductions, other States will not achieve the progress at 

their Class I areas which they expected under the collaborative WRAP process. 

As discussed previously, we have concluded that it is appropriate to address the 

requirements for NOx BART for SJGS at the same time we address New Mexico’s obligations 

under the visibility prong of 110(a)(2)(D)(i). As part of the BART analysis, we performed 

CALPUFF modeling to assess the impacts of the NOx BART proposed controls on the single 

source at issue on visibility impairment. Because Method 8 is the preferred method for analyses 

being conducted at this time,206 we estimated the CALPUFF visibility impacts using this peer 

reviewed algorithm. We also evaluated modeling results using Method 6 to quantify the 

sensitivity of our results to the choice in visibility impairment algorithm. We note that using 

 205 Revised IMPROVE algorithm for Estimating Light Extinction from Particle Speciation Data, IMPROVE, 

January 2006 (http://vista.cira.colostate.edu/improve/Publications/GrayLit/gray_literature.htm) ; Hand, J.L., 

Douglas, S.G., 2006, Review of the IMPROVE Equation for Estimating Ambient Light Extinction Coefficients – 

Final Report 

(http://vista.cira.colostate.edu/improve/Publications/GrayLit/016_IMPROVEEeqReview/IMPROVEeqReview.htm) 206 U.S. EPA. Additional Regional Haze Questions. U.S. Environmental Protections Agency. August 3, 2006, 

available at http://www.wrapair.org/forums/iwg/documents/Q_and_A_for_Regional_Haze_8-03-

06.pdf#search=%22%22New%20IMPROVE%20equation%22%22; WRAP presentation, “Update on 

IMPROVE Light Extinction Equation and Natural Conditions Estimates” Tom Moore, May 23, 2006; U.S. 

Forest Service, National Park Service, and U.S. Fish and Wildlife Service. 2010. Federal land managers’ air 

quality related values work group (FLAG): phase I report—revised (2010). Natural Resource Report 

NPS/NRPC/NRR—2010/232. National Park Service, Denver, Colorado. 
124 

either Method 8 or Method 6, substantial visibility benefits were projected for the installation of 

SCR and support the conclusion that SCR is the appropriate BART control. 

We disagree with the comment concerning Method 8 and the “regulatory version” of the 

model. CALPOST is the post-processing tool used to apply an algorithm to estimate visibility 

impairment from pollutant concentrations from CALPUFF. We determined CALPOST version 

6.221, which includes the option to apply either the Method 6 or the Method 8 algorithm, was the 

appropriate CALPOST version for our analysis. Since we determined Method 8 was the better 

method for estimating impairment, we chose to use the version of CALPOST that allowed the 

calculation using either Method 6 or Method 8. We note that this CALPOST version was 

approved and supported by the FLMs to allow for application of the revised IMPROVE equation 

(“Method 8”) 207. As discussed in more detail in the following response to comment, the ultimate 

decision on the acceptable model version, formulation, and set-up of CALPUFF and CALPOST 

for visibility modeling is our responsibility in a FIP situation. 

Comment: We received a number of comments concerning the version of the CALPUFF 

modeling system EPA has used. We utilized CALPUFF Version 5.8 suite for visibility 

modeling. The commenter indicated revised CALPUFF model Versions 6.112 and 6.4 are 

available and submitted modeling analyses using these versions of CALPUFF with the 

suggestion that their modeling should be used instead of ours. A number of commenters stated 

that Version 5.8 is outdated and overestimates visibility impacts. The commenters argue that the 

latest version, CALPUFF Version 6.4, which includes updated chemistry and technical 

enhancements to improve the model’s performance and accuracy, should be used to evaluate 

visibility impacts. They alleged that this version includes updated chemistry that is more robust 

and performs better and technical enhancements to improve the model’s performance and 

accuracy. 

Additionally, commenters included information on a February 16, 2011meeting held with 

the EPA in Research Triangle Park (RTP), North Carolina along with representatives of the 

western states utility organization WEST Associates, the American Petroleum Institute (API), 

and TRC (the developer of CALPUFF). The FLMs participated in this meeting by 

teleconference. This information indicates that it was agreed at the meeting that the FLMs will 

take the lead on a review and testing of the CALPUFF model code changes including the new 

chemistry modules, and Model Change Bulletins (MCBs) and coordinate with EPA. 

Response: The commenter indicated that a revised version of the model is available and 

submitted modeling analyses using CALPUFF model Versions 6.112 and 6.4. Comments 

received justifying the use of these versions of CALPUFF alleged that they were more 

scientifically robust and included updated chemistry and technical enhancements to improve the 

model’s performance and accuracy. We disagree that the newer versions of CALPUFF should 

be used in this action to determine potential visibility impacts. The newer version(s) of 

CALPUFF have not received the level of review required for use in regulatory actions subject to 

 207 U.S. Forest Service, National Park Service, and U.S. Fish and Wildlife Service. 2010. Federal land managers’ 

air quality related values work group (FLAG): phase I report—revised (2010). Natural Resource Report 

NPS/NRPC/NRR—2010/232. National Park Service, Denver, Colorado, available at 

http://www.nature.nps.gov/air/Pubs/pdf/flag/FLAG_2010.pdf. 
125 

EPA approval and consideration in a BART decision making process. Based on our review of 

the available evidence we do not consider the models to have been shown to be sufficiently 

documented, technically valid, and reliable for use in a BART decision making process. In 

addition, the available evidence would not support approval of these models for current 

regulatory use. There are known technical problems with CALPUFF 6.112. Furthermore, 

these newer versions of the model introduce additional chemical mechanisms that have not gone 

through the public review process required for approval by the Agency and, that if added to 

ensure the models meet regulatory requirements, would necessitate EPA’s reevaluation of past 

policy decisions on the use of the model that were based on our understanding of the effects of 

using more simplified chemistry.. 

The commenter’s modeling using different model versions with as yet unapproved 

mechanisms and the non-guideline techniques indicated different results than past modeling 

submitted by PNM and the results of our modeling of SJGS.208 The visibility impacts of their 

modeling results are much lower compared to results of past PNM, NMED and EPA modeling. 

These discrepancies are large enough to lend further credence to the need for a full review of the 

revised modeling systems before considering the modeling results for any decision making.209,210 

EPA also notes that review of previous CALPUFF model version updates has been a lengthy 

process due to lack of documentation and finding additional technical issues that had to be fixed 

before an update could be approved. EPA was fully justified in following its modeling approach, 

which was consistent with current EPA and FLM guidelines, as well as similar to modeling 

recently performed by NMED and PNM. EPA used the approved version of the model in 

accordance with the appropriate procedures, as discussed further in other response to comments 

and is confident in using our results as one of the five factors in making a BART determination. 

In considering the comment that we should use the latest version of CALPUFF (6.4) or 

an earlier version 6.112, we considered the regulatory status of CALPUFF for visibility analyses 

and what analyses are needed to utilize an updated CALPUFF modeling system. The 

requirements of 40 CFR 51.112 and 40 CFR Part 51, Appendix W, Guideline on Air Quality 

Models (GAQM) and the BART Guidelines which refers to GAQM as the authority for using 

CALPUFF, provide the framework for determining the appropriate model platforms and versions 

and inputs to be used. Because of concern with CALPUFF’s treatment of chemical 

transformations, which affect AQRVs, EPA has not approved the chemistry of CALPUFF’s 

model as a ‘preferred’ model. The use of the regulatory version is approved for increment and 

NAAQS analysis of primary pollutants only. Currently CALPUFF Version 5.8, is subject to the 

requirements of GAQM 3.0(b) and as a screening model, GAQM 4. CALPUFF Versions 6.112 

and 6.4 have not been approved by EPA for even this limited purpose 

 208 Comparison of model results presented by commenter with values in our TSD Chapter 6. 

209 70 FR 39123, 39124. “We understand the concerns of commenters that the chemistry modules of the 

CALPUFF model are less advanced than some of the more recent atmospheric chemistry simulations. To date, no 

other modeling applications with updated chemistry have been approved by EPA to estimate single source pollutant 

concentrations from long range transport.” and in discussion of using other models with more advanced chemistry it 

continues, “A discussion of the use of alternative models is given in the Guideline on Air Quality in appendix W, 

section 3.2.” 

210 EPA report, “Assessment of the VISTAS Version of the CALPUFF Modeling System”, EPA-454/R-08-007, 

August 2008 available at (http://www.epa.gov/ttn/scram/reports/calpuff_vistas_assessment_report_final.pdf); 
126 

 Under the BART guidelines, CALPUFF should be used as screening tool and 

appropriate consultation with the reviewing authority is required to use CALPUFF in a BART 

determination as part of a SIP or FIP. The BART Guideline cited and referred to EPA’s GAQM 

which includes provisions to obtain approval through consultation with the reviewing authority. 

Moreover, we also note that in EPA’s document entitled Guidance on the Use of Models and 

Other Analyses for Demonstrating Attainment of Air Quality Goals for Ozone, PM2.5, and 

Regional Haze (EPA-454/B-07-002), that Appendix W does not identify a particular modeling 

system as ‘preferred’ for modeling conducted in support of state implementation plans under 40 

CFR 51.308(b). A model should meet several general criteria for it to be a candidate for 

consideration. These general criteria are consistent with the requirements of 40 CFR 51.112 and 

40 CFR 51, Appendix W. Therefore, it is correct to interpret that no model system is considered 

‘preferred’ under 40 CFR 51, Appendix W, Section 3.1.1 (b) for either secondary particulate 

matter or for visibility assessments. Under this general framework, we followed the general 

recommendation in Appendix Y to use CALPUFF as a screening technique since the modeling 

system has not been specifically approved for chemistry. The use of CALPUFF is subject to 

GAQM requirements in section 3.0(b), 4, and 6.2.1(e) which includes an approved protocol to 

use the current 5.8 version. 

As noted previously, the summary of results provided by the commenter indicate much 

lower results compared to the current regulatorly approved version of the modeling system. The 

significant difference in results is an indicator that there are important changes in the science 

between these new versions and the current EPA version. We must have a full understanding of 

these changes before 'approving' their use. The information provided indicates the new science 

includes chemistry for which this model was never approved so these changes would necessitate 

a notice and comment rulemaking and not a simply update as previously done for this model to 

address bug-fixes and the like. We believe that with such modifications to the modeling system, 

CALPUFF (Version 6.4) used in this manner could no longer be considered a screening 

technique under Section 4 of GAQM. The CALPUFF Version 6.112 would be considered an 

alternative model and would be subject to the requirements of Section 3.2 of GAQM. As 

covered in more thorough detail below, these alternate versions of CALPUFF (6.112 and 6.4) are 

subject to the provisions of GAQM. 

Based on the technical information that has been provided, these model versions could 

not be approved because the information provided is not sufficient and does not comport with the 

requirements of Section 3.2, including 3.2.2(b)(3) and (e), of GAQM. The model developer has 

relied upon several articles (Escoffier-Czaja and Scire, 2007; and Scire, et al., 2003) which 

describe the general reliability of the CALPUFF modeling system and post-processing 

techniques for use in visibility assessments. Based on our review of this information, we do not 

believe it provides sufficient information for EPA to assess the suitability of the newer versions 

of the modeling system as would be done in reviewing models in accordance with GAQM 

Section 3.2.2(e) requirements. 

First, it is important to understand that each of the papers were presented as part of 

general proceedings at conferences, and therefore do not reflect the thoroughness of a formal 

peer review process that would be associated with submission to mainline scientific journals. 

Therefore, we do not consider these references suitable for establishing the validity of the model 
127 

or post-processing techniques or demonstrating that these models have undergone independent 

scientific peer review as necessary for reviewing models in accordance with Section 3.2.2(e)(i) 

of GAQM. 

Second, the evaluation techniques utilized by the developer are not appropriate for 

evaluation of the chemical mechanisms of the CALPUFF system. Appendix A.3 of GAQM 

describes CALPUFF as generally considered suitable for treatment of dispersion of non-reactive 

pollutants from a single source or small group of sources for distances beyond 50-km to 200- to 

300-km. CALPUFF usage, in the context of the Southwestern Wyoming Air Quality Task 

Force (SWWYTAF) modeling dataset presented in both Escoffier-Czaja and Scire (2007) and 

Scire et al. (2003), is treated as a full photochemical modeling system such as the 

Comprehensive Air Quality Model with Extensions (CAMx) or the Community Multiscale Air 

Quality Model (CMAQ). However, the evaluation techniques presented in the aforementioned 

references evaluate the model as a near-field dispersion model, presenting information on sulfate 

and nitrate performance in quantile-quantile plots (Q-Q plots) only for the Bridger-Teton 

IMPROVE monitoring site. This technique is not satisfactory for purposes of model 

performance evaluations for full science chemistry models. Recommended methods and metrics 

for evaluation of photochemical models are discussed at length in EPA’s Guidance on the Use of 

Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for Ozone, 

PM2.5, and Regional Haze (EPA-454/B-07-002). Therefore, we do not consider the analysis 

techniques presented by the model developer sufficient to demonstrate that the model is not 

biased, as would be done to justify use of a model in accordance with Section 3.2.2(e)(iv) of 

GAQM. 

Finally, no modeling files were provided for review, no protocol or other complete 

documentation was provided outlining the methods and procedures of operating the alternative 

model in agreement with the appropriate reviewing authority (EPA Region 6) prior to 

submission of comments, contrary to requirements of Section 3.2.2(e)(v) of GAQM. 

Therefore, on the basis of available information submitted to the public record, we could 

not approve the use of the alternative model versions in accordance with Section 3.2.2(e) 

requirements of GAQM. We believe our modeling accurately describes the visibility impacts of 

the SJGS, the benefits of BART controls, and was based on established and well-recognized 

methods. 

It would be problematic for us to allow the use of any unapproved model variants with 

potentially significant changes to chemistry treatment without additional information regarding 

the model’s formulation, performance, and acceptability. In promulgating the BART guidelines 

we made the decision in the final BART Guideline to recommend that the model be used to 

estimate the 98th percentile visibility impairment rather than the highest daily impact value as 

proposed. We made the decision to consider the less conservative 98th percentile primarily 

because the chemistry modules in the CALPUFF model are simplified and likely to provide 

conservative (higher) results for peak impacts. Since CALPUFF’s simplified chemistry could 

lead to model over predictions and thus be conservative, EPA decided to use the less 
128 

conservative 98th percentile.211 The modeling that PNM’s contractor performed for PNM was 

based on CALPUFF versions that have been updated with an allegedly more robust chemistry 

and purportedly performs better according to the commenter than the current version of the 

model approved for regulatory actions (CALPUFF version 5.8). If these versions of CALPUFF 

can be shown to be reliable and acceptable to EPA, it would likely be appropriate to the use 

Highest Daily impact (1st High instead of the 8th High) based on the presumption that the updated 

chemistry of CALPUFF model would result in less conservative results than Version 5.8. In past 

agreements in using the CAMx photochemical model, which has a robust chemistry module, the 

Region has recommended the use of the 1st High value when sources were being screened out of 

a full BART analysis based on the CAMx results.212 

The current version of CALPUFF approved for regulatory action was last updated by 

EPA on June 29, 2007. The CALPUFF modeling system approved at that time included 

CALPUFF version 5.8, level 070623, CALMET version 5.8 level 070623, and CALPOST 

version 5.6394, level 070622. CALPUFF is still considered a screening model for visibility 

assessments. Therefore, we followed the requirements of Appendix W for screening models in 

our modeling.213 We conducted our modeling with the version 5.8 suite with a few exceptions 

that were discussed among modeling experts from EPA Region 6, EPA/ OAQPS and FLM 

representatives. Our modeling procedures were discussed more fully in our TSD. 

We note that the CALPUFF Versions 6.4 and 6.112 have not been reviewed by EPA for 

potential regulatory use. PNM’s contractor has indicated that a meeting was held with 

EPA/OAQPS representatives on Feb. 16, 2011 and FLM representatives participated via 

conference call. The commenter indicates that EPA was going to let the FLM representatives 

take the lead on review and testing of the new version of CALPUFF (6.4) and coordinate with 

EPA regarding this issue. Mr. Tyler Fox, Group Leader of the Air Quality Modeling Group at 

EPA/OAQPS has indicated that EPA will take the lead on the review of the new version 

(CALPUFF Version 6.4) and that the new addition of a more sophisticated chemistry mechanism 

is a paradigm shift in treatment of chemistry in CALPUFF and requires additional rule making 

and public review since CALPUFF was never approved for chemistry in the GAQM and EPA is 

currently evaluating several models to address current modeling needs for models that can be 

used for analyses of secondary formation pollutants for ozone, PM2.5 secondary, and regional 

haze/visibility impairment.214 At this time, EPA and the FLM representatives are in the process 

of planning to move forward on reviewing all available models to determine their suitability for 

these analyses. We note that we have reviewed the materials shared at the meeting and discussed 

 211 “Most important, the simplified chemistry in the model tends to magnify the actual visibility effects of that 

source. Because of these features and the uncertainties associated with the model, we believe it is appropriate to use 

the 98th percentile—a more robust approach that does not give undue weight to the extreme tail of the distribution.” 

70 FR 39104, 39121. 

212 . Comment Letter from EPA Region 6 to TCEQ dated February 13, 2007 regarding TCEQ 

Final Report “Screening Analysis of Potential BART- Eligible Sources in Texas”, December 

2006. . , 213 GAQM (2005 update) Part 3.0(b), and 4.2.1.1 and 4.2.1.2. Section 4 dealing with screening versions of modeling 

analyses was updated in the 2005 GAQM notice. 

214 Personal communications with Mr. Tyler Fox to verify guidance given at meeting pertaining to alternate 

CALPUFF versions. July 29, 2011. 
129 

the planned steps forward from the meeting, but that CALPUFF Versions 6.4 and 6.112 have still 

not been evaluated to determine their suitability for use in various contexts. 

Based on the applicable GAQM and BART Guidelines regulations, the combination 

GAQM (2005) citations (6.2.1(e) and 3.0(b)), and the BART Guidelines outline that for any 

visibility modeling performed with the CALPUFF model in a SIP, a protocol addressing 

procedures and analyses should be developed with the appropriate reviewing authority and 

affected FLMs. Approval of an alternate model usually includes consultation with the modeling 

group at EPA/OAQPS even though ultimate authority in most cases is the Regional Office. In 

the case of a SIP or a FIP, the EPA Regional Office has the final approval decision on what 

constitutes appropriate/acceptable modeling. Development of an acceptable protocol with a 

Regional Office for review and approval of an alternative model (i.e. updated model version, 

etc.) can be a very significant task and could take 6 months to a year or longer to complete a 

protocol that detailed submission of information for review including model sensitivity runs, 

evaluation of model performance, etc., so this can be a sizable hurdle in order for EPA to ensure 

that we are basing decisions on sound science and the best tools for actions. Approval of 

updated CALPUFF versions has been such a large task that EPA/OAQPS has typically taken the 

lead in approval of CALPUFF updates for regulatory use. In this case, PNM did not work out a 

protocol to address any of these needed elements for EPA Region 6 to conduct a review of 

PNM’s proposed use of an alternate model and the modeling results. The new versions of 

CALPUFF, version 6.112 or 6.4, that the commenter used to provide modeling analyses have not 

gone through a full regulatory review in accordance with 40 CFR Part 51 Appendix W Section 

3.2.2. Furthermore, the currently available information does not support the approval of these 

versions of the CALPUFF model for use in making BART determinations. In addition, if these 

versions of the model were used, EPA would have to reconsider whether using the 98th percentile 

impact for determining impairment was appropriate. Therefore, EPA does not believe the use 

of CALPUFF version 6.112 or 6.4 is appropriate for this rule making. We believe we have made 

the appropriate choice in using CALPUFF version 5.8. 

In support of the discussion above concerning the regulations that apply when using 

CALPUFF, we have also included a detailed overview of the regulatory status of CALPUFF for 

conducting visibility impairment as part of a BART determination and what requirements apply 

when using alternate model versions. 

On February 15, 2003 at 68 FR 18440, EPA issued a rule establishing the dispersion 

model, CALPUFF, as the preferred technique for assessing the long range transport of primary 

pollutants, including for assessing impacts on Class I increments Federal Class I areas. See 40 

CFR Part 51 Appendix W, Guideline on Air Quality Models (GAQM). In this 2003 GAQM 

rulemaking, we approved CALPUFF for PSD Ambient Air Standard analyses of ambient air 

concentrations and increment consumption, and also for complex wind situations (with case-bycase approval by the EPA Regional Office, subject to Secion 3.2.2.e), but not for AQRV 

analyses (i.e. visibility impacts). We defined the role of CALPUFF for assessment of 

reasonably attributable visibility impairment due to one source or a small group of sources on a 

case-by-case basis as a screening model subject to approval by the EPA Regional Office in 

accordance with Section 3.0 of the GAQM, including Section 3.0(b). Because of concern in 

CALPUFF’s treatment of chemical transformations, which affect AQRVs, we did not approve 
130 

the chemistry of CALPUFF’s model in the 2003 GAQM update. The FLMs are the reviewing 

authority for Class I AQRV’s assessments conducted for permit actions. It is important to point 

out that without a preferred model for visibility impairment, the use of CALPUFF based on the 

2003 final rule is approved in accordance with Section 3.0(b) and the screening technique 

provisions in Sections 4.2.1 of GAQM when used to meet EPA requirements. 215 

Subsequently, we further addressed the regulatory status of the CALPUFF modeling 

system in the BART Guidelines. In the BART Guidelines, we indicated that CALPUFF has not 

yet been fully evaluated for secondary pollutant formation. For the specific purposes of the 

regional haze rule’s BART provisions, however, we concluded that CALPUFF as a screening 

application is sufficiently reliable to inform the decision making process in determining if a full 

BART analyses is required and in estimating the degree of visibility improvement that may 

reasonably be expected from controlling a single source in order to inform the BART 

determination. In the BART Guidelines, we did not give CALPUFF full regulatory approval for 

visibility impairment analyses. Rather, we said that CALPUFF should be used as screening tool 

and appropriate consultation with the reviewing authority is required. We indicated in the 

BART Guidelines that we had updated GAQM in 2003 to address CALPUFF usage. 

Specifically Section 7.2.1(e). of the 2003 GAQM states: 

CALPUFF (Section A.3) may be applied when assessment is needed of reasonably 

attributable haze impairment or atmospheric deposition due to one or a small group of sources. 

This situation may involve more sources and larger modeling domains than that to which 

VISCREEN ideally may be applied. The procedures and analyses should be determined in 

consultation with the appropriate reviewing authority (paragraph 3.0(b) and the affected FLM(s). 

This indicates that CALPUFF modeling (including model version, inputs and parameters 

and processing, etc.) conducted for visibility (haze) impairments has to be approved by the 

appropriate reviewing authority in accordance with Section 3.0(b) of the 2003 GAQM. Section 

3.0(b) indicates: 

In this guidance, when approval is required for a particular modeling technique or 

analytical procedure, we often refer to the ‘‘appropriate reviewing authority’’. In some EPA 

regions, authority for NSR and PSD permitting and related activities has been delegated to State 

and even local agencies. In these cases, such agencies are ‘‘representatives’’ of the respective 

regions. Even in these circumstances, the Regional Office retains the ultimate authority in 

decisions and approvals. 

The combination of these GAQM (2003) citations (7.2.1(e), 3.0(b), 4.2.1) outline that for 

any CALPUFF visibility modeling in a SIP, a protocol addressing procedures and analyses 

should be determined with the appropriate reviewing authority and affected FLMs. The EPA 

Regional Office has the final approval decision on what constitutes appropriate/acceptable 

modeling. 

As indicated in the TSD and RTC for this notice, we conferred with EPA OAQPS and 

FLM representatives on the details of conducting the CALPUFF modeling in this action. We 

 215 GAQM (2003 update) Part 3.0(b), and 4.2.1. 
131 

also received comments from FLM representatives supporting the way we conducted our 

modeling. 

 We made the decision in the final BART Guideline to use less than the highest 

daily impact value for assessment of visibility impacts. We made this decision in response to 

comments we received expressing concern that the chemistry modules in the CALPUFF model 

are less advanced and that use of the 1st High was conservative and the knowledge that 

CALPUFF’s simplified chemistry could lead to model over predictions and thus be conservative. 

We decided in the BART Guideline to use the 98 percentile for CALPUFF based modeling 

results. 216 We also received comments opposed to using the day with the worst meteorology, 

but the primary reason we changed to using a less stringent metric than the day with the highest 

visibility impact was because of concerns about overestimations in CALPUFF’s simplified 

chemistry. As a result, we determined that it was appropriate to use the 98th percentile or 8th 

High value when modeling all days of the year instead of the 1st High value, also described as 

the Highest Daily impact level for each year modeled. 

In the context of the commenter’s assertion that EPA should allow the use of the 

modeling that their contractor performed for PNM based on CALPUFF versions that have been 

updated with a more robust chemistry and purportedly performs better according to the 

commenter than the current version of the model approved for regulatory actions (CALPUFF 

version 5.8), it is important to note that with the updated chemistry in CALPUFF version 6.4, it 

would probably be appropriate to the use Highest Daily impact (1st High instead of the 8th High) 

based on the presumption that the CALPUFF (v. 6.4) model would be less conservative than 

Version 5.8. In past agreements in using the CAMx photochemical model, which has a robust 

chemistry module, the Region has recommended the use of the 1st High value when sources 

were being screened out of a full BART analysis based on the CAMx results. 217 

The most recent update to the GAQM occurred November 9, 2005. Based on the BART 

Guidelines some additional language was added to the GAQM about the use of CALPUFF. In 

Appendix A to the GAQM we added the following update on CALPUFF to A.4.: 

CALPUFF is a non-steady-state time-and space-dependent Gaussian puff model. 

CALPUFF treats primary pollutants and simulates secondary pollutant formation using a 

parameterized, quasi-linear chemical conversion mechanism. Pollutants treated include SO2, 

SO4 =, NOX (i.e., NO + NO2), HNO3, NO3-, NH3, PM–10, PM–2.5, toxic pollutants and others 

pollutant species that are either inert or subject to quasi-linear chemical reactions. 

This indicates that CALPUFF includes some rudimentary calculations to simulate the 

atmospheric chemistry for the pollutants listed that are best described as quasi-linear chemical 

reactions. This additional language does not indicate that the model was changed but merely 

 216 “Most important, the simplified chemistry in the model tends to magnify the actual visibility effects of that 

source. Because of these features and the uncertainties associated with the model, we believe it is appropriate to use 

the 98th percentile—a more robust approach that does not give undue weight to the extreme tail of the distribution.” 

70 FR 39104, 39121. 

217 . Comment Letter from EPA Region 6 to TCEQ dated February 13, 2007 regarding TCEQ Final Report 

“Screening Analysis of Potential BART- Eligible Sources in Texas”, December 2006. 
132 

provides a more descriptive characterization of the module for chemistry that had been 

incorporated in the approved version of CALPUFF since its initial limited promulgation in 2003. 

Some of the numbering of sections changed in the 2005 update to GAQM but it indicated 

basically the same language about the status of CALPUFF modeling for visibility impairment as 

in the previous version. In the 2003 update, this section was 7.2.1(e) and in the 2005 update it is 

now 6.2.1(e) that states: 

CALPUFF (Section A.3) may be applied when assessment is needed of reasonably 

attributable haze impairment or atmospheric deposition due to one or a small group of sources. 

This situation may involve more sources and larger modeling domains than that to which 

VISCREEN ideally may be applied. The procedures and analyses should be determined in 

consultation with the appropriate reviewing authority (paragraph 3.0(b)) and the affected 

FLM(s). 218 

In summary, based on the applicable GAQM and BART Guidelines regulations the 

combination GAQM (2005) citations (6.2.1(e) and 3.0(b)) and the BART Guidelines outline that 

for any visibility modeling performed with the CALPUFF model in a SIP, a protocol addressing 

procedures and analyses should be developed with the appropriate reviewing authority and 

affected FLMs. Furthermore, even if the state has been delegated, the EPA Regional Office has 

the final approval decision on what constitutes appropriate/acceptable modeling. In the specific 

situation of the BART FIP for the SJGS, EPA Region 6 is the reviewing authority. 

We note that the CALPUFF Versions 6.4 and 6.112 have not been reviewed by EPA for 

potential regulatory use. PNM’s contractor has indicated that a meeting was held with 

EPA/OAQPS representatives on Feb. 16, 2011 and FLM representatives participated via 

conference call. The commenter indicates that EPA was going to let the FLM representatives 

take the lead on review and testing of the new version of CALPUFF (6.4) and coordinate with 

EPA regarding this issue. We note that we have reviewed the materials shared at the meeting 

and discussed the planned steps forward from the meeting, but that CALPUFF Versions 6.4 and 

6.112 have still not been revaluated to . Both Mr. Tim Allen, of US Fish and Wildlife, and Mr. 

Tyler Fox, of EPA RTP, have indicated that EPA will take the lead on the review of the new 

version as EPA evaluates models to address current modeling needs for models that can be used 

for analyses of secondary formation pollutants for ozone, PM2.5 secondary, and regional 

haze/visibility impairment. At this time, EPA and the FLM representatives plan to move forward 

on reviewing all available models to determine their suitability for use in various contexts. 

 In sum, the new versions of CALPUFF, version 6.112 or 6.4, that the commenter 

used to provide modeling analyses have not gone through a full regulatory review in accordance 

with 40 CFR Part 51 Appendix W Section 3.2.2. As we have already covered in this comment, 

there is not a preferred model for single source visibility analyses in GAQM. Therefore Section 

3.2.2(b)(3) and (e) apply in this situation. Specifically, Section 3.2.2(b) indicates: 

 218 We note that 6.2.1(e) is cross referencing CALPUFF, which was moved to A.4 which was an inadvertent carry 

over from the last GAQM update. The Applicable CALPUFF section is in Appendix A to the GAQM in Section 

A.4. 
133 

An alternative model should be evaluated from both a theoretical and a performance 

perspective before it is selected for use. There are three separate conditions under which such a 

model may normally be approved for use: (1) ... (2) ... ; or (3) if the preferred model is less 

appropriate for the specific application, or there is no preferred model. 

Section 3.2.2(e) states: 

Finally, for condition (3) in paragraph (b) of this subsection, an alternative refined model 

may be used provided that: 

i. The model has received a scientific peer review; 

ii. The model can be demonstrated to be applicable to the problem on a theoretical basis; 

iii. The data bases which are necessary to perform the analysis are available and 

adequate; 

iv. Appropriate performance evaluations of the model have shown that the model is not 

biased toward underestimates; and 

v. A protocol on methods and procedures to be followed has been established. 

In this case, the commenter provided some information regarding a review of the model, 

but it was not clear that it was an independent and unbiased peer review. EPA would have to 

have had all the elements in Section 3.2.2(e) addressed and then conducted a detailed review 

including existing modeling databases to evaluate model performance before being able to 

consider approving an alternate version of CALPUFF. We note that an air quality model may be 

considered to have undergone some “scientific peer review” if each of the major components of 

the modeling system (i.e., air chemistry/deposition, meteorological and emissions models) has 

been described and tested, and the results have been documented and reviewed by one or more 

disinterested and independent qualified parties. Even with such an independent review, EPA 

would need to conduct an overall assessment in order to make a determination. 

We note that EPA has reviewed and approved previous version upgrades of the 

CALPUFF modeling system in accordance with 40 CFR Part 51 Appendix W, Guideline on Air 

Quality Models (GAQM) which governs the process for using non-regulatory approved models 

and also how to certify upgraded models. Specifically, we have conducted rigorous analyses of 

CALPUFF modeling systems in accordance with Sec 3.2.2 for primary pollutant analyses (NOx, 

SOx, etc.) and these reviews have taken many months to a year or more to conduct. This has not 

been done for Versions [6.112 and 6.4]. To conduct a full review of a new model system suite 

can take a year or more if the upgrade is significant. The addition of a detailed chemistry would 

be considered significant. We would also have to address if the inclusion of a more advanced 

chemistry negated the logic for using the 8th high in CALPUFF modeling and would require the 

use of the maximum daily 1st High for each year. 

Comment: The USDA Forest Service (USFS) provided comments supporting our 

assumptions regarding the value of the background ammonia (a constant 1.0 ppb concentration) 

used for the visibility analysis. In contrast, PNM claims that the use of variable monthly 

ammonia values ranging from 0.2 ppb in the winter months to 1.0 ppb during the summer would 

better reflect the seasonal variations in ammonia concentrations than would a constant, assumed 
134 

ammonia concentration. PNM further argued that the use of variable monthly ammonia 

concentrations would still be conservative. Therefore, PNM alleges, since a variable monthly 

ammonia scheme is more representative and conservative, it should be used instead of EPA’s 

constant ammonia levels. PNM also claims that the use of the Ammonia Limiting Method 

(ALM) is appropriate given the “conservatism (averaging about a factor of two) of the assumed 

ammonia relative to observations.” PNM further comments that our supporting documentation 

also states that “alternative levels may be used if supported by data” and therefore we have no 

basis for criticizing the variable, monthly ammonia levels used in the modeling prepared by 

PNM. PNM further comments that EPA’s decision to rely on constant high background 

ammonia concentrations unjustifiably results in higher visibility improvements than expected by 

PNM’s more realistic modeling results. 

Response: We agree and concur with the use of the 1 ppb ammonia levels from USFS 

representatives. We disagree with the comments supporting the use of variable, monthly 

ammonia concentrations. There are several factors to consider with selecting the appropriate 

ammonia background for estimating visibility impacts, including the length and temporal 

resolution of the ammonia data collected, whether the ammonia data varies depending on 

location of collection in comparison to proximity of SJGS plumes, the fluctuation of levels 

throughout the year, and the importance of plume chemistry from the point of NOx and SO2

emissions that react with emitted and background ammonia as the plumes transport to downwind 

receptors. We have examined the available ammonia data collected, including the data cited to 

in the comments.219 Our selection of the IWAQM Phase 2 default ammonia background constant 

value of 1 ppb (rather than the variable monthly ammonia concentrations suggested by the 

commenter) better represents ammonia concentrations directly around the SJGS emission 

sources. The ammonia near the source that is available to interact with the plume as it is emitted 

is of greater concern for determining visibility impacts from the source due to the atmospheric 

chemical reactions that occur as the pollutants and ammonia are transported together to a Class I 

area. Therefore, it is more appropriate to use a background level for ammonia that is 

representative of the area around the source rather than the ammonia levels at the isolated 

downwind Class I areas. 

The pollutants emitted by the source, such as sulfate and nitrate, will react with available 

ammonia present near the release point and this ammonia and ammonia reaction products will be 

transported along with the emitted pollutants to the downwind receptors. The available 

monitoring data indicates that ammonia levels are higher around the SJGS emission sources and 

decrease at Mesa Verde, thus supporting that conclusion that when SJGS plumes are transported 

to Mesa Verde (and other Class I areas), as expected, the SJGS emissions react with ammonia 

levels near the SJGS resulting in decreasing ambient ammonia levels downwind from the SJGS. 

The Substation and Farmington airport sites, which are the passive monitor readings that are 

closest to the SJGS, have annual mean ammonia concentrations of 1.13 ppb and 1.47 ppb, 

respectively, and are above the 1 ppb levels that we have chosen to model. We also evaluated 

the average of each 3 week period data from the Substation and Farmington sites, which was as 

high as 1.75 ppb and never dropped below 0.8 ppb for any individual 3 week period that data 

 

219 Sather, et. al. “Baseline ambient gaseous ammonia concentrations in the Four Corners area and eastern 

Oklahoma, USA,” Journal of Environmental Monitoring (September 2008) (“The Sather 2008 report”) 
135 

was collected in 2007, the average of the annual mean at these two sites being 1.3 ppb. This is 

substantially higher than the annual mean value of 0.21ppb at Mesa Verde, and the monitoring 

data suggests that the higher ammonia is due to the sources around the Farmington and 

Substation monitors. The available data indicates that the average at the five ammonia gathering 

sites (not including the Mesa Verde site) is 0.88 ppb on annual basis The data also shows that the 

monthly maximums at the five sites ranged from 1.3 ppb to 3.5 ppb with an annual average 

monthly maximum of 1.74 ppb. This supports our decision to use a constant 1.0 ppb ammonia 

value as being representative of the area around the source rather than the ammonia levels at the 

isolated downwind Class I areas. Therefore, the level we modeled is more appropriate. We have 

taken into consideration the issues raised by the commenter and conferred with the author of the 

2008 Sather report, and concluded that the ammonia levels we used in the model are appropriate. 

 

 We disagree with the use of the ALM. There is a lack of documentation, 

adequate technical justification, and validation for the development and use of the ALM. This is 

discussed further in a separate response to comments. 

Comment: PNM contracted with Mr. Joe Scire to review and prepare a report on PNM’s 

BART modeling submitted to NMED during its 2010 state proposed rulemaking process. PNM 

included this Report as part of its comments to EPA. PNM asserts that the Report confirms that 

PNM’s modeling was consistent with the methodology developed for CALPUFF and it was 

prepared consistent with the WRAP protocol for BART modeling and the WRAP BART 

modeling. The commenter argues that since EPA has accepted the WRAP modeling and used it 

to support its own positions with regard to SO2 in the proposed FIP, and given the fact that 

PNM’s modeling was prepared in a manner consistent with the WRAP modeling, EPA should 

not need to alter PNM’s modeling Moreover, the modeling results achieved by us are merely a 

function of our modeling methods, not true differences in visibility impacts. 

In addition to the commenter’s position that the PNM modeling was conducted 

appropriately, PNM claims that the Report shows more recent developments in modeling science 

and chemistry could be used to make a more accurate and realistic prediction of the visibility 

improvements that might result from installing SCRs at SJGS. The recommendations included 

modeling results from the use of (1) two updated CALPUFF models, Ver. 6.112 and a version 

with updated chemistry (Ver. 6.4); (2) a refined modeling grid (1km versus 4 km), and (3) 

Ammonia Limiting Method (ALM). PNM claims use of the ALM would take into account the 

spatial variations of background ammonia concentrations and account for the consumption of 

background ammonia by background sources of sulfate and nitrate; and that modeling at a higher 

resolution of 1 km (compared to 4km) is better, to “better represent the wind flow in a complex 

terrain regime.” Using these modeling techniques, PNM argues that these alternate modeling 

results show that the greatest visibility improvement that could be achieved at any Class I area 

by installing SCRs at SJGS would be less than 0.5 dv per unit, and thus less than what a human 

could perceive. 

Response: The commenter indicates that we used the WRAP photochemical modeling to 

support our action on SO2 controls and from this, somehow concludes we should accept PNM’s 

BART CALPUFF visibility modeling, allegedly consistent with WRAP protocols for assessing 

the visibility impacts of SJGS. In this instance, the commenter appears to confuse two types of 
136 

modeling. As we discuss elsewhere in this notice, we did rely on the WRAP’s photochemical 

modeling in considering whether New Mexico sources, specifically SJGS, interfered with other 

States’ visibility plans. The WRAP’s CALPUFF screening modeling was used to determine 

which BART-eligible sources were subject to BART. As a result of the WRAP CALPUFF 

screening modeling, New Mexico identified one source subject to BART and, as discussed 

elsewhere, projected emission reductions that were relied upon by the WRAP in their 

photochemical modeling. The photochemical modeling was used to consider the emissions from 

all sources in the regions and was used to establish the reasonable progress goals for the WRAP 

States. The source-specific CALPUFF visibility modeling, on the other hand, requires a site 

specific modeling approach designed to evaluate visibility impacts to inform decisions in a 

BART determination for a specific source. Our CALPUFF visibility modeling, performed using 

an accepted CALPUFF model version and following applicable guidance and EPA/FLM 

recommendations, showed significant visibility benefits due to the use of SCR as NOx BART at 

SJGS. 

As discussed elsewhere, since NMED was previously proposing to install the most 

stringent controls, we did not raise some of our concerns with past modeling, since the BART 

guidelines allow some flexibility in the need to conduct modeling when the most stringent 

controls are being required. In our review of PNM’s earlier BART CALPUFF visibility 

modeling, we did note some inconsistencies between PNM’s CALPUFF modeling protocol and 

the EPA approved modeling techniques for source-specific modeling to support a BART 

determination. As stated in the TSD that accompanied our proposal, however, we agree with 

commenter that the PNM CALPUFF modeling generally followed the BART protocol for BART 

screening analyses developed by the WRAP.220 After the WRAP CALPUFF screening 

modeling had been generated, some problems with the changes from the previous CALPUFF 

modeling system that were included in CALPUFF Version 6.211 and another version referred to 

as the “VISTAS version” had been identified.221 Version 6.211 has been found to set up 

situations where the boundary layer could artificially collapse creating unrealistic meteorological 

conditions and significantly impacting the modeled dispersion (refer to the TSD for additional 

details). This assessment leads to EPA’s approval of CALPUFF 5.8 as the approved version, 

announced on June 29, 2007. Furthermore, PNM did not consult with Region 6 to establish a 

protocol for additional CALPUFF modeling as part of the BART visibility analyses, and while 

they chose to generally follow the protocol developed by the WRAP specifically for BART 

screening analyses], PNM deviated in some ways. In addition, a site specific protocol for SJGS 

should have included additional refinements in model settings and incorporation of data. we 

 

220 CALMET/CALPUFF Protocol for BART Exemption Screening Analysis for Class I Areas in the 

Western United States (August 15,2006; available at: 

http://pah.cert.ucr.edu/aqm/308/bart/WRAP_RMC_BART_Protocol_Aug15_2006.pdf ...) 221 “CALPUFF: Status and Update” , Dennis Atkinson, Presentation at Regional/State/Local Modelers Workshop, 

May 16, 2007. 

(http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/archive/2007/presentations/Wednesday%20-

%20May%2016%202007/CALPUFF_status_update.pdf); EPA report, “Assessment of the “VISTAS” Version of 

the CALPUFF Modeling System”, EPA-454/R-08-007, August 2008 available at 

(http://www.epa.gov/ttn/scram/reports/calpuff_vistas_assessment_report_final.pdf); “CALPUFF Regulatory 

Update”, Roger W. Brode, Presentation at Regional/State/Local Modelers Workshop, June 10-12, 2008, 

available at 

(http://www.cleanairinfo.com/regionalstatelocalmodelingworkshop/archive/2008/presentations/BRODE_CA.pdf

). 
137 

specifically noted several deviations from appropriate practice in PNM’s implementation of the 

meteorological processing model for CALPUFF, named CALMET, in addition to model 

versions issues. PNM’s CALMET modeling utilized radii of influence values inconsistent with 

EPA/FLM guidance, and did not follow the EPA/FLM guidance about including upper air 

observational data. Finally, the CALPUFF modeling system (including CALMET) versions 

used by PNM did not follow EPA and FLM recommendations and guidance. NMED received 

comment on not being consistent with established BART modeling procedures from the FLM’s 

during the proposed 308 SIP in August 2010. PNM has also alleged that variable ammonia 

concentrations should be used, which is inconsistent with the WRAP’s BART screening protocol 

and modeling. Furthermore, NMED specifically requested that PNM perform modeling using 

the default constant 1 ppb background ammonia concentration on multiple occasions in 2008 as 

they were developing the proposed RH SIP. These numerous deviations from our guidance 

methods and procedures and use of an alternate model version were not considered by the 

commenter. These deviations are discussed further in the Technical Support Document that 

accompanied our proposal. 

As discussed in section 4.3.1 and table 4-6 of the TSD, our sensitivity modeling results 

support the conclusion that the differences between the WRAP BART screening protocol and 

our current regulatory approach would not likely change the original determination by the 

WRAP and NMED of which sources screen out of BART and which are subject to a full BART 

analysis. We disagree, however, that PNM’s modeling was acceptable modeling for evaluating 

the visibility impacts to inform a BART determination. It would have been inappropriate for us 

to use a CALPUFF model version with known problems/errors to support our proposed BART 

determination instead of using the CALPUFF version we approved for regulatory review. 

Therefore, our BART CALPUFF visibility modeling sought to correct the deficiencies in the 

PNM BART CALPUFF visibility modeling. In addition, given that the emission rates that we 

proposed as NOx BART differed from those used in PNM and NMED’s BART visibility 

modeling, it was necessary to perform our CALPUFF visibility modeling, following EPA/FLM 

guidance and practices, to assess the anticipated visibility improvements from the use of SCR 

with our proposed BART lower emission rate of 0.05 lb of NOx/MMBtu (NMED/PNM 

modeling used an emission rate of 0.07 lb of NOx/MMBtu for SCR). As discussed in the TSD, 

we also had updated emission estimates for sulfuric acid emissions based on the latest 

information that was included in our modeling. We therefore disagree with the commenter and 

have explained why we needed to do our own BART CALPUFF visibility analysis. We used the 

approved version of the model in accordance with the appropriate procedures, as discussed 

further in other response to comments and we are confident in using our results as one of the five 

factors in making a BART determination. . The commenter did not provide any direct 

comments indicating that our BART visibility modeling differed in any way from EPA and FLM 

modeling guidance and standard practices that EPA and the FLM representatives have approved 

in other protocols. 

With regard to the commenter’s suggestion that more recent versions of CALPUFF be 

used, as discussed in more detail in another response, the two suggested model versions have not 

gone through the appropriate review to assess if they are founded in appropriate science and 

perform adequately and reliably and are an improvement to the current version that is acceptable 

for regulatory actions. PNM did not submit the modeling files as part of its comments. Instead, 
138 

the PNM submitted report only includes a summary of the modeling results. Therefore, 

sufficient evidence has not been presented to support PNM’s claims had we wished to review 

this modeling done with non-approved models. Because the model results provided by the 

commenter cannot be evaluated and because we have no basis to conclude that these versions 

provide reliable results, we did not conduct a full review of the submitted summary of the model 

output results. In looking over the summary of the modeling results in the submitted report, 

however, we continue to have significant concerns with the model version and options/inputs 

used given that the results are indicating drastically lower values than our modeling that was 

conducted with CALPUFF Version 5.8. 

We disagree with the use of a higher grid-resolution (1-km) for modeling of visibility 

impacts using the CALPUFF modeling system. Current EPA guidance from the May 15, 2009 

EPA Model Clearinghouse memorandum defaults to a horizontal grid resolution of 4-km. While 

this guidance does not automatically preclude the use of higher resolution meteorological fields, 

the memorandum discusses five issues that should be addressed in considering use of a 1-km 

meteorological grid. None of these five elements were addressed by the commenter. Among the 

elements that should have been considered were a discussion of the nature of SJGS’s sourcereceptor relationship to Class I areas in the modeling domain and meteorological characteristics 

which govern these source-receptor relationships, a statistical performance analysis showing the 

inadequacy of the 4-km CALMET fields, demonstration of the technical adequacy of CALMET 

diagnostic algorithms in a complex terrain situation, statistical evaluation demonstrating that 1-

km CALMET fields perform better than 4-km fields in this specific situation, and discussion of 

how the enhanced resolution impacts the air quality model. When CALMET is using much 

higher grid resolutions, such as 1-km grid, on the original Numerical Weather Prediction files, 

the CALMET meteorological model performance must be examined through appropriate 

statistical analysis to understand if the CALMET diagnostic adjustments perform appropriately. 

The Report presented no evidence to support the claim that a 1-km resolution increases the 

accuracy of the final wind field in specifically modeling the SJGS. The commenter has not 

provided any statistical or other analyses to justify such a deviation for modeling of the SJGS. 

The commenter did not establish the nature of source-receptor relationships and meteorological 

characteristics that are associated with it in support that a finer resolution is necessary or 

beneficial. The commenter has not established what the effect would be on dispersion using on 

plume half-height algorithm (MCTADJ = 3, default from IWAQM recommendations) at 4-km v. 

1-km. Furthermore the commenter has not established the relationship between grid resolution 

and chemistry conversion equations. Since CALPUFF is a Lagrangian model, chemistry does not 

take place on computational grid, but is based upon volume of puff. The volume of the puff is 

governed by sigma-y and sigma-z, and the model developer has not established how higher 

LULC (Land Use Land Cover) resolution will change model projections and if that is an actual 

improvement or degradation in accuracy. The commenter failed to establish that going beyond 

the resolution necessary for good meteorological model performance characterizing the synoptic 

was necessary for good air quality model performance. We are using one model domain to 

examine impacts at multiple Class I areas, thus the nature of source receptor relations will be 

somewhat different depending upon the distance between the source and the Class I areas. The 

commenter has not provided analyses that the 4-km CALMET domain is not performing 

acceptably considering the multiple Class I areas being evaluated. The commenter did not 

provide information establishing the technical adequacy of CALMET diagnostic algorithms to 
139 

address technical concerns with complex terrain effects with a 1 km grid. Consistent with EPAFLM recommendations for CALMET and the WRAP BART screening modeling protocol, we 

determined that a 4-km grid resolution should be used. 

 

We also disagree with the use of the Ammonia Limit Method which is also called ALM 

and note that it is inconsistent with the nitrate repartitioning approach that has been previously 

accepted by the FLMs and EPA. There is a lack of documentation, adequate technical 

justification, and validation for the development and use of the ALM. We and the FLMs have 

previously reviewed protocols proposing using ALM and we and/or the FLMs have not approved 

the use of the proposed ALM procedure. In general terms, one of the key issues is ALM is a 

method to have emissions from other sources consume ammonia, so there is less ammonia to 

react with the source of interest being modeled. Since ammonia levels from the local area 

around the plant were used by EPA, to do calculations in the modeling to consume ammonia 

from surrounding sources would unnaturally consume ammonia that was actually monitored in 

the vicinity of the SJGS. The ALM has not been approved by EPA and the FLMs through 

interagency workgroups (IWAQM or FLAG) as an approved part of CALPUFF based visibility 

analyses. The commenter has not provided any adequate justification, documentation, or other 

analyses to justify the proposed use of ALM. 

Furthermore, the use of ALM requires the input of background ammonia concentrations 

as well as background concentrations of sulfate, nitrate, and nitric acid. The commenter used 

background concentrations derived from modeling simulations of the EPA Community 

Multiscale Air Quality Modeling System (CMAQ) for 2002. The Report’s summary shows that 

monthly averages of predicted concentrations for ammonia, sulfate, nitrate, and nitric acid at a 

grid resolution of 36 km were used as model inputs to apply the ALM. As discussed in a 

separate response to comments, available ammonia monitor data indicates that ammonia 

concentrations are higher in the vicinity of the SJGS and city of Farmington than at the Mesa 

Verde Class I area (approximately 42 km from SJGS). The use of 36 km resolution model 

predictions results in an average ammonia level for the entire 36km by 36 km grid cell and does 

not reflect the higher ammonia concentrations measured near the SJGS which are of greater 

concern for determining visibility impacts from the source. In addition, the CMAQ model 

predictions that the commenter used are not an appropriate estimation of background ammonia 

available for reaction with the SJGS emissions since this CMAQ simulation of “background” 

concentrations already includes SJGS emissions and reactions they have in the atmosphere. The 

background ammonia concentration that the commenter input into the non-approved CALPUFF 

model has already been decreased by reaction with SJGS emissions in the CMAQ model 

predictions. 

The commenter also provided a summary of the modeling results based on variable 

ammonia levels using CALPUFF version 6.112 and 6.4. We disagree with the use of variable 

ammonia as we have responded to comments about using variable ammonia levels in another 

response to comment. We note that variable ammonia levels were not approved in the WRAP’s 

BART screening modeling protocol, nor in protocols by NMED in their 2010 proposal, nor by 

EPA Region 6 as the commenter seemed to indicate in their comment. 

We note that the summary of the report’s BART visibility modeling results shows that an 

SCR emission rate of 0.07 lb/MMBtu was used, rather than the 0.05 lb/MMBtu that we included 
140 

in our proposal. Using this higher level of 0.07 lb/MMBtu would bias the reduction in impacts 

from the installation of SCR lower than what we proposed. If their modeling was conducted 

using our proposed emission rate, it may have shown a value greater than 0.5 dv for each 

individual unit. This is not relevant though given the numerous issues associated with their 

modeling analysis as discussed above. Moreover, as noted in the BART Guidelines, the 

CALPUFF model results are useful for considering the comparative impacts of single sources on 

visibility impairment in a relative sense and relative to other sources, SJGS’s impacts are 

significant. We note that the SJGS is one of the single largest sources of NOx in the United 

States and located close to 16 Class I areas. As such, even without modeling results, one could 

conclude that the source is likely to contribute to significant visibility impacts at multiple Class I 

areas and that the installation of SCR would lead to meaningful visibility benefits. We also 

note that our modeling looked at the dv improvements at 16 Class I areas and indicates even 

greater visibility benefits at other Class I areas than Mesa Verde. The summary of the modeling 

results provided by the commenter do not evaluate improvements at other Class I areas or any 

cumulative visibility improvement benefits of SCR, yet they asserted that their analysis showed 

the maximum impacts from SCR at any Class I area. As we note elsewhere, we actually 

projected the largest visibility improvement due to SCR control level at the Canyonlands Class I 

area. As a result, there is no evidence to support the commenter’s claim that the largest 

improvement was less than 0.5 dv at any Class I area. Given the relative size of SJGS and its 

location as compared to other BART sources, such results would be surprising. We conclude 

that our modeling which was performed using an accepted CALPUFF model version and 

following applicable guidance and EPA/FLM recommendations is an appropriate approach for 

assessing the visibility benefits due to the use of SCR. This modeling confirmed that our NOx 

BART determination will result in significant visibility benefits. 

Comment: A commenter alleged that EPA lacks the requisite statutory authorization in 

this proceeding to implement its proposed emission limits for H2SO4 and NH3 emissions from 

the SJGS. The commenter indicated that if EPA has not shown that limits on emissions of 

H2SO4 and NH3 from the SJGS will result in reduced visibility impairment or make reasonable 

progress in a class I area’s Reasonable Progress Goal, the Agency has no authority under CAA 

§169A to require the proposed emission limits on those pollutants from SJGS. The commenter 

also alleged that if EPA has not shown interference from H2SO4 or NH3 emissions, EPA has no 

authority to regulate these pollutants under CAA section 110(a)(2)(D)(i)(II). EPA has not shown 

that its conclusory statement that the proposed limits will “minimize the contribution of these 

compounds to visibility impairment” falls short of demonstrating a visibility-impairment 

contribution that is necessary to authorize regulation of those compounds under Section 169A. 

The commenter indicated that if EPA has no other policy reason other than appropriate 

considerations of comity, EPA should defer to New Mexico’s determination of which pollutants 

to regulate with BART requirements. The commenter noted that New Mexico’s proposed 

regional haze SIP under section 309 of 40 C.F.R. part 51 and the withdrawn regional haze SIP 

proposal under section 308 both demonstrates the State’s intent to regulate regional haze during 

the first planning period with controls only on emissions of SO2, NOx and PM. The commenter 

concluded that any proposal by EPA to limit emissions of either H2SO4 or NH3 from New 

Mexico sources goes beyond the planned scope of the State’s regional haze SIP and should be 

abandoned. The commenter also indicated it is unclear from EPA’s proposal if its action is being 
141 

proposed under CAA section 110(a)(2)(D)(i)(II) as an Interstate Transport provision related to 

visibility, id., or instead under CAA section 169a as part of a BART determination for the SJGS. 

Response: For the reasons discussed elsewhere in our response to comments, we have 

determined that neither an ammonia limit nor ammonia monitoring requirements are appropriate. 

The design plans for the SCRs that will be submitted will address design and operation of SCRs 

based on a maximum ammonia slip level of 2 ppm. Proper design and operation of the SCR 

should be protective of visibility impairment modeling projections. We disagree with the 

commenter concerning the need to regulate H2SO4. If a power plant is installing SCR at an 

existing facility in an area where a state has a concern about PM2.5 and regional haze impacts, it 

would be normal for a state to consider the imposition of limits on H2SO4 to minimize/limit the 

amount of degradation in visibility due to any increases in these pollutants. 

As we discussed in our proposal, we have concluded that the low sulfur coal burned at 

the SJGS generates very little sulfur trioxide (SO3), and hence H2SO4, which is formed when 

SO3 combines with water in the flue gas to form H2SO4. In addition, SCR catalysts are available 

with a low SO2 to SO3 conversion of 0.5%, further limiting the production of H2SO4. 

Nevertheless, several modeling runs were conducted with different H2SO4 emission levels and 

that modeling indicated that increases in H2SO4 did result in some visibility degradation at Class 

I areas in New Mexico and surrounding states. Some of the H2SO4 runs we performed were not 

used in the final decision modeling analysis, but provided a basis for being concerned about 

potential H2SO4 impacts and thus limiting the amount of growth in H2SO4 from our action. 

To address questions from NMED regarding the inherent removal of SO3 by existing 

control equipment and removal by sorbent injection, PNM performed additional modeling to 

estimate the visibility impacts resulting from lower estimated sulfuric acid emissions.222 We 

note, as detailed in the TSD, our estimates of sulfuric acid emissions are significantly less than 

those estimated by PNM, and support the conclusion that sorbent injection is not required. 

Furthermore, PNM’s modeling deviated from EPA guidance and utilized a model version not 

approved for regulatory use. However, this modeling performed by PNM provides an example 

of the impacts of sulfuric acid emissions on visibility. For all Class I areas modeled the 

reduction in sulfuric acid emissions estimated by PNM due to sorbent injection led to a decrease 

in visibility impacts.223 For example, PNM model results indicate that visibility impacts at Mesa 

Verde decrease by 1.34 dv when their H2SO4 emission estimates were reduced and all other 

emissions are kept constant. 

Our modeling similarly shows that emissions of H2SO4 can adversely impact visibility 

conditions. We performed visibility modeling with estimated sulfuric acid emissions calculated 

by the NPS and submitted to NMED in response to the proposed Regional Haze SIP that differed 

 222 PNM San Juan Generating Station Review of Inherent SO3 Removal Scenarios and Sorbent Injection for SO3 

Removal, Black and Veatch, March 16, 2009 

 (http://www.nmenv.state.nm.us/aqb/reghaz/documents/COMPLETE_Final_SO3_Removal_Report_031609.pdf 223 See Table 2 on page 19 of PNM San Juan Generating Station Review of Inherent SO3 Removal Scenarios and 

Sorbent Injection for SO3 Removal, Black and Veatch, March 16, 2009 
142 

from certain assumptions and methodology used by NMED for SJGS.224 These emissions 

estimates were later revised by NPS after discussion with EPA region 6, 225 resulting in a 

reduction in the estimated emissions. Our modeling was updated to reflect these changes. 

Comparison of these two modeling scenarios provides further evidence of the impact of 

relatively small changes in sulfuric acid emissions on visibility. The original estimate for 

sulfuric acid emissions calculated by NPS totaled 17.84 lb/hr, and the revised estimate totaled 

1.99 lb/hr for the 4 units. Even at these low emission rates, a small increase in sulfuric acid 

emissions does increase visibility impairment. For example, the average modeled visibility 

impact at Mesa Verde increases 0.09 dv when sulfuric acid emissions are increased from the 

revised estimate to the original estimate levels. 

In summary, we conclude that emissions of H2SO4 will not be a significant concern at the 

SJGS. However, modeling conducted by us and some modeling results provided by PNM’s 

contractors indicate that visibility impairment could worsen if emissions of H2SO4 are not 

limited in an enforceable manner. We do not wish to allow a growth in emissions to occur that 

would undermine the NOx reductions that we are requiring to ensure that NM emission sources 

do not interfere with visibility in other states as required by the 110(a)(2)(D)(i)(II). Therefore, 

we believe we have struck the right balance in limiting emissions of H2SO4 to a reasonable level 

verified by annual stack testing. We are controlling H2SO4 under the BART provisions of the 

RHR and CAA Section 110. Our regulatory authority includes CAA section 169A(b)(2), 40 

C.F.R. 51.308(e)(1)(ii) and CAA §110(a)(2)(D)(i)(II). 

Q. Comments Not Relevant to the Proposal 

Comment: We received comments not related to the proposal. These included comments 

on: 

• relying on a diversity of resources to maintain low cost reliable energy supplies, 

• expanding the region's reliance on lower carbon and water efficient sources of energy, 

• increasing energy efficiency and power generation from renewable sources, 

• decreasing coal-fired power generation, and 

• greenhouse gas emissions. 

Response: While these and other comments not related to the proposal may be important 

topics for discussion, we are not addressing these topics in our rulemaking. 

 224 Comments of the National Park Service and US Fish and Wildlife Service Regarding the New Mexico Regional 

Haze State Implementation Plan August 17, 2010 (http://www.nmenv.state.nm.us/aqb/reghaz/documents/FWSNPS_Comments-NewMexicoRegionalHazeSIP-17AUG2010.pdf) 225 Don Shepherd to Michael Feldman, EPA Region 6 (electronic mail) dated Nov. 1, 2010 – revised NPS 

calculations to correct for errors in penetration factors.