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

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

8/5/2011Table 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 Relian ce on the EPA Air Pollution Control Cost

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

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

C. Comments on our Proposed SO 2 Emission Limit ....................................................... 66

D. Comments on our Proposed H 2 SO 4 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 Ecosyste m Benefits, and other Pollutants ......................... 78

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

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

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

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

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

L. Comments Requesting an Extensi on 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 .................................................................. 142A. Comments on the Costs of the NOx BART Determination

1. General Cost Comments

Comment: The National Park Service (NPS) pres ented information in support of their opinion that PNM’s contractor Black & Veatch ha s 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 effect iveness of other analyses used to establish the acceptable cost range should also be adjusted fo r 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 constructi on indirects were typically 50% to 60% of installation labor costs. In the post-2005 period, they reported construction indirect s rose to a range of 90% to

120% of installation labor costs due to tightening in labor mark ets. 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" magazine 1 : "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 dram atic 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 estimat es for three years (from the date of the survey to the end of 2007) produces an average SCR system installe d cost of$185/kW..." (or $184/kW in 2009 $).

"Overall, costs were reported to be in th e $100 to $200/kW range for the majority of the systems, with only three reported installations exceeding $200/kW."

Five industry studies conduc ted between 2002 and 2007 have reported the installed unit capital cost of SCRs, or the cost s actually incurred by owners, e xpressed in dollars per kilowatt.

1 June 13, 2009 "Power" magazine article "Air Qua lity 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-complia nce-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 ye t available). The second survey of 40

installations at 24 stations re ported a cost range of $75 to $240/kW, converted to 2009 dollars. 3
The third study, by the Electric Ut ility 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 co urse 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 operati onal in 2006 or were sc heduled 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 (A EP) estimated that the average capital

cost to install SCRs to re move 85-93% of the NOx from many of its units was $162/kW. 10 The NPS also references a graph constructed by EP A 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 in to 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 S CR 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/i s_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, Curren t Capital Cost and Cost-Effectivene ss of Power Plant Emissions Control Technologies, June 2007, pp. 28-29, Figure 7-1 (Ex. 1).

7 Wisconsin Electric Power Company's Ap plication 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 Fl ue Gas Desulfurization and Selective Catalytic Reduction Facilities and Associated Equipment on Oa k 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/presen tldocuments/2008EEI-Fact-Book.pdf.3 MegaSymposium (provided by the NPS in an appe ndix). Despite the limited space and other obstacles, the SCR installation cost $224/kW. 11 It should also be not ed 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 th at 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/MMB tu)." 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-constr ained retrofit in which the SCR was built 230 feet above the power station usin g 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 typi cally 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 th e "Coal Utility Environm ental Cost (CUECost) estimates, cost data supplied by equipment ve ndors (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 nati on. NMED's December 21, 2007 letter specifically requested that PNM use OAQPS Cost Manual met hod. The USFS also takes issue with PNM's estimation of indirect (soft) costs which incl ude: engineering costs; construction and field expenses (i.e., costs for construc tion supervisory personnel, office pe rsonnel, 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 "sta ff 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 inclus ion 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-=-Su premely-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/sampie updateslNoxMarketUpdateSample.htm4 - $568/kW (in 2010 dollars) TCI provided by PNM i ndicates overestimates throughout their cost analysis. PNM's contractor Blac k & Veatch deviated from standa rd 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 additi onal time to install. The large amount NOx emissions from SJGS (15th largest in the nation) necessitate a tig hter 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 severa l 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 term s 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 Instal ling 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 Guid elines, “[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 (dep ending on the unit) with a total cost of $908 million for all four units. EPA maintains th at 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 sh ort, 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 di sparity 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 have5 reported the installed unit capit al cost of SCRs to be $79/kW to $316/kW, where the upper end of the range is for very complex retrof its 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 ra nge of expected costs for such

controls.

We believe the difference between our costs a nd 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. Th e revised costs, summarized in Exhibit 1, RTC Revised Cost Analysis, range fr om $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 Construc tion (AFUDC)) that has been disallowed under EPA”s Cost Manual methodology and specifically di sallowed for SCR; (2) consistently using assumptions at the upper end of the range fo r 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 inj ection, SCR bypass); and (4) using excessive contingencies. The BART Guidelines require that "documentation" be provided for "any

unusual circumstances that exist for the source th at 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 Sta tion 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 anal ysis. 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 Schedul es 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 Selectiv e 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 Ex isting Facilities (underground util ities, 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 co sts 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 e ssential to document site-specific conditions that lead to costs outside of the normal range.

Instead of preparing a site-specific SCR de sign, Black & Veatch in most circumstances made a worst case, upper bound assumption that, take n together, result in ove rall costs that are significantly outside of the normal range for SC R. However, Black & Veatch provided no record support for their decision to choose the upper end of the ra nge for nearly every aspect of the cost of SCRs. It is unlikely that so ma ny 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 be lieve that our approach to consid ering 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 re futed 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, wh ich by its nature must account for site-specific challenges at each facil ity. 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 ch allenges at SJGS, EPA did not to take into account many of the most significant costs that ar e essential in calculating an accurate cost estimate of installing SCRs at SJGS.7 Response: We agree that a source-by-source anal ysis is appropriate. However, we do not agree that Black & Veatch provided a site-sp ecific 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 u pper 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 contin gency factors. In response to direct questions as to why various things are assumed, gene ral site specific cons traints are alleged, bu t none are identified specifically or supported with any drawings , photographs, or engi neering calculations. 23
Therefore, we feel, with the exception of certain issues related to site congestion that are addressed separately in other comments, all cost s 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 pr ocess of designing and constructing an SCR, thereby not only ignoring th e technology itself, but also the si te 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 instal led since the early 1990s in the United States. Accordingly, constructability issues are well understood. Standard design and construction management methods have been develope d from these 300+ existing installations. 24 This experience would inform the design and construc tion of the SJGS SCR, resulting in significant economies compared to the estimates presente d by Black & Veatch based on a very rough preliminary design that has not been optimized fo r constructability. The record does not identify any unusual site-specific conditions that would result in direct inst allation 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 (structura l 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/libra ry/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, Bl ack & Veatch has provided no support in the record for its assumptions. Finally, the design costs are not a direct installation co st, 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 ti me and money. While some economies may arise with a multiple SCR installation, as lessons le arned in designing and installing one SCR are applied to the next, a three-year deadline would require PNM to de sign 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 unfor eseen 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 "multip le 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 mu ltiple 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 contro l system. Economies arise fr om shop and material discounts based on quantity. Our cost analysis, however, did not assume any discount for multiple unit discounts. Regardless, for other re asons 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 acknowl edge, or take into account, the $330 million incurred in the past five years implemen ting 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 pol lution 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 c ontrols included the in stallation 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 con tinuous 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 consider ation the technology available, the costs of compliance, th e energy and nonair quality environmental

25 Revised BART Cost Effectiveness Analysis for Selectiv e 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 contro l 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 anti cipated 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, ov er 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 th e assumptions used in the WRAP modeling will ensure that emi ssions from New Mexico source s do not interfere with the measures designed to protect visi bility in other states.” 76 Fed. Reg. at 496-97. EPA states that the WRAP modeling assumed that SJGS’s NO x 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 character ized by EPA), additional NOx emission controls are required. EPA, however, proposes on this ba sis 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 disconti nues its evaluation of them before fully assessing their relative cost-effectivene ss and other factors mandated by section 169A(g)(2)

of the Act. See id . EPA’s analytical approach is in c onflict with its own BART rules and is inconsistent with a logical approach to a ssessing relative cost-eff ectiveness of various technology options. Cutting off a full analysis af ter 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 uni ts 1, 2, 3, and 4 of the SJGS were subject to BART, we conducted a fu ll five factor BART analysis (40 CFR 51.308(e)(1)(ii)(A)), rather than relying on the WRAP mode ling. In conducting the BART analysis, we identified all available retrofit control technologies, in cluding Selective Non Catalytic Reduction (SNCR), considering the technology available, the costs of compliance, the energy and non-air quality environmental impa cts of compliance, any pollution control equipment in use at the source, the remaining useful life of the sour ce, 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 a ssess other NOx control technologies. 28

27 “You are expected to identify potentially applicable retr ofit 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 s hould 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 Ne w 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 Guid elines supports a NOx emission rate for the SJGS of between 0.23 to 0.39 lb/MMBtu, as opposed to our propos ed 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 statutor y 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 not ed 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 presump tive 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 stri ngent control options could achieve that limit. A five-factor BART analysis of increasingly stri ngent control options coul d then properly assess incremental costs (and cost-effectiveness) and any be nefits 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 c ontinuous emission contro l technology for each source subject to BART taking into account the technology available, the costs of compliance, the energy and non-air quality environmental im pacts of compliance, any pollution control equipment in use at the source, the remaining useful life of the sour ce, and the degree of visibility improvement that may be e xpected from availa ble control technology 29

The RHR also states:

States, as a general matter, must require ow ners 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 grea ter 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 leve l 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 increasing ly 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 significa nt 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 leve ls achievable by the SN CR technology recommended by the State.

Comment: To meet a three-year deadline, PNM w ould have to prefabricate as much of the SCRs as possible. In addi tion, a three-year deadline would also require significant overtime hours, expedited material costs, double “heavy long -lift” crane costs, a nd a larger construction

workforce overall. Because these costs would ne ver be incurred in the normal course of installing SCRs, PNM did not include these costs in its analysis, but th ey would be unavoidable in the event a three-year deadline is required. Such a short construc tion 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, pa rticularly 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 mo dified the schedule for compliance with the emission limits to now require compliance within 5 year s – rather than 3 year s -- from the effectiv e date of our final rule. We believe this compliance schedule will provide adequate time to schedule the necessary

labor resources for the installati on 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-effectiv e solution. Instead, it represents a broad considerati on of technical, economic, ener gy, 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 visi bility in multiple Cl ass I areas warrants a higher cost/ton than where only one Class I area is affected. The N PS 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 Wiscons in 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 ev aluate 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 th e $/deciview metric. One commenter states EPA has not appropriatel y considered the costs of comp liance 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 pr ojected to achieve and proposes the $/dv as the means for making a ra tional comparison of the relative cost-effectiveness of control

measures.

This commenter also states that a met hod that aggregates projected visibility improvement in each affected cl ass 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 appro ach 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 valu es 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 virt ually meaningless in the context of the RH program. Thus , EPA’s assessment of the $/t on costs of BART candidates for the SJGS is flawed because the pr emise for its use is faulty, i.e., a change in emissions is not a suitable surrogate to represen t a change in visibility.

Another commenter believes that a dollar per deciview of vi sibility improvement metric

would be more in line with the overall goal of the RH program, name ly 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 $/ton 32 . 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 Specifi c 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 NP S 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 detail ed 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 co st estimate with their own estimate of an average cost of $2,600/ton for th e 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 we re overestimated by PNM. Please see elsewhere in our response to comments for our opinion rega rding the appropriate estimated costs for these

and other cost items. We note th at the NPS estimate of an aver age 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. Th e Region 6 cost analysis recognizes that the14 installation of SCRs at SJGS will require addition al 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 disco unted by nearly 80 percent the estimated cost of the auxiliary power upgrades need ed 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 continue d 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 di fficult 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 tr igger the need to upgrade the auxiliary power system. We believe this is incorrect. The auxiliary power upgrade is required due to the cumula tive effect of the Consent Decr ee projects (LNBs/OFA, scrubber upgrade, baghouse, carbon injection) and the S CR. These projects were planned around the

same time. PNM has not identifie d 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 c ontrol centers that will serve the entire fan auxiliary loads of both the Cons ent 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 projec ts 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 cumula tive effect of these control projects exceeded the capacity of the auxiliary power system.

33 Black & Veatch, San Juan Generation Station BART Proj ect, 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 po wer 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 a uxiliary power system by 80%, but rather distributed it among the control projects planned around the same ti me that triggered its need according to each control's contribution to draft pr essure lost. This is a standard engineering practice.

Comment: EPA failed to account for additional co sts associated with protecting the air preheater following an SCR Installation. Retr ofit SCRs are designed to convert NOx into nitrogen gas and water through the injection of a mmonia 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 c ondenses in the air preheater where flue gas temperatures drops to the dew poi nt of ABS. ABS is an acidic substance that forms a sticky deposit on heat transfer surfaces, resulting in bot h corrosion of the equipment and the collection of fly ash that plug passages, which ultimately impai rs the efficiency and reliability of the unit. As such, the installation of a retr ofit SCR generally requires a modi fication to the air preheater to allow for easier cleaning of the basket surfaces in order to protect the h eat 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, “pendi ng compelling justification that they are required for the SCR.” Region 6’s cost analysis recognizes that modifications to the air preheater are generally required fo r “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 di fference between “high” and “low” sulfur coal, Region 6 assumes that SJGS would not experi ence 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 pr epared by Sargent and Lundy for the Navajo Generating Station, which did not recommend modificat ion of the air preheater if SCR were required for that facil ity. Region 6 also cites an arti cle 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 th e assumptions and recommendations made in the BART determination report prepared for that source are not ba sed on actual operating experience. Perhaps more importantly, however, the Region’s characterization of the report as suggesting that ABS is not a concer n is inaccurate. On the contra ry, the BART analysis prepared for the Navajo Generating Station includes th e following discussion of the dangers of ABS formation in the air preheater fo llowing installation of an SCR:

The application of SCR technology to coal fire d 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 th e sulfur dioxide in the flue ga s to sulfur trioxide. Under certain temperature and concentration conditions, th e sulfur trioxide will r eact with ammonia slip

from the SCR reactor to form a mmonium bisulfate (ABS) which will tend to deposit in the air preheater. If favorable conditions for this re action persist and ammonia concentrations reach16 higher than the designed value of 2 ppmvd, freq uent 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 pressu re 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 corrode d material further enhances the deposition of ammonium bisulfate and accelerates the plugg ing mechanism. The ABS dew point while burning bituminous fuel will be in the temperatur e range of 590 °F to 615 °F. The melting point of this compound is 300 °F and the boiling poin t is 914 °F. Once this compound is formed, it will be in liquid phase above 300 °F and the so lid 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 bot h Navajo Generating Station and SJGS are below the 300o F threshold, both projec ts units would be at risk fo r 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 r ecommendation was based on the specific emission characteristics at Navajo Genera ting Station, which differ significan tly from those at SJGS. For instance, although SJGS does burn rela tively low sulfur coal, the sulf ur content is still typically higher than that of the coal burned at the Na vajo 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 c ontent is one-hundred-eight per cent (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 Gene rating Station seem to have been completely ignored in the effort to rely on the BART dete rmination for the Navajo Generating Station to delete the air preheater costs from the SJ GS 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 posit ion. 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 attrib utable 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 transien t load conditions.” In other wo rds, even if ammonia slip is generally kept below 2 ppm, changes in load wi ll likely result in higher slip that will form ABS in the air preheater. Region 6 ignor es 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 th e 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 gene rically describes only three parame ters. 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)

SJGS 36 0.77 21.29 9,692 Navajo 37 0.63 10.36 10,418

The differences in coal quality are either not ma terial (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 & Lu ndy 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 (SO 3 ) and ammonia (NH 3 ) in the exhaust gases that reach the air preheater and the air preheater temperature regime. 38

The amount of ammonia is an SCR design pa rameter and is controlled by the ammonia injection system, not coal quality. The design a mmonia slip for both the SJGS and Navajo SCRs is 2 ppm. Regardless of small differences in co al sulfur content, some of which becomes SO3,

actual test data indicate that SO 3 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 preheate rs at the two plants are about the same.

The formation of ammonium bisulfate depends on the relative amounts of NH 3 and SO 3 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 preferen tially 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 fo r the nearby Navajo Generating Station, which burns a similar coal, ammonium bisulfate fou ling would not be expect ed and no upgrades are justified for the air preheate rs 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 Un its 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 an d 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.airpreheater company.com/Data/DownloadDocum ents/Mega%20Symposium%201999.PDF.

41 The average NH3 slip concentration ov er the catalyst lifetime is 0.75 ppm (EPRI, Estimating Total Sulfuric Acid Emissions from Stationary Powe r Plants, 2010, p. 4-10). The NH3 flow rate for each un it 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 th e likelihood of any ammonium bisulfate plu gging at SJGS, compared to Navajo, as the SO 3 and ammonium bisulfate are absorbed by the ash particles before they reached the air preh eater 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 inj ection upstream of the air preheater has been used as a control technology for SO 3 . Particles have been intentionally injected into the flue gas upstream from the air preheater to enhance SO 3 removal. The particles provide nucleation sites for hete rogeneous condensation in pref erence 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 preheate r fouling potential than Navajo, where Sargent & Lundy concluded air preheaters modi fications were not required.

Thus, for all of these reasons, ammonia bisulfat e deposition should be less of a concern at SJGS than at Navajo. Sargent & Lundy conclu ded based on a more complete SCR design than available for SJGS that air preheater modificatio ns were not required, as this excerpt from the Navajo BART analysis demonstrates:

3.5.5.3 Air Preheater Recommendation

Based on normal catalyst performance, NH 3 slip should range from a negligible value during initial operation to less th an 2 ppm towards the end of the catalyst life. After the SCR installation, SO 2 levels as high as 6 ppmvd at 3% O 2 are possible. SRP currently operates on a th ree 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 SO 2 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 SO 3 and NH 3 flue gas concentrations are low. The key design methods are ensuring proper cata lyst design, including 2 ppm ammonia slip and

maximum 0.5% oxidation of SO 2 to SO 3 across the SCR reactor and ensuring NH 3 /NOx distribution requirements are conf irmed by CFD and physical flow modeling to avoid large areas of high ammonia slip. 44 These standard practices presumab ly 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 fa ct, 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 th e 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 NH 3 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 NH 3 to SO 3 is greater than 2, as is the case he re, 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 s lip level will be the controlling factor in the extent to which these deposits in terfere with rout ine unit operation." 45 The sulfur content of the SJGS coal, 0.77%, is low compared to most Americ an coals, which typically have from 1% to

4% sulfur.

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

installation of SCR at SJGS woul d increase the resistance in the fl ue 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 pr essure 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 an d 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 Associat ion (NFPA) Code 85. NFPA 85 governs fire and im plosion protection for Boilers and Combustion Systems and establishes structural and controls design requirements that mu st be incorporated. Throughout the industry, state inspection au thorities and insurers routin ely use NFPA 85 as a minimum standard to determine when a boiler requires st iffening for implosion a nd 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 la rger ID fans will be needed and that an SCR would increase the flue ga s 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 require d, 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 woul d be a necessary part of any SCR project at SJGS to maintain a safe and reliable facility that also meets code requireme nts. 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 po llution control equipment that already exists at the site in an effort to argue that those c ontrols, not the SCR, trigger the need for additional boiler and duct stiffening. In fact, partial bo iler stiffening was alrea dy performed during the installation of the existing contro ls to bring the unit into comp liance 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, st atic mixers, and duct work. Determining the pressure drop due to the SCR requires a more a dvanced 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 draw ings; 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 pressu re drop likely has not been optimized and could be significantly reduced by catalyst selecti on (e.g., by using honeycom b with large pitch) 47 and ductwork design. An SCR system is normally de signed 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 w ith 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. Therefor e, 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 bo iler stiffening costs that “[m]y review of the 2004 and 2007 revisions of NFPA 85 indicates th at the 2004 revision of the [relevant code provisions] applied to the Consent Decree projects.” The “Consent Decree” projects referenced in the Re gion’s cost analysis include th e demisters, low NOx burners, baghouses, and activated carbon inje ction systems that PNM instal led in compliance with a 2005

Consent Decree. Dr. Fox makes the asserti on 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 attr ibuted 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 even tually 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_g as/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 Installatio n on New Coal-Fired Project, Institute of Clean Air Companies, ICAC Forum '98, March 1998, Available a t: http://www.babcock.com/libra ry/pdf/br-1654.pdf; Scot Pritchard and others, Optimizing SCR Catalyst Design an d 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/Und er%20Severe%20Opera ting%20Conditions.pdf21 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+ y ears of experience preparing hundred s 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 se parately, but rather included in construction directs or contingencies. The SJGS "code compliance" costs are very high and very unusual, warranting documentation. See discu ssion 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 ve rsion was utilized in that wo rk. 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. PN M complied with NFPA 85 during construction of the Consent Decree projects by dem onstrating, through “a more comple te and rigorous analysis,” that the SJGS boilers would be adequately prot ected from implosion dur ing upset or transient

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

2007 version of NFPA 85 has rece ntly 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 c onclusions attributed to Dr. Fox are actually statements made by

Black & Veatch that were co rrected after Dr. Fox submitted her report. In the 2007 BART analysis, Black & Veatch states that at the tim e of the Consent Decree projects, stiffening was not required as NFPA 85 51 (2004 revision) did not apply to hybrid systems which were neither "truly forced draft or truly balanced draft." 52 In the 2010 cost revisi on, Black & Veatch states that by 2007, NFPA 85 (2007 revision) had change d 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 Consen t 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, afte r 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 res ponse to the query about dates (going to the fact

that Black & Veatch had mischaracterized the a pplicable code sections), PNM retracted Black & Veatch's prior statements about NFPA complia nce 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 th is comment further note that this latter approach was pursued for the Consent Decree projects but th e BART cost analysis is based on the former approach, which yields an upper bound estimate. This is an importa nt clarification as sti ffening 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 betw een either designing to the genera l 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 w ill qualify for an exception from the generallyapplicable implosion protection stan dard through the use of alternat ive methods. To date, neither PNM nor its consultants have fully determined wh ether 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 proj ects 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 incl uding the cost for stiffening the boilers to +/-35 inches w.g. is the only way to ensure full comp liance 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 bo iler 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 pr essure differentials of 18 in. w.g. during the Consent Decree projects. As the upper bound estimat e 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. es timate is a worst-case upper bound that is not supported by vendor quotes and SCR design.

Comment: This explanation [referring to th e previous comment] was previously provided to Region 6 and to Dr. F ox, 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 requirement s of NFPA 85. According to the code, that authority lies with the entity defined as the “Aut hority 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 believ e significant boiler stiffening will likely be required to protect the boilers from impl osion following installation of an SCR and, without a successful de monstration that the boilers c ould 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 wi ll be possible to do so again. Region 6’s failure to properly account for the bo iler 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 explanati on was not received until December 8, 2010, after our cost analysis had been finalized. We ag ree some cost for code compliance is warranted. However, we disagree as to the amount. The wors t case used in Black & Veatch's analysis is unreasonable and unsupported, given the SCR's poten tial upper bound contribu tion of 10 in. wg. Absent the "more complete and rigorous an alysis" to support upper bounds for both an SCR pressure differential and stiffeni ng to +/- 35 in w.g., we feel st iffening 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 anal ysis 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 incr eased our estimate of the capital cost to install SCRs by $19,258,318.

Comment: In addition, the Region 6 cost estimate al so 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 st iffening. Lost power gene ration is a real cost

that PNM will incur as a result of the SCR retrof it. 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 th e cost to produce power at SJGS, and thus will

result in additional costs to the SJGS owners. Th ese costs must be taken into account in the cost

estimate for the SCRs.

Response: We have extended the compliance sche dule, as discussed elsewhere in our response to comments. We feel this will allow any required s tiffening work to be completed during routinely scheduled outages, which occur ev ery 3 years for 3 to 4 weeks and every 6 years

for 16 to 17 weeks. We feel there should be no lo st 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 in stalling the initial la yers 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 fa ctors 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 laye rs and the replacement catalyst la yers. The first method is to include the initial catalyst layers in the capital cost calculation for the SCR and account for each of the replacem ent layers in the annual opera ting cost calculation. The second method is to24 include all of the catalyst layers, both the initial layers and the replacemen t 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 wi ll be needed over time operate the SCR.

The cost analysis prepared by Black & Veat ch 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 th e annual cost calculation. In doing so, the Region’s analysis entirely eliminates the cost of the initial cataly st 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 ha ve 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 analys is costs associated with the installation and operation of a sorbent injection sy stem. 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 anal ysis of the SCRs for SJGS for several reasons. First, sulfuric acid mist resulting from SCR ope ration 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 PN M included the cost of sorbent in jection in its cost estimate is

that the failure to address the sulfuric acid mi st 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 determinatio ns developed by NMED.

Response: We disagree with this comment. Black & Veatch upda ted 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 an alysis did not include any costs for sorbent injection. NMED concluded that BART for SJGS was SCR plus sorbent injection to remove sulfur trioxide (SO 3 ) and requested a sorbent injection cost analysis. However, we disagreed and concluded that sorbent injection was not required due to the lo w sulfur content of the coal, availability of low conversion S CR catalyst, and our calculations. 58 We see no reason to change

57 Black & Veatch, San Juan Generation Station BART Proj ect 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 comm ent for requiring sorben t injection to control sulfuric acid mist (SAM) are not applicable to the SJGS SCR.

First, PNM suggests that SCR ope ration 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+% su lfur 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 else where and considered to be low sulfur.

Second, PNM suggests that "although the instal lation of SCRs may not result in such a plume at SJGS, the sorbent injection system woul d 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 pr operly designed to address SJGS's coal, a plume

should not materialize.

An SCR will typically include tw o to three active layers of catalyst and one spare. Low

SO 2 conversion catalysts were de veloped to address blue plum e 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 in itial layers and one spare) design (compared to 2+1 at SJGS, which thus can meet even lo wer 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 SO 2 conversion as low as 0.1% per layer of catalyst in the high dus t, 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 SO 2 conversion of 0.5% for

59 Anthony C. Favale and others, Application and Operatin g 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, A pplication and Operating Re sults of Low SO2 to SO3 Conversion Rate Catalyst for DeNOx Application at AEP Gavin Unit 1, Pro ceedings 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 lo w SO2 conversion catalyst th at achieves less than 0.1% SO2 oxidation while balance all other key produc t 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%2 0files/Scr_denox/Topsoe_scr_oxidatio

n.ashx ; William J. Gretta and others, The SCR Retrofit De sign for the Seminole Gene rating Station, PowerGen 2008; DNX TM – Topsøe SCR DeNOx Catalysts Oxidation of SO2 into SO3. (“Topsøe has demonstrated superior performance together with low SO2 oxidation under indus trial 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 Applica tion, Mega Symposium, 2008.. Available at: http://secure.awma.org/presentati ons/Mega08/Papers/a104_1.pdf.26 two active and one spare layer base d on the 0.1% per layer catalyst. 62 See, for example, the

discussion of the Seminole SCR else where 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 & V eatch proposed a 0.5% conversi on 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 SO 2 to SO 3 conversion of 0.125% per layer at the end of catalyst life for a 4+2 installation, or 0.5% across the SCR wh en 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 addre ss the sulfuric acid mi st 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 SO 2 conversion catalyst. The Black & Veatch analyses assumed a 1% conversion catalyst, twice as high as achievable and specified for similar co als at nearby faciliti es, and significantly

underestimated inherent remova l 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 us ed 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 ag es. 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 catalys t. Using that assumption, the sulfuric acid

emissions from SJGS are calculated to be twic e that assumed by EPA. As a result, EPA’s attempt to justify its decision to delete the cost s of sorbent injection based on minimal sulfuric

acid mist emissions is incorrect.

Response: The commenter is correct in that the EPRI report doe s suggest that a value of 0.75 ppm should be used. We note that the amm onia slip of an SCR is minimal when the catalyst is new and increases as the catalyst ages. In order to be conser vative, we recalculated the sulfuric acid emission rate, base d on zero ammonia slip, to be 2.6 X10 -4 lb/MMBtu,

62 See, e.g., CERAM, “Hot Topic Hour” Presentation on SC R 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 Stati on 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 Environmenta l 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 wa s based on the maximum slip from PNM's design specifications. This revised sulfuric acid emissi on rate remains significantly lower than that estimated by NMED and is a minimal level of sulf uric 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 contro l equipment and our revi sed 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 su lfuric acid mist emissions are lower than would be estimated using the EP RI 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, sulf uric acid emissions vary significantly from unit to unit because emissions removal is depende nt on many variables including temperature, moisture, process operation, air quality control equi pment, ambient conditions, and the quality of the testing. As mentioned above, SJGS and the Na vajo 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 mi scharacterizes 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 calcula ted for the Navajo Gene rating Station using the EPRI procedure with a stack test at the Nava jo 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 s uggests 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 em issions 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 emissi ons that were reported to the Toxic Release Inventory in recent years are much lower than th ose 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 incr eases 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 emissi ons 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 av ailable control technology,” which fo r sulfuric acid mist emission increases would likely include a sorbent injection system. Although there remains some uncertainty as to whether the SCR would trigge r 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 be28 needed. However, it is possible that the installa tion of SCR on all four units of the SJGS could generate enough additional sulfur ic 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 b ecause despite the projected increa se 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 throug h the use of lower reactivity catalyst, thus mitigating the formation of sulfuric acid across th e catalyst bed. We have set an emission limit

for emissions of sulfuric acid that restricts the increase of sulfuric aci d. According to the two most recent Toxic Release Inventory (TRI) repo rts 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 sulf uric acid to be significantly lower than these reported values due to the low sulfur content of th e coal and the removal of sulfuric acid in the installed control equipment, including wet scrubbe rs and fabric filters. We project, with the implementation of SCR using a low reactivity cataly st that total emissions of sulfuric acid will remain below 22 tons/year. 67 In this particular case, sorb ent injection technol ogy is unlikely to be cost-effective on a cost per t on 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 Revi ew 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” overa ll. Region 6 misunderstood PNM’s analysis because a “complexity factor” is not a “contingency factor.” “C ontingency 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. Acco rding to her report, Dr. Fox’s opinion is based

on a review of the SJGS and SJ RPP using Google Earth, a web site that includes a database of satellite photographs.

Google Earth is not a valid means of ascertain ing site-specific engine ering challenges at a complex industrial facility. PNM asks Region 6 to reconsider the analysis provided by Black & Veatch, given that the engineer s at Black & Veatch made seve ral 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 assu ming each unit operates 100% of the year (8760 hr/yr) .29 The extreme site congestion at SJGS is cause d by several factors that do not exist at SJRPP. First, SJGS has “hot side” ESPs that ar e ahead of the air preheate r in the flue gas path, whereas most coal plants have “cold side” E SPs that are downstream of the air preheater.

Because the ESPs for SJGS are located in front of the air heaters they ar e right in the middle of the boiler outlet duct area, which severely restri cts the area in which SCRs would need to be installed, particularly given the fact that the stacks are also located right next to th e air heaters.

The second primary cause of site congestion at SJGS is the arrangemen t 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 Attach ment B, the only space available between units are small maintenance roads to go in to the boiler building. As a result, there is very little room between units fo r 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 “int erior units” (located in between the exterior units 1 and 4) and crane access is especially limited on those units. Th e factor applied to the normal structural steel cost was not a “contingency factor ,” but rather an expected co st of installing SCRs at the complex and congested SJGS site. Region 6 unde restimated 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 fact ors as unknowns that cannot be determined until the SCR is designed. Second, there are approximately126 coal-fir ed 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 one s, 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 bui lt before SCRs were required (a ll units built prior to about 1995), this location is necessarily constrained as facil ity 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 equi pment, such as the boiler house, air heater, or electrostatic precipitator. Finding space for an d 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 St ation (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 stru ctural steel for Units 1 and 4 would be 1.2 times higher than at SJRPP and 1.5 tim es higher for Units 2 and 3, as alleged in this comment. We have not visited SJRPP, and the r ecord does not contain any plot plans or design drawing for SJRPP (or SJGS) that would allow one to conclude anythi ng 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 structur al steel framework, only the cost of constructing

it.

The BART Guidelines require that "doc umentation" be provided for "any unusual

circumstances that exist for the source that woul d lead to cost-effectiven ess estimates that would

exceed that for recent retrofits." 70 We specifically asked PNM to identify any retrofit constraints and to support them with engineerin g calculations, drawings, and photographs. 71 PNM did not respond. Therefore, we do not believe PNM ha s provided any specific documentation that supports the use of the structural steel complexity factors. Neve rtheless, we have modified our cost analysis to use Black & Veatch's estim ate 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 ju stification for the removal of this cost line item was that fuel oil is efficiently burned in mode rn low NOx burners with oil igniters, citing two

coal-fired units that have show n the ability to startup on oil w ithout 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 risk ing 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 pollu tion handbook concluded (before U.S. ozone season trading programs made them routine): "most applications do not have SCR bypasses, since routines are used during star tup 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 re quired to prevent damage due to low-load oil firing, thermal gradients, and other conditions.

Comment : Region 6 assumed that SJGS could initi ate startup of its units on oil without fouling the catalyst in the SCR. The Region’s ju stification 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 an y retrofit constraints and sup port them with engineering calculations, drawings, and photographs.")

72 S.M. Cho and S.Z. Dubow, Design of a Selective Ca talytic 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 show n the ability to startup on oil w ithout a bypass and two oil-fired boilers with SCRs that do not have a bypass. Ba sed 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 pollu tion handbook concluded (before U.S. ozone season trading programs made them routine): "...mos t applications do not have SCR bypasses, since routines are used during star tup and shutdown which preclude their need (Cho and Dubow 73 ), and regulations sometimes prohibit their use. Also, experience in Japan and Germany has shown them to be costly and not re quired 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 catalys t 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 th e ability to startup on oil without bypassing the SCR, as the risk of catalyst fouling due to incompletely com busted 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 instal ling and supporting operational retr ofit SCRs across the nation. Since the BART analysis requires a site-specifi c analysis, Region 6 shoul d defer to the opinions of experts who have practical experience with th e 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 & V eatch "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 f act, PNM and Black & Veatch have not pointed to a single unit that required an SCR bypass to prevent catalyst fouli ng 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 suppor ts 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 comp ly 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 Cataly tic 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-92332 Veatch design for the IPALCO Harding St reet 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, th e two SCRs that Black & Veatch designed and used to extrapolate costs for SJGS are exis ting units that do not us e 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 requi red 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 duri ng 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 by passes: Morgantown (2 units) and Belews Creek (2 units). In addition, the retr ofit 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 S CRs 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 Jone s, 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 Po int, 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 provisio ns 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), "Sched ule 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 Environmenta l 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 Electri c 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 Environmenta l 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 Electri c 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 de sign specifications, a complete SCR technology assessment, requests for proposal, and even vendor quotes. 84

Further, Black & Veatch itself has not sp ecified SCR bypasses, contrary to PNM's allegation in this comment that only new units that startup on oil would no t require bypasses, in NOx reduction studies prepared for other simila rly 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 un its), a similar aged facility that burns a similar coal and starts up on oil. 85 Black & Veatch also specifi cally 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 requi red an SCR bypass due catalyst fouling while firing oil nor due to any un usual circumstances at SJ GS that would require a bypass while none is required at the 13 units I identified.

While some catalysts (e.g., platinum-based oxi dation catalysts) are se nsitive 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, sh ortens reactor startup, lengthens catalyst life, and reduces stress on reactor structural members. 88

Comment: The EPA cost estimate also does not properly estimate a nnual operating costs for auxiliary power consumption and catalyst re placement 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 ot her hand, simply assumed a cost of 5,400 kW at $0.05 per kWh based on a percentage estimate fo r “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 assumpti ons, a SCR bypass system will not be included due to year round operation of the SCR system..."), 5-1 ("Cost saving s were realized by eliminating the SCR bypass (due to year-round operation instead of ozone season operatio n) which removes additional ductwork and dampers.").

87 See, e.g. Gretta et al, 2002, p. 6 (A large pitch catalys t was selected to prevent fouling. This would also reduce pressure drop).

88 Ted Kurtides, Lessons Learned from SCR Reactor Retr ofit, Coal-Gen 20 03, (Attach 20), pp. 2, 17-18.34 Response: We disagree with the comment. Th is comment claims the Black & Veatch auxiliary power demand cost estimate is based on a site-specific analys is for SJGS and thus should be favored over generic estimates from th e Control Cost Manual. This site-specific analysis does not appear to be in the recor d, thus preventing us from reviewing it. The assumptions used in the analys is, e.g., duct length, catalyst pr essure 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 capac ity of the station, which is high compared to other estimates known to the Region. 89 An SCR typically uses a bout 0.3% of a plant's electric output, which would be about 5,400 kW or three tim es less than assumed in the cost analysis. 90
The BART Guidelines require that unusual cost s 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 uncl ear whether 10 in. w.g. was used in estimating the auxiliary power demand as the calculations are not in the re cord. 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 el ectricity, or the busbar cost, not market retail rates. The Black & Veat ch 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 anal ysis. We further note that the use of forecast

cost is inconsistent with the BART me thodology, which is based on current dollars.

As to the cost of auxiliary power, we cons ervatively used the upper end of the range of

costs assumed in BART cost effect iveness analyses ($0.03/kWh to $0.05/kWh) 93 or $0.050/kWh (Exhibit 1, Fox Row 81). After our analysis wa s 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 Technolo gies, 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 ma de no changes to our estimate of auxiliary power demand.

Comment: Because of the Region 6’s underestimati on of the capital cost of the project, the capital recovery (which repres ents the annual impact of the in itial 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, base d 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 in stalling 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 imp act results for EPA’s proposed FIP. EPA’s

consultant’s cost effectiveness study departs from the BART analys is of control op tions prepared by PNM, and shows a total cost more than $670 m illion 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 near ly 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 e xpert's estimate. This alone should cause EPA to pause and at a minimum question and rean alyze 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 c onsultant 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 pr ovide an open process for use of multiple sources of data for establishing control option engineering design and costs, including site

‐ specific retrofit restricti ons (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, cons ider, 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 make s the nonbinding nature of the Manual even more explicit and reaffirms the requirement that real, site-specific cost s 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 equi pment 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, th e 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 ar e 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 us ed, 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 in clude a particular line item provide s no basis for striking that item from a BART analysis. On the contrary, EPA is bound by its rules and th e 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, th e 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 SJ GS. 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 su fficient auxiliary power to operate SCRs.

• Costs associated with protecting the air preheater following an SCR installation.

• Costs for Boiler “stiffening” required by convers ion 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 th e SCR during startup on oil fuel were not

included.

• Reasonable cost escalation f actors were not included.

• Some costs appear not to have been incl uded 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 follo ws a consistent set of rules so that costs incurred for pollution control equipment can be compared between facilit ies 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 th e actual cost of the control. Ra ther, a BART cost effectiveness analysis is a regulatory cost an alysis. Thus, while the experi ences 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 determ ined by compari ng annual cost per ton of pollutant removed

for the source of interest to th e range of cost effectiveness valu es 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 determ ination, based on costs borne by other similar facilities. To compare costs among units, a leve l 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 r uns the risk of comparing apples with oranges when making the co st 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 effec tiveness 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 a ll cost effectiveness valu es for SCR for all BART

sources were calculated as advoc ated by Black & Veatch, then th e 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 Appe ndix 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 an alyses, the Guidelines stipulate: "In order to maintain and improve consistency, cost estimat es 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 & Ve atch, 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 recomme nding 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 Ma nual “where possible,” recognizing the limits to which the BART dete rmination 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 Co st 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 Ai r Quality, North Dakota Department of Health, Re: EPA's Comments on the North Dakota Departme nt 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 costanalysis 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 Radiati on agreed that consistency among various EPA Regions is important but recognized that site-spe cific considerations must be addressed because “plants are not all alike.” As such, Region 6’s fa ilure to properly consider costs for site-specific challenges beyond those identified in the manual is inappropriate and in consistent with the regional haze program.

Response: We agree that site-specific challenges mu st 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 c onsistency" in the cost analysis, but rather consistency in the methodology and a ppropriate allocation of costs. As explained elsewhere, the Control Cost Manual provides two broad cate gories 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 f actors for other control technologies, which vary significantly from SCRs. As a result, EPA’s analys is 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 anal ysis 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 suppor ts; (2) handling and erection; (3) electrical; (4) pipi ng; (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 specifica lly requested support. Instead, they were calculated by multiplying total purchased equipm ent 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 e ngineering, foundation and s ite work, structural39 steel, and electrical/instrumental and controls, among others. The costs are plotted as a function

of unit size in MW for units w ith 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 doc umentation has been provided to justify these

costs.

The Control Cost Manual estimating procedure fo r 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 1 03% to 113% of total purc hased 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 Es timates, 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 comp ared to direct installation costs that it reported for the SJRPP SCR, which was otherwise us ed 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 estima te to conform with the balance of the Black &

Veatch cost estimate.

This comment claims that our estimate of direct installation co sts 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 assu mes 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 im portant to note that this duration corresponds to construction of a much smaller project (less bypa ss, preheater modificatio ns, etc.) than proposed by Black & Veatch. Further, we did not estimate construction dur ation but rather the length of

time from the effective date of the final rulema king to startup of the SCR or 36 months. Thus, the basis of this comment's starting point, an EPA estimate of 38 weeks, appears incorrect 104

. The SJGS record does not contain a schedule, wh ich 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 misimp ression that there are three contingencies “imbedded” in the analysis. Howe ver, two of the three allowances are for known costs, and therefore are not “contingencies.” Spec ifically, the complexity factor for structural steel costs of 1.2 (for Units 1 a nd 2) and 1.5 (for Units 3 and 4) are known, expected costs, and therefore do not constitute a contingency fact or, 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 represen t a duplicative contingency fact or. Thus, EPA’s claim that PNM double-counted its contingency costs is incorre ct and underestimates the cost of SCRs at SJGS by $61,978,000.

Response: This comment explains that the "c omplexity factor," site unknowns, and general building requirements are not contingenc ies, 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 Fo llow-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/libra ry/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/lib rary/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 unde rground obstructions and on-site buildings, are

reasonable and we have modified our cost esti mates 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 th e 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 fo r interest during construction of 7.41% of direct pl us indirect costs. This ch arge is generally known as the Allowance for Funds Used During Construction (A FUDC) 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 allo wed return on equity are not charged to current customers. Instead, AFUDC capitalizes these costs a nd 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 wo rds, AFUDC is the accumulated cost of carrying capital and holding it waiting to spend, so money can be made in th e future by selling electricity.

Future income should not be ch arged against the cost of a SCR in a BART cost-effectiveness analysis. These costs are not part of the cons tant dollar approach found in the Cost Manual and

should not be included in BART cost-effectiven ess analyses.

3. Concerns over Possible Electricity Rate Increases

Comment: Both the CAA and EPA BART regula tions require consideration of the remaining useful life of a source. Requiring th e 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 technologi es. As such, it could make production at SJGS during its remaining useful life uneconomical in comparison w ith other existing or fu ture 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, reli able 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 advers ely affected by the EPA proposal. PNM estimates that the average residential cust omer 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 correc t 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 cont rols. 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 determina tion 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 restri ction 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 fede rally enforceable restriction.

Comment: Several local and county governme nts and municipal power systems expressed concern that the propos ed FIP would require a major cap ital expenditure that could well exceed $750 million, according to PNM. Such si gnificant 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 comment er 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 in to consideration various comments, we have refined our estimate to be $344,542,604. In light of th e visibility benefits we predict will occur,

we consider this to be cost effective. We ta ke 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 po tential increase in electricity rates to be the most appropriate type of analysis for considering the costs of co mpliance 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 unr ealistic. 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 consulti ng 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 spec ifically to the power generation industry.

Response: The CECPI, which is pub lished 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 be cause "this index specifically covers cost items that are pertinent to pollution co ntrol equipment (materials, constr uction labor, stru ctural support, engineering & supervision, etc.)." 107 The Black & Veatch escala tion 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 requi red to consider site-specific costs,

even when those costs are not in cluded 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 ma de on a "source-specific basis," which includes costs that are source specific. Moreover, EPA's own BART rules contemplate that based upon site specific el ements, an available control t echnology 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 impact s on a case-by-case (or si te-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 pro cedure developed by EPA” that is “stipulated in the BART Guidelines,” and cites to it more than thirty ti mes in its analysis. A lthough 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 pro cedure.” 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 th at will be associated with installing SCRs at

SJGS.

107 Email from Larry Sorrels (OAQPS) to Don Shepherd (Par k 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 al so 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 contro l technologies in sufficient detail for a BART analysis. Th e cost analysis should also take into account any site-specific design or other c onditions identified above that affect the cost of a particular BART technology option. 108

The Control Cost Manual contains two types of information. Firs t, it establishes a methodology for calculating cost effectiveness th at allows comparison across multiple units. This methodology is a regulatory cost analysis that is no t 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. Consiste ncy 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 me thods 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 seve ral other projects; and its own proprietary and c onfidential databases not av ailable for public review.

Second, the Control Cost Manual contains specific cost estimating procedures for individual pollution control equipment, such as fl ares, scrubbers, and SCRs. These sections of the Manual generally set out standa rd design procedures used to si ze the equipment, factors for estimating direct and indirect costs from instal led capital costs (obtai ned from vendor quotes), and sometimes provide cost estimates for some equipment components. We generally did not use this section of the Manual except as discus sed elsewhere in these re sponses to demonstrate

that Black & Veatch's estimates were out of reasonable bounds.

Finally, as to unusual circumstances, the Guid elines require that "documentation" be provided for "any unusual circumstances that exis t 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 documentati on is that found in the appendices of the 8/17/10 Navajo Cost Analysis prepared by Sargen t & Lundy for a nearby, si milar 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-constrai ned 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 stati on using the largest crane in the world 112 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 pr ojects in the U.S., invol ved installing the SCR 280 feet above ground level above the boiler build ing. 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 Gibson 115

Black & Veatch's estimates of capital cost to retrofit SCR at SJGS ($446/kW - $599/kW) are higher than actual installed cost for Gibs on 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 ou t-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/sample updates/NoxMarketUpdateSample.htm.

114 Bill Hoskins, Uniqueness of SCR Re trofits 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/AuxillaryE quipment/SelectiveCatalyticReductionSystems.cfm.46 Comment: The exclusive use of the Cost Manua l 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 actu ally written in October 2000. In addition, on page 2-40 of the SCR section, the Manual indica tes 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, th e 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 SO 2 controls, and [the 2002] edition starts the process of correcting that oversight.” Finally, EPA also admits in th e Manual that it had difficulty obtaining information on control costs because most of the information is proprietary – the very type of information to which Bl ack & Veatch has ready access.

Response: As discussed elsewhere in our re sponse to comments, the Cost Manual contains two types of information, general co st analysis methodol ogy and control-specific costing information. This comment addresses th e latter. The information on SCR in Chapter 2 of the Cost Manual contains general informa tion on SCR, design procedures, and some cost information. We agree that the cost information doe s not reflect current market costs. Thus, cost

data should be escalated to curr ent dollars using the CECPI before it is used or replaced with site-specific vendor quotes. We di d not use any SCR costs data from this chapter in our analysis.

Comment: The Region 6 cost estimate rarely diffe rs 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 provi des 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 lif e span than provided for in the

manual is that other facilities ha ve requested 30 year life spans in requests for proposal and some unidentified SCRs in Europe have lasted that long. If such gene ral, anecdotal information were sufficient to convince Region 6 to stray from th e 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 th e 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 Ma nual for cost factors that for reasons expressed elsewhere in our response to comments, we f eel 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, th e 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 co st 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 r ecord is silent on the remaining useful life of the SJGS units. Th ese 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 st udies of the coal reserves that SJGS relies on indicates that the local coal supply is adequa te to support a remaini ng useful life of 30 years. 116

Further, as previously noted, there are many SC Rs 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 proposal s. A study of the economic risks from SCR operation at the Detroit Edison Monroe power pl ant, 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 f acility assumed a 40 year SCR lifetime. 118 And finally, Sargent & Lundy assumed a design life of 30 years 119 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 c onsider additional line items outside the scope of the Cost Control Manual on the grounds that “PNM had provided no documentation regarding unique circumstances re lated to the BART determinations.” That claim is incorrect. Region 6’s own analysis cites the documentati on 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 th e 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 docum ent 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 Co mmentary,” PNM also provided significant evidence of the site-specific chal lenges 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 lengt hy, 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 Intern ational Conference: Risk, Reliability, and Security, p. 3. Available here: http://www.unwin-co.com/ files%5CSCR-Risk-Pap er,CCPS-RRS 2002.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 Un its 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 di scussed elsewhere in our response to comments. The information provided in the "Cost Analysis Ma nual 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-s pecific constraints at SJGS, that would justify extrapolating costs from these other facilities, the St. Johns River Power Project, which burns coke, and Harding Street, we re never explained. Th e record, for example, does not contain any structural steel and duct layout drawings to justify this high contingency and other factors, nor does it cont ain 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 demonstrati on required by other air quality standards that EPA’s BART Guidelines specifically encourage st ates to follow in setting BART limits. Regardless of the NOx limit chosen (whether 0.0 5 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 averag e could include as little as on e hour of operation if the unit is offline for an outage that lasts longer than thir ty days because the first hour of operation would be the only data recorded in the last thirty ca lendar days. To avoid this approach, PNM asks Region 6 to consider changing “cale ndar 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 N SPS 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 whic h 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 aver age. 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 contin uous 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 an alysis are presented in response to another comment. In summary, we continue to believe th at NOx BART for the units of the SJGS is an

emission limit of 0.05 lbs/MMBtu. We have conc luded that emission limit should be based on a49 30-day BOD rolling average based on any operation in a given day co unting 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 (U SFS) 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 Cl ass I areas throughout the Four Comers region. Additionally, the USFS feel s SCR has already been determined to be

BART at several other coal-fir ed power plants across the Un ited States. Lastly, the USFS approves of the methodology employed by EPA in their modeling assessment and agrees with examining the cumulative impacts at all affect ed Class I areas inst ead 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 propos ed 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/MMBt u, to provide a direct comparison with Black & Veatch's analysis. Following this, we de termined 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 attempte d 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 in stalling retrofit SCRs determined that a retrofit SCR would only be capable of achieving 0.07 lb/MMB tu on a continuous basi s, particularly if required to use the low-oxidation catalyst assu med 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/MMB tu satisfies BART rath er 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, 7-150 since July 2007, but we do not believe that PNM has provided adequate s upporting analysis. We do not view an unsupported statement, such as th is, 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 Ju ly 2007, PNM explained that the value of 0.07

lb/MMBtu was selected based on an informati on search of the BACT/LAER Clearinghouse and specifically based on a permit issued by Geor gia 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 le vel 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 Washi ngton. 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]lo t 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 e fficiency (i.e., a lower NOx limit) could not be achieved. In response, PNM did not provide any site-specific info rmation, calculations or design drawings, but rather argued that the NOx em ission value was established based on outlet NOx emissions, not removal efficiency. 127 We do not believe this provide s 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 Re sources, Air Quality Permit, Plant Washington, Permit No. 4911-303-0051P010-0, April 8, 2010, (Attach. 45). Available at: http://airpermit.dnr.state.ga.us/gaairper mits/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/document s/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 establis hed 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 Pa rk 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 fo r the SCR retrofit fo r the nearby Navajo Generating Station, a facility of a similar age that burns a simila r coal, with a more constrained

site. 131

Lastly, as explained elsewhere in our res ponse 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 stat ement 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 (incl uding the Havana Unit 9, Amos Units 1 and 2, Chesterfield Unit 6, Cardin al 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/M MBtu 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 ha ve 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 retrof it technology on older units for under a 30

‐ day rolling averaging period. The Clean Air Act programs app licable to stationary sources recognize the difference between the potential effectiveness of re trofit controls at exis ting units and controls that can be installed during the in itial construction of a new unit. The visibility pr ovisions 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 be en achieved on a continuous basis by two new units that are less than five years old and th at were designed from inception to accommodate

SCRs. One commenter stated that Black and Veat ch, through a site-specific technical analysis

has determined that the SJGS units could cont inuously 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)/385.5x10 6 = 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: CO MPLETE 100930 EPA Questio ns 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 unachie vable 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 a nd 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 conclu sion, we followed the language in the BART

Guidelines: 132

It is important, however, that in anal yzing the technology you take into account the most stringent emission control le vel that the technology is capable of achieving. You should consider recent regulatory decisi ons and performance data (e.g., manufacturer’s data, engineering es timates and the experience of other sources) when identifying an emissions pe rformance level or levels to evaluate.

In assessing the capability of the control alternative, la titude 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 ra nge) 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 represen tative of the achievable level for the source being analyzed.

First, we examined “the most stringent em ission 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 lim it, and found none. Third, concluding there was no “showing of differences between th e source and other sources that have achieved more stringent emissions limits” that would preclude the applicati on of this limit, we “conclude[d] that the level being achieved by those other sources is represen tative of the achievable level for the source being analyzed.” The following di scussion expands on these points.

We believe the commenter, PNM, misquot es our consultant’s report, which was incorporated into our proposal’s Technical Support Document (T SD). That report contained a previous study of SCR performance during th e 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 requ ired 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 be ing achieved by over 100 SCR-equipped coal-fired

132 70 FR 3916653 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 de signed 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 lo ad 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) retain ed Babcock Power and D uke 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, opera ting 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/Licat a.pdf; LG&E Energy, Selective Catalytic Reduction: From Planning to Operation, Competitive Powe r College, December 2005, p. 75-77. (Attach. 29).

135 M.J. Oliva and S.R. Khan, Performance Analysis of S CR Installations on Coal-Fired Boilers, Pittsburgh Coal Conference, September 2005, (Attach 27).

136 Jason Peltier, Top Plants: Seminole Gene rating Station, Palatka, Florida, Powe r, 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 St artup 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/Meg a08/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 instal led SCRs designed to achieve 90% NOx control on many units in its flee t. The demonstrated performance of one of these units,

the 1300 MW AEP Mountaineer fa cility, has been reported. 140

• An 85% efficient SCR was originally insta lled 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 ca ll limit during the ozone season. The demonstration test indicate: “[T]he SCR syst em 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 de monstrated NOx removal at 91.6%. 142

While these and other SCRs are routinely desi gned to achieve 90% NOx control, they are not routinely operated to meet these design targ ets as they operate unde r cap and trade programs that do not apply to specific units. This mi smatch 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 be low, we believe the units of the SJGS are capable of achieving a NOx em ission 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. Fi rst, 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 as sertion in another comment that our proposed NOx emission limit should be based on boiler operat ing days, rather than a straight calendar average. In response to that comment, we have reanalyzed ou r 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.babcockpow er.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 Cliffs ide 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 da ys. This distinction is significant, as the boiler operating day conve ntion discussed by the regional haze rule 143
smoothes out the 30-day rolling av erage outage spikes. Second, these charts include large blocks of time during which the SCRs were turned off b ecause 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 Ai r Markets Division (CAMD), which compiles continuous emission monitoring system (CEMS) da ta reported under various trading programs. We analyzed the NOx CEMS data for the pe riod 2009-2010 to identify the best performing retrofit units that operate year round. We ranked the annual aver age NOx emissions for all units in the database for the years 2009 and 2010 from th e lowest to the highest NOx emissions. The year 2009 was selected as it is the first year that most existing SCRs we re operated year round to comply with CAIR, rather than just during the ozone season. Th e 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 year s to identify consistently best performers. The annual average NOx emissions ach ieved 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 rol ling 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 gr aphs it prepared to support this comment in

Attachment C.

As Exhibit 2 shows, the averaging conventi ons we used are: (1) a conventional 30-day calendar rolling average (30 da y rolling); (2) a 30-day B OD 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 fo llowing midnight during which any fuel is combusted at any time at the steam generating unit.” 144

.

The Havana Unit 9 data shows that it ha s 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 da ta 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 appr oximately 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 mont hs of continuous operation

below 0.05 lbs/MMBtu. We believe th is data demonstrates that sim ilar 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 program s, such as the Acid Rain Program, Clean Air Interstate Rule (CAIR), and the NOx SIP Call 145 or to comply with elevated permit limits, such as from netting out of NSR review. Therefore, th ese reporting units are not subject to regulatory requirements that compel the continuous ope ration 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 ha ve no incentive) to co ntinuously 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/p rogress/CAIR_09/CAIR09.html , and Clean Air Markets Progress Reports at http://www.epa.gov/airmarkets/pr ogress/progress-reports.html.57 The SCRs on these units were installed in 2003 to comply with stringent NOx limits under the

Houston-Galveston-Brazoria Nonatt ainment area cap and trade program, 146 contained in Texas Administrative Code, Rule 117.1210 and 117.1220. Th ey all had trouble-free startups, passed their performance guarantees, but encountered unexpected ash de position problems, which were subsequently resolved. They have operated y ear 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 desi gn 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/MMB tu, 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 examinati on of the CAMD data. This is evident in the Parish data, which commonly shows, for exampl e, very low steady operation (when required to meet caps), followed by extended periods of operati on 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 c ontinuous 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 ha s been designed. The Electric Power Research Institute, for example, has projected a st eady 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 Po wer 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/M MBtu 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 in ception and only two are cu rrently 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 in itial BART determination was being drafted. 151
The reliance on permits to establish BART is cons istent with and anticipa ted 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 th e technical feasibility of that technology or emissions limit." 152
The BART Guidelines also require permitting agenci es to “consider recent regulatory decisions . . . when identifying an emissions performance le vel” that can be achieved by available pollutionreduction methods. 153

Regardless, we present information elsewh ere in our response to comments that demonstrates the ability of re trofitted 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 potenti al for greater control rates as

low as 0.03 lbs/MMBtu” for SJGS. This commente r references our TSD for the proposed FIP, that SCR technologies “are routinely designed and have rou tinely 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), th e 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% contro ls, 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 achievi ng 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 pr esented in the commenter’s contractor’s report. As we discuss elsewher e in our response to comments, we agree there are SCR retrofits that are meeting NOx emission limits below 0.05 lb s/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 perm it (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 ha s presented monthly emission data for a number of units which appear to indicate that some ar e occasionally able to m eet monthly emission limits below 0.05 lbs/MMBtu. The Havana 9 unit is partic ularly 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 th at 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 techni cally 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 aver age (especially if figured on the basis of a BOD). However, we see no data, presente d either by the comment er or from our own research, 154 which we have discussed el sewhere 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 un it such as SJGS with retrofitted SCRs on the basis of a 30 day rolling averag e. Furthermore, the existence of a permit limit is not the only indicator of the technical feasibility of achievi ng a particular emission limit. However, its absence, combined with no documented instance of an SCR retrofit ach ieving this level of control on a continuous basis, causes us to conc lude 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 exam ple, Black & Veatch assumed that SCR could achieve 0.05 lb/MMBtu (annual average) when ev aluating retrofitting of SCR at the Craig power plant in Colorado. EPA's Clean Air Markets (CAM ) data and vendor guaran tees) 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, el even of which are dry-bottom, wall-fired units like SJGS. Although SCR may be capable of ev en 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 provide d any documentation or justification to support the higher values used in its analyses. We are also pr esenting information from industry sources that supports our understanding that SCR can achie ve 90% reduction6 and reduce emissions to 0.05

lb/MMBtu or lower on coal-fired boilers. For ex ample, according to the Institute of Clean Air Companies white paper titled "Selective Cataly tic 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 efficien cies exceeding 90 percent may be achieved." And, according to the June 13, 2009 "Power" magazine article "Air Quality Compliance: Latest

Costs for S0 2 and NOx Removal (effective coal clean -up has a higher-but known-price tag)" by Robert Peltier, " An excellent example of the significant investment ma ny utilities have made over the past decade is American Electric Power (A EP), one of the largest public utilities in the U.S. with 39,000 MW of installed ca pacity with 69% of that capaci ty 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) consen t decree signed in 2007 that requ ires the utility install air quality control systems to reduce NOx by 90%..."

Comment: PNM proposed emission control tec hnology consisting of Low-NOx burners (LNB) with overfire air (OFA) co mbined 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 simila r in design as the SJGS. NOx emissions can be reduced by 90% with SCR installed at 0.05 lb/MMB tu emission limit. Given the SJGS’s size and amount of NOx emissions, a more stringent em ission limit than PNM's proposal is not only achievable, but it will provide for gr eater reduction in NOx emissions.

Response: We agree with the NPS that PNM ha s 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 it s assumption that SCRs would enable

SJGS to achieve an emission rate of 0.05 lb/M MBtu 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 incorr ect assumption that SCRs at SJGS would achieve

0.05 lb/MMBtu into her cost eff ectiveness calculations, Region 6’ s consultant overestimated the

emission reductions that the S CRs 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 provi de. At an emission limit more appropriate

for the retrofit context under c onsideration, the SCRs would not achieve nearly the level of visibility improvement that Region 6 expects. In short, Region 6’s in correct assumption that

SJGS could achieve 0.05 lb/MMBtu with SCRs sk ewed its entire cost-eff ective and visibility analysis. As a result, the Region’s proposed FIP is unachievable and it sh ould 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 th e visibility modeling or the cost analysis on that basis.

Comment: The USFS feels that PNM has underes timated the achievable emission limit

that would result with Low-NOx burners with over fire 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/MMB tu emission limit. Given the SJGS’s size and amount of NOx emissions, a more stringent em ission limit than PNM's proposal is not only achievable, but it will provide for gr eater reduction in NOx emissions.62 Response: We agree with the USFS that PN M 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 meeti ng an annual NOx emission limit of 0.05 lbs/MMBtu, we extended our analysis. As we discuss else where in our response to comments, we also analyzed the ability of some of the better controll ed 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 emissi on limits on a plant wide basis, and the proposal offers no justification for deviating from that established and reasonabl e 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 fo r 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 visi bility impact or visibility improvement, as to which unit or units within a facility the emi ssions - or the emission re ductions - occur at, there is no rational basis for the Agency to preclude the plant wide aver aging that is contemplated in EPA’s own BART rules. Indeed, as noted a bove, 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 th at 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 EP A must revise its proposal to re move 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 genera ting 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 s hould consider allowing sources to ‘‘average’’ emissions across any se t 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 si mply controlling each of the BART-eligible units that constitute BART-elig ible 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 roll ing 30 day calendar average, in favor of a limit calculated on the basis of a rolling 30 day Boile r Operating Day (BOD) av erage. The definition we have adopted for BOD complies with th e BART Guidelines, being, “any 24-hour period

155 70 FR 39104.63 between 12:00 midnight and the following midni ght during which any fuel is combusted.” 156 A BOD averaging scheme has the effect of smoothi ng out the data peaks that occur due to boiler start up and shut down. As explained in our resp onse to that comment, we intend to comply with that request. As a consequence of the BOD averag ing scheme, days in which a unit is shut in for the full 24-hour period don’t coun t in calculating the 30 day averag e. 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 averag ing scheme, it is likely after an initial period of time passes, that all four units will be using diffe rent 30 days of time in calculating their individual 30 day B OD 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 conc erning a plant wide average, we advise, “In addition, emissions limits must be enforceable as a practical matter (contain appropriate averaging times, compliance ve rification 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 enforceab ility. Therefore, as we discuss elsewhere in our response to comments, we will conditions th e 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 exclud e 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 re quested we consider setting a

different standard that is more representative of the emission ch aracteristics of the units during those events or consider requiri ng work practice standards to mi nimize such emissions. Another commenter requested that we sp ecifically include startups a nd 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 appl icable emission limit. That commenter also requested that we clarify that this provision a pplies to all pollutant s controlled by this FIP, including, NOx, SO 2 , H 2 SO 4 , ammonia, and particulate matter (PM).

Response: As we have discussed in our response to other comme nts, 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 temperatur e range of the SCR catalyst, or when the ammonia injection system malf unctions. We believe that st artup 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, SO 2 , and H 2 SO 4 , 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 finalizi ng 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 catalys t to maximize ramp rates and NOx reduction at low temperatures; and use of both tunable ammonia injection grids (AIGs) a nd 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 A ttachment A is a table of the other NOx BART determinations that have been made by 13 differe nt states as they have developed the proposed regional haze SIPs that are awai ting 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 nati on, (ii) at the cheapes t price, and (iii) in the shortest amount of time. These unrealistic expectations do not reflec t the significant site-specific challenges SJGS must face to install SCR, particularly w ithin the proposed 3-year deadline.

First, the FIP is overly optimistic about th e 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 im posed on a unit with a re trofit SCR by any state, as illustrated by the attached table. Second, SJGS will not be able to inst all SCR on all four units for the price calculated by Region 6 and its consul tant, 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 cons truction feasibility challenges, and much more significant interruptions in opera tion of the plant. Taken t ogether, these assumptions are unrealistic and undermine the Region’s cost-eff ectiveness calculation, particularly when compared to the results of the other BART determ inations that have been made by the states for other electric generating units. The FIP propos ed 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 emi ssion 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 i ndication 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 repl acing those plans with FIPs. That approach would directly contradict the design of the visi bility provisions of the Clean Air Act, which grants to the states significant discretion in choosing their own means of meeting the national65 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 cont rast between Region 6’s approach and other states. PNM requests Region 6 take a more realistic l ook at its conclusions in light of this additional inform ation and the additional technica l 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 highe r standard or a more costly standard than other similar power plants.

Response: As explained in our responses to ot her 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 disc ussed in our responses to other comments, although we find that our propo sed 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 c onclusions 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 commente r’s own table indicates, other states and EPA regions have made NOx BART dete rminations that will be met or are proposed to be met with the addition of SCR, including th e 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 point s 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 (mor e 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 effec tiveness 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 fi ve factor analysis is de signed to consider sitespecific issues. For instance, we note that the chart does not cont ain 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, ev en controls that have either a relatively high capital cost or cost e ffectiveness 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 predicte d 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 SO 2 Emission Limit

Comment: One commenter stated an SO 2 emission rate of 0.15 lbs/MMBtu on a 30 day rolling average is not appropria te and does not ensure that SO 2 emissions from SJGS will not interfere with visibility in New Mexico or other states. This commenter believes an SO 2 emission rate of 0.15 lbs/MMBtu does not reflect the level of emissions reductions achievable

under BART for wet limestone scrubbers. This comm enter also points out that the units of the SJGS are all currently achieving SO 2 limits significantly under 0.15 lbs/MMBtu on a 30 day rolling average and concludes we should not set SO 2 emission rates in a Section 110 FIP that

exceed the historic SO 2 emission rates at SJGS. The comment er requests that if we do set a nonBART SO 2 limit in our Section 110 FIP, we set unit-speci fic limits at least consistent with the

recent historic SO 2 emission identified in the table the commenter references, or issue formal

SO 2. BART determinations for each unit at SJGS under a Section 308 FIP.

Response: We believe the SO 2 emission rate of 0.15 lbs/MMBt u is appropriate to meet the requirements of section 110(a )(2)(D)(i)(II) to ensure that thes e emissions from SJGS will not interfere with visibility in other states. As di scussed in our proposal, we believe that emissions reductions consistent with the assumptions us ed in the WRAP modeling will ensure that

emissions from New Mexico sources do not inte rfere with the measures designed to protect visibility in other states. We are aware that the SO 2 controls currently installed on the SJGS are in fact achieving grea ter control than would be evid enced by an emission limit of 0.15

lbs/MMBtu. The commenter’s observation of the SJGS’s current SO 2 emissions simply means

that the SO 2 emissions from the SJGS are better cont rolled 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 re quiring the installation of scrubber to meet a more stringent limitation. We did not propos e to address the BART requirements for SO 2 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 i ssue of requiring different capital expenditures to meet the requirements of section 110(a)(2)(D)(i )(II) as compared to thos e of the RH program’s BART requirement does not arise. Since we did not propose the S0 2 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 SO 2 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 BA RT 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 oblig ations under 40 CFR 51.308 (e)(2)(i).

Response: We disagree with the commenter. In accordance with our proposal, we are finalizing SO 2 limitations under section 110(a)(2)(D)(i)(I I), not under the RHR. We disagree67 with commenter’s view that we are sidestep ping our BART obligations by not proposing to

establish SO 2 BART emission limits. Our rationale for not proposing BART requirements for

SO 2 in this action appears in our response just prio r to this comment. Moreover, we note that the

established SO 2 limits do not rely upon a nonexistent trading program. We will address New Mexico’s obligation to address SO 2 under the RHR in a future separate action.

D. Comments on our Proposed H 2 SO 4 and Ammonia Emission Limits and other Pollutants

Comment: The League of Women Voters, Mont ezuma County, Colorado supports the

EPA determination that SCR is cost-effective fo r all units of the SJGS. They defer to our judgment on the proposed final limit for sulfuric aci d 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 impera tive 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 oz one) that contribute to visibi lity impairment also harm public health. This commenter also noted that oz one 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 Mexic o, Colorado, and Utah are al ready in the range of

ozone levels deemed to be harmful to human health.

Response: We agree that the same pollutants that contribute to visibi lity impairment can also harm public health. Although we note public health benefits, we di d not rely on these benefits in establishing c ontrols necessary to meet BART in today’s action.

Comment: For the reasons stated in EPA’s pr oposed rule, we also fully support EPA setting emission limits for H 2 SO 4 and ammonia at the SJGS, and the corresponding installation of CEMs to accurately document the continuous em ission 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 secti on 308. With regard to H 2 SO 4 , 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 th at this rate is supportable based on use of low reactivity catalyst and the most current informa tion from the Electric Power Research Institute (“EPRI”). If continuous emission m onitors are truly unavailable for this pollutant, we also urge EPA to require stack test monitoring for H 2 SO 4 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 determ ination for the facility and must be complied with within 3 years of the date of the final ru le. If EPA does not set BART limits in the final rule, it should conduct a BART analysis for H 2 SO 4 in a Section 308 FIP. With regard to ammonia, we also support EPA setting the lowest emission rate considered at the SJGS. NH368 emissions are important in that they react with SO 2 and NOx to form ammonium sulfate and ammonium nitrate pa rticles, which are very effective in impairing visibility. Thus, we support EPA setting the ammonia emission limit at the lo wer 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 visibil ity 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 F our 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 individua lly, 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 Regi on 9 for the Four Corners power plant PM BART determination by setting a 10% opa city limit at each unit at SJGS to control PM emissions. Compliance with PM emission limit should likewise be required with in 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 th e assumed ammonia slip level used to estimate sulfuric acid emissions, we have recalcul ated the expected sulfuric acid emissions rate with no ammonia slip. The sulfuric acid em ission 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 actua l ammonia slip will vary over the life of a catalyst layer. We conclude an assumption of a mmonia slip up to 2.0 ppm as the catalyst ages is reasonable for an SCR system that is de signed to achieve a NOx emission limit of 0.05 lbs/MMBtu on a rolling 30 BOD basi s, considering the coal the SJ GS burns. We also note PNM assumed an ammonia slip of 2.0 ppm in its SCR co st 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 H 2 SO 4 emission limit of 2.6 X10 -4 lb/MMBtu.

Our intention in our proposal regarding the regulation and monitoring of ammonia was,

like H 2 SO 4 , to minimize the contribution of this co mpound to visibility impairment. After

careful consideration of the comments we receiv ed 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-f act regulation. We are requiri ng 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 am monia slip of 2.0 ppm. We believe this strikes the proper balance between the additional cost of ammoni a monitoring and reporting and

the need to have a reasonab le expectation of the amount of ammonia emitted by the SJGS.69 The H 2 SO 4 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 reques t that if emission monitors are truly unavailable for this pollutant, we should requ ire stack test monitoring for H 2 SO 4 on a more frequent basis than annual monitoring, we do not believe that an adequate continuous emissions monitor is

available for H 2 SO 4 and will continue to rely on stack te sting. We do not agree that more frequent stack testing is appropr iate, due to a consideration of the cost of that testing in comparison to the value of havi ng a greater certainty of the H 2 SO 4 emissions that may result. As we discussed in our proposal 158 , we have concluded that the low sulfur coal burned at the SJGS generates very little sulfur trioxide (SO 3 ), and hence H 2 SO 4 , which is formed when SO3 combines with water in the flue gas to form H 2 SO 4 . In addition, SCR catalys ts are available with

a low SO 2 to SO3 conversion of 0.5%, further limiting the production of H 2 SO 4 . Therefore, we

conclude we have stru ck 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 pe riod of five years for achieving the proposed emission limits. They stated SCR was first pa tented in the U .S. in 1957 and has been an operational pollution control technol ogy for over 30 years at large scale facilities like the SJGS. They believe allowing an extra two years ma y provide the opportunity for ambiguity and technological changes to enter into arguments about engineeri ng solutions and controls, which potentially could feed appeals and litigation by the ope rator of the SJGS, and thus delay cleanup efforts. The operators of the SJGS have had seve ral decades of largely un restricted 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 coul d 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 em ployees, contractors, and subcontra ctors to meet their financial obligations.

Another commenter asked if ther e 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 tr uncation of the five-year compliance period should be persuasively justified by a specific analysis of the feas ibility and cost-e ffectiveness of such a schedule in light of the ci rcumstances at the facility in que stion. 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 acco unt for in our analysis, compounding the errors made in its unrealistic cost analysis. They stat ed 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 comm enter made several points: first, Region 6 cites to the installation timelines provided in a white paper prepared in 2002 by the Institute of Clean Air Companies (ICAC) entitled “Typical Inst allation Timelines for NOx Emissions Control Technologies on Industrial Sources.” As stated in the paper’s in troduction, “[t]he information below can be used as a general guide for the t ypical time required to complete a typical NOx control project....” However, as explained throughout these comment s, 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 applic ations, not electric util ity 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 repr esentative, which it alleges we neglected to consider, which is the recently published “Implementation Schedule for Selective Catalytic Reduction (SCR) and Fl ue Gas Desulfurization (FGD) Process Equipment” October 1, 2010, prepared by J. Edward Cichanowicz for th e Utility Air Regulatory Group. The report is based on a review of numerous FGD, SCR, and LN B retrofits actually completed at coal-fired power plants during the last ten ye ars. Particularly relevant is Section 4.1.2 of that report, which discusses several examples of multiple SCRs in stalled 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 factor s. 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 stud ies, 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 questio n. The commenter then cites another report it believes is more representative and concludes the site conge stion 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 f acility, which required 60 and 62 months to complete, respectively.

Response: We have decided, base d 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 very71 preliminary, low-level estimate, that is missing much of the informati on 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 si te 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 nu mber of sources, including the following:

• 13 months for 675 MW Somerset Station; 159

• 18 month for Harding Street, which wa s used to cost the SJGS catalyst; 160

• 19 months for two 900 MW units at Keystone. 161

• 26 months for Asheville Power Station w ith a reported normal range of 27 to 30

months. 162

• 30 months for 4 units based on 21 months typi cal 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 star tup. This facility

was used to estimate most of the SJGS SCR costs. 164

• 42 months for 14 SCRs installed to comp ly 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 ci ted in this comment was published around the

159 ClearSkies: http://www.epa.gov/clearskies/03technical_pa ckage_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/clear skies/03technical_package_sectiong.pdf.

162 Case Histories: Asheville Power Station's Retrofit First to Meet North Carolin a's Clean Smokestacks Act.

163 ClearSkies: http://www.epa.gov/clear skies/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://w ww.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 th is 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 (c ompared to 18 - 69 months for the 9 facilities (greater than 33 units) in our sample). The av erage 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 si te visit, that site congestion will require a longer tota l 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 co ncluding 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+ year s, 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 Decr ee schedule was beat, how ever, and all of the controls were operating by May 2010.

The Sammis retrofit project at this 2,200 MW pl ant is generally recogn ized 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 extremel y 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 balan ce 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 elsewhere 174

168 U.S., et al., v. Ohio Edison Company, et al., Opinio n and Order, Case No. 2:99-CV-1181, In the U.S. District Court for the Southern District of Ohio, Eastern Divisi on, 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/complia nce/resources/decrees/civ il/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.de tail/id/552039/Sammis-energy-plant-project-winsaward.html?nav=5010.

171 Linda J. Hutchinson, W.H. Sammis Plant in Ohio Be ing Retro-Fitted to Scrub Air Pollutants, ConstructionEquipment 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/di splay/articledisplay/6243020871/articles/powerengineering/volume-115/issue-4/features/retrof itting-air-handling-equipmen t-at-w-h-sammis.html

173 Anthony J. Alexander, Bank of America/Merrill Lync h 2010 Power & Gas Leaders Conference, Available at:http://phx.corporateir.net/External.File?item=UGFyZW50SUQ9Mzk3M zY1fENoaWxkSUQ9NDAzNjQ4fFR5cGU9MQ==&t=1.

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Existing facilities are located to the north and sout h of the plant. Photographs of these units and engineering analyses indicate Sa mmis Units 6 and 7 are more congested than the SJGS units. 180

We proposed a compliance schedule of 3 y ears and solicited comments on alternative timeframes up to 5 years. 181 The BART Guidelines require documentation of any "unusual

circumstances" that would affect cost effec tiveness, 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 sc hedule, nor any demonstra tion 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 desc ribed above, we find that a cha nge to our proposed compliance schedule is appropriate. We belie ve that a longer time frame than the median time frame for

construction identified in our surv ey 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 eff ective 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 th e 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 respons e to comments, we have modified the compliance schedule. We are fi nalizing a schedule which requires compliance with the emission limits within 5 years – rather than 3 years -- fr om the effective date of our final rule. We conclude this is adequate time for the incl usion of any possible permitting requirements.

Comment: A commenter stated that our complia nce schedule of three years from the

effective date of our final rule did not allow tim e 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 qua lified vendors or provi de 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: h ttp://www.4cleanair.org/OhioEdiso n.pdf; Hans Hartenstein, Control Technologies for the W.H. Sammis Plant, Stratton, Ohio, Expert Report on Beha lf 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 fail ure to account for this renders the three-year compliance date unrealistic, and calls into question the underlyi ng cost estimates, which are based on contracts entered into by other utilities that most likely were allowed sufficient time to complete a proper compe titive 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 fo r 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 ta king 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 fi nally, the construction on each un it needs to take place during an outage. By comparison, the re cent environmental upgrades at SJGS were phased in over five years. In addition, a three

‐ year deadline would likely eliminat e 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 po ssible, which would re quire extremely large

pre

‐ fabrication yards and prefabrication crews. Due to the physical layout of the site and units, independent, simultaneous fabrication and instal lation activities would also be required. In
addition, a three

‐ year deadline would also require significa nt overtime hours, expedited material costs, double “heavy long

‐ lift” crane costs, and a larger cons truction 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 unavoidabl e in the event a three

‐ year deadline is required. Such a shor t 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 approva l from the Arizona Corporation Commission. These pre-construction activities co uld add 18 months to two years (i f 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 elec tricity, at higher prices than the electricity produced at SJGS, from the open market for at le ast 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 customer s, 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 a ffect service reliabili ty to custom ers. EPA Region 6 should

consider these costs and constr aints 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 asso ciated with the inst allation of SCRs at SJGS. Therefore, EPA should set the deadline fo r compliance to the five years allowed by law, or even longer of [sic] PNM is required to re spond with a “Better than BART Alternative.”

Response: As stated elsewhere in our respons e to comments, we have modified the compliance schedule. We find that compliance with the emission limits must be within 5 years77 of the effective date of our final rule. A l onger schedule will allow PN M to tie in the SCRs during routinely scheduled maintenance outages a nd 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 determina tion 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 w ould have an adverse effect on the cost of electricity. Based on 2006-genera tion numbers of 12.5 million MWh’s, amortized over a 20-year period at 8% interest, and a $750 million modificati on price, the commenter calculates the cost of electricity would increase by approxim ately $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 th e 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 find s that they produce far lower emissions than conventional petroleum-based fuels.

According to the commenter, the conversi on 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 th e 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 ba rrel per day CTL plant can co-produ ces 1200 MW of clean, efficient, low carbon power. This would be baseload gene ration, the commenter ar gues, that would be produced 24/7 and could be sold into the Californi a 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 ex isting CO2 pipeline in the vicinity. The CO2 from the plant could be sold to KinderMorga n and used for enhanced oil recovery. The

commenter also notes that ash in the coal is melte d in the gasification process, and can be used as an aggregate for paving roadways. In addition, th e 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 subs tantially reduced by reutilization of much of the plant, including coal handling equi pment, steam turbines, condensers, cooling towers, and transmission lines. The re-utilization of ex isting equipment could reduce the capital cost by an estimated 25 to 35% as compar ed to a totally new facility. The commenter suggests this could be a BART (re trofit) 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 consid er conversion to a CTL plant with integrated power generation to be BART for SJGS.

Response: We appreciate the commenter’s sugges tion that we consider CTL technology with integrated power generation as an opti on 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 cons ider it as a potential NOx BART technology as it would involve a complete redesign of the plant. We note the BART guide lines state that “[w]e do not consider BART as a requirement to re design 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 re duce 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 th at submission in a future action. As discussed in our proposal, we disagree with PNM’s cost es timate 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 discus sed 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 th at 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 te rrestrial and aquatic plan ts and animals, soil health, and moving and stationary bodies of water by contributi ng to acid rain, ozone formation, and nitrogen deposition. Anothe r commenter, a retired pediatri cian, notes that NOx as a precursor to ozone, causes numerous respiratory problems and adversely affects children in particular; he supports our action. Another comment er 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 contribu tes 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 study79 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 es timated $255 million in h ealth 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’ conc erns regarding the negative health impacts of emissions from the SJGS. We ag ree that the same PM2.5 emissions that cause visibility impairment can be inhaled deep in to lungs, which can cause respiratory problems, decreased lung function, aggravated asthma, bronchitis, and prematur e death. We also agree that the same NOx emissions that cause visibility im pairment also contribute to the formation of ground-level ozone, which has been linked with re spiratory problems, aggravated asthma, and even permanent lung damage. We agree that these pollutants can ha ve negative impacts on plants and ecosystems, damaging plants, trees, an d other vegetation, and reducing forest growth and crop yields, which could have a negative e ffect on species diversity in ecosystems. Therefore, although our action c oncerns visibility impairment , we note the potential for significant improvements in human health and the ecosystem.

Although we appreciate the comm enter’s concern regarding th e negative health impacts of toxic emissions from the SJGS, we note that toxi c emissions are not considered to be visibility impairing pollutants. Similarly, mercury is no t a visibility impairing pollutant, and N2O – a GHG – does not belong to the NOx family, nor is it c onsidered 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. Ac cording to the commenter, the SJGS is one of the greatest NOx polluters in the nation, contri buting to the formation of harmful particulate matter, ground level ozone smog, and acid rain.

Response: We appreciate the commenters’ concer ns regarding the NOx emissions from power plants such as the SJGS. We agree that these emissions are detrim ental to human health and the environment, with NOx being a precursor to ground-level ozone a nd 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 be lieve 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 appropri ate and necessary for us to promulgate a FIP that addresses interstate transport of air pollutants from New Mexic o, pointing out that the

SJGS is located a short distance from several state boundaries. Th ey also state we should have presented a clearer explanation of the events that have taken pl ace related to New Mexico’s work

on the SIP in the 2003-2010 timeframe. The comment er 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 SI P would have added clarity for the public.80 Response: We believe the level of detail we in cluded in the “Backgroun d” section of our proposal is appropriate and sufficien t to give the public a clear pict ure of the events leading up to our proposal. In particular, the subsecti on titled Statutory and Regulatory Framework Addressing Interstate Transport a nd Visibility provides detailed in formation to give the public a clear picture of what we received from New Mexi co in terms of the RH SIP and the Interstate Transport SIP.

Comment: A commenter is concerned with degr adation 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 visibili ty in neighboring states seems to be unsupported by the evidence presented by NMED.

Response: We note that it appears that the comm enter 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 In terstate Transport SIP that no s ources in New Mexico impact the protection of visibility in nei ghboring states. Instead, New Mexi co’s Interstate Transport SIP stated that the requirement under section 110(a)(2)(D)(i)(I I) that the state no t interfere with the visibility programs of other states would be a ddressed 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 altern ative means of demonstrating that emissions

from its sources would not interfer e 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 statutor y 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 achie ving 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 emi ssion 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 mu st be balance in the proposals and regulations that are presented by the federal and state government s. 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 expresse d his belief that our proposal is counter-productive and has a better than average potent ial to harm the local and state81 economies. The commenter stated that the t echnology we are proposing is costly and seems unnecessary, as PNM recently comp leted 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 im pact to the local community. The commenter expressed his belief that cost estimates from th e 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 act ion, and suggests allowing tomorrow’s technology provide a solu tion to today’s problems.

Response: We understand the commenter’s concern regarding the need for balance in the regulations promulgated by state and federal gov ernments. 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 sign ificant improvements in public health. The SJGS is one of the largest sources of NOx in th e western U.S. and is within 300 kilometers of 16 Class I areas. Finalizing our proposal is neces sary to satisfy CAA requirements, including section 110(a)(2)(D)(i)(II) with respect to prev enting emissions from New Mexico sources from interfering with other stat es’ measures to protect visibility. As previously stated, we have an obligation to promulgate a FIP to address the requirements of secti on 110(a)(2)(D)(i) with respect to visibility and a FIP to address the re quirements 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 th at our proposal is counter-productive. As presented in our proposal, our mode ling analysis demonstrates signi ficant 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 complia nce with all current health requirements,” we note that as part of our visibility im pairment and BART evaluation, we did consider the controls previ ously installed by PNM as a result of its consent decree with the Grand Canyon Trust, Sierra Club, and NMED on March 10, 2005. These c ontrols included the

installation of low-NOx burners wi th overfire air ports, a neural network system, and a pulse jet

fabric filter.

However, as we discuss elsewhere in our re sponse to comments, thes e controls were not sufficient to prevent New Mexico sources from in terfering with measures required in the SIP of any other state to protect visibi lity, pursuant to section 110(a)(2 )(D)(i)(II) of the CAA. The

reduction in NOx from our NOx BART determina tion 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 stat es. In addition, the RHR requires us to examine additional retrofit technologies. We have determined that SCR is cost effective and results in significant visibility im provements 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 m ore accurate than government estimates,82 we note that we take our duty to estimate the co st of controls very seriously and make every attempt to make a thoughtful and well-informed de termination. With regard to the commenter’s belief that this is not an issue that requir es emergency action and that we should allow tomorrow’s technology provide a solution to today’ s problems, we note th at Congress added the BART requirements to the CAA in 1977 to focus a ttention on the visibility impacts from sources such as SJGS. We therefore believe it is approp riate 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 sta ndard, and to satisfy certain related RH requirements. We also note that as described el sewhere in this preamble, New Mexico has only recently submitted a RH plan that addresses the inte rstate provisions of the CAA with respect to visibility, and as also explained we cannot review it as part of th is action. The FIP clocks of both statutory requirements have expired and we th erefore 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 it s resource planning by handi capping its ability to cost effectively respond to changi ng 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 investme nts. 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 resour ces, changes in acceptance of coal resources by State utility commissions, and reduced demand fo r 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-l ong 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 Bo ard. The commenter suggests that further reductions could be made at the plant, in cluding the possible installation of SCR, over subsequent planning periods. Su ch an approach would reduce the immediate financial burden on the power plant’s customers, allo w time for greater certainty in terms of potential carbon limits and customer demand, and retain greater fl exibility in future resource decisions.

Response: Regarding costs, EPA reevaluated proj ections 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 emi ssion limits we select today are the result of a schedule in the 1977 Clean Air Act to make grad ual 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 a83 result of its consent decree w ith the Grand Canyon Trust, Sie rra Club, and NMED on March 10, 2005. However, in making the NOx BART determ ination, 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 ar e 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 installa tion costs within the limited timeframe without resorting to a reduction-in-force th at would potentially impact Nava jo 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 lo cal employment during that time associated with the installation of pollution cont rols. The RHR requires that th e 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 propos al, we found that PNM did not identify any significant or unusual environmental impacts associated with the cont rol alternatives that had the potential to affect the selection or eliminati on of that control alte rnative. For SCR and SCR/SNCR hybrid technologies, the non-air qual ity 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 o ccurrences 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 degr ee of visibility impairment in Class 1 areas. The purpose of th is decision is to signifi cantly decrease impairment from the largest man made sources. In addi tion, the emissions resu lting from wood burning stoves and fireplaces are typically included in the emission invent ory, 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 th e 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 Orde rs Review section of th is action, which includes

our determination that the FI P does not contain a Federal mandate that may result in expenditures that exceed the inflation-adju sted Unfunded Mandates Reform Act of 199584 (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 represen ting states, tribes, local govern ments, various organizations and concerned citizens in support of this rule making: These comments were received at the Public Hearing in Farmington, New Mexico, by in ternet, and through the mail. Each of these commenters was generally in fa vor 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 curren tly or potentially released by the facility. A number of representative comments from th is group are summarized below. Please see the

docket associated with this ac tion 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 comm ent letters in the doc ket 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 specif ically 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 Co lorado in support of this rulemaking. These comments include support for our careful eval uation of NOx emission control costs for the SJGS, and our proposed promulgation of cost eff ective emission control for this facility to improve visibility and provide other environm ental benefits. The State of Colorado also encouraged us to work closely with the State of New Mexico in selectin g 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 pr oposed action to prevent emissions from New Mexico sources from interfering with other st ate’s measures to prot ect visibility, and to implement NOx and SO2 emissions limits at the SJ GS to prevent interfer ence. In addition, the Tribe supports our proposal to regulate emissi ons sources in neighbor ing areas that could undermine the Tribes’ efforts to maintain air quali ty on the Reservation. The Tribe is concerned about the impacts of emissions from SJGS on visibi lity on the Reservation; therefore the Tribe is in favor of reducing the regi onal transport of ozone and oz one 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 Sa n Juan Generating Station.

Another commenter expressed support of our pr oposal. The commenter states that for the past 30-40 years, the SJGS ha s had a largely unrestricted us e of the large common air-shed shared by Montezuma County, Colorado and Sa n Juan County, New Mexico. During this85 timeframe, the residents of Montezuma County and their neighbors have been continually exposed to the air pollution ar ising from the SJGS, yet the residents of Montezuma County receive no benefit from operati on 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 fr om the Park. The commenter states that the 2.88 deciview of visibility impr ovement 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 websit e claims that SCR is “unnecessary” and would “raise electricity prices for the SJGS’s two m illion 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 in stallation of emission cont rols pursuant to the

2009 consent decree. The commenter also states that it is legally, soci ally, 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 st ates that although PNM characterizes the SJGS as a “low cost” produc er 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 w hom do not consume SJGS power and derive no economic benefit from the facility. The comm enter believes a three-year implementation schedule for SCR at the SJGS is both appropr iate and achievable at a reasonable cost.

Letters of support were also received from re presentatives of the following organizations: New Mexico Interfaith Power and Light, the Si erra Club, San Juan College, San Juan Basin Health Department, San Juan Citizens Allian ce, LaPlata County Board of Commissioners, League of Women Voters of La Plata County, PNM home and business customers, Mesa Verde Nation Park volunteers, Wild Eart h Guardians, Green Think Dine Power, Northern Dine Youth Committee, and Dooda Desert Rock. Each of th ese commenters was generally in favor of our proposed pollution control technology for the SJ GS 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 amm onia released by the facility.

Response: We appreciate the support of these commenters for th is action. We note that several of the specific emissions and timeframe limitations suppor ted by these commenters in the proposal have been modified slightly in this fi nal 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 Hu rt the Economy and/or Raise Electricity

Rates

The preamble to the finalized FIP has identical res ponses to the ones provided in this section. As stated in the preamble, we f ound there to be significant overlap between many comments. EPA has summarized and provided responses to ea ch 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 expens e not justified by the likely results of that investment, and would be a terrible, indefensib le waste of resources. Plant shutdown would

result in the loss of hundreds of jobs in direct plant employme nt, coal mining, and other support and service sectors. The commenter also point s 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 fo r 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 co mmenter states that plant modifi cation 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 i ndicates that all three op tions would result in an increase in the cost of electricity to customer s, which should be avoided or eliminated in light

of the weakened and unstable economic conditions at the national, stat e, and local levels.

Another part owner of Unit 4 at the SJGS, submitted comments stating that the impact from imposing its share of the cost s 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 SO 2 emission limits at the SJGS to prevent

interference with other st ates’ visibility SIPs as well as requir ing 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 ex isting pollution control te chnology in use at the source, (4) remaining useful life of source, and (5) degree of improvement in visibility which may reasonably be anticipated to resu lt from the use of such technology.

After careful cost review EPA has determined that the significant be nefits 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 res ponses to the ones provided in this section. As stated in the preamble, we f ound there to be significant overlap between many comments. EPA has summarized and provided responses to ea ch 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 diffe rent jobs in the Region and by increasing tourism. In particular, one commenter stated reducing visibility-causing pollu tants 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 that87 tourism is critical to the econom y 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 j obs. Parks attract businesses and individuals to the local area, resulting in eco nomic growth in areas ne ar parks that is an average of 1 percent per year gr eater than statewide rates over the past three decades. National parks also generate more than four dollars in va lue to the public for ev ery tax dollar invested. Therefore, this commenter concluded, improving vi sibility at these national parks improves the

local economies around them.

This commenter also noted that an add itional 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 sh ort-term construction jobs as well as permanent operations and management positions.

Response: We agree with the comments. Alth ough we did not cons ider the potential positive benefits to local economies in making our decision today, we do expect that improved visibility would have a positive impact on touris m-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 res ponses to the ones provided in this section. As stated in the preamble, we f ound there to be significant overlap between many comments. EPA has summarized and provided responses to ea ch 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 ou r proposal was due to close on March 7, 2011. In response to requests we extended the pu blic 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 ba sed 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, ar e 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 th at was sent to the NMED on February 11, 2011 (later submitted to EPA on July 5, 2011), while ot hers 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 decisi on 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 sec tion 110(a)(2)(D)(i) for the 1997 8-hour ozone and

PM 2.5 NAAQS on September 17, 2007. New Mexico’s September 17, 2007 submittal addressed the requirement that the state not interfere with th e 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 natio n’s national parks and wilderness areas by the required date of December 17, 2007. We found that New Mexico fa iled to submit the plan elements required by 40 CFR 51.309(g), the reasonable progress requirement s 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), whic h 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 woul d provide the basic progra m 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 fail s 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 requirem ents 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 WildEa rth Guardians to resolve this matter.

This consent decree specifi cally 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 th e requirement of 42 U.S. C. § 7410(a)(2)(D)(i)(II) regarding interfering with measures in other states related to protection of visibi lity. 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 FI P; 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, EPA89 proposed a FIP on January 5, 2011. We receive d 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 stat ed they do not support the proposed rulemaking. Their reasons included: it will a ffect the town’s economy, affect the coal power plant industry, electricity costs wi ll increase, they have no direct health problems from actual emissions, direct and indirect jobs/businesses would be affected, curr ent air pollution control equipment meet EPA and health standards. Othe rs commented that our d ecision is arbitrary as no other similar facilities have the same require ments imposed by the FIP and that there will be no benefit to the community. One commenter ar gues that SJGS already meets the visibility standards require d by the CAA.

Response : While we appreciate the effort and ti me 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 identi cal 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 res ponses to each significant argument, assertion and question contained within the totality of these comments.

1. EPA’s Authority

Comment: Various commenters argued that comb ining Interstate Transport and RH BART requirements in the proposed action excee ds 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 author ity 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 addr essing 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 SJ GS is subject to both provisions of the CAA, and both provisions concern emissions of NOx (a mong other pollutants). To separate our actions could potentially lead to the same source needin g to install two successive levels of control measures, the first in order to meet the require ments 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, am ong 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 impl ementation plan for any other State to protect visibility. CAA secti on 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 PM 2.5 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 tr ansport of air pollution affecting visibility, and st arted 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 co mplete SIPs for improving visibility in the nation’s national parks and w ilderness 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 ar eas 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 el ement required by 40 CFR 51.309(d)(4), which requires BART for stationary source emi ssions 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 PM 2.5 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 subm ission 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 ac tion on January 5, 2011, the state had not make the RH SIP submission as represented in its se ction 110(a)(2)(D) submissi on, and had not make a RH SIP submission or alternate section 110(a )(2)(D) submission indi cating 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 pa st 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 resu lt of the 2009 finding of failure to submit the RH SIP. Moreover, the July 5, 2011, submission also occu rred more than four ye ars after th e date by91 which we were obligated either to approve a SIP submission or to promul gate a FIP to address

the state’s failure to submit a submi ssion for section 110(a) (2)(D)(i)(II).

We are under a consent decree deadline with WildEarth Gu ardians that requires the Agency to take action by August 5, 2011, eith er to approve the New Mexico section 110(a)(2)(D) SIP, or to promulgate a FIP, to address the 11 0(a)(2)(D)(i)(II) visibility prong. Because of the lateness of the July 5, 2011 s ubmission, 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 promulga te 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 whol e or in part the SIP submission. CAA section 110(c)(1). As previously disc ussed, we have made findings re lated to the New Mexico SIP submission needed to address interstate transp ort and the requirement that emissions from New

Mexico sources do not interfere with measures re quired 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 subm it 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 re gulatory 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 visi bility requirements of section 110(a)(2)(D)(i)(II) and RH program requi rements simultaneously in these circumstances because the purposes and requirements of the inte rstate transport provis ions 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 stat es 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 s ource 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 vi sibility.” These required SIP meas ures 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 st ates. However, because the RH program requires measures that must be included in SIPs speci fically to protect visibility, EPA’s 2006 Guidance 184

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 an d PM 2.5 National Ambient Air Quality Standards,” from William T. Harnett, Director Air Quality Policy Division, OA QPS, 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 respec t to visibility.

Subsequently, when some stat es did not make the RH SIP submission, in whole or in part, or did not make an approva ble RH SIP submission, we have evaluated whether states could comply with section 110(a)(2)(D)(i)(II) by other m eans. Thus, we have elsewhere determined that states may also be able to satisfy the re quirements of CAA secti on 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 wo rds, 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 s eek to address these issu es 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 inappropria te and conflicts with the structure and purpose

of the CAA.

Response: We disagree with the premise of th e 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 au thority 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 act ion is inappropriate and conflicts with the structure and purpose of the CAA. We have au thority to act on submi ssions, or portions of submissions, as appropriate to meet the require ments of the CAA, in accordance with section 110(k)(3). In this instance, we have determined that it is appr opriate to take action addressing the NOx BART requirements for an individual s ource, and thereby to meet a portion of our outstanding statutory FIP obligat ion for the RH program, at the same time as acting on the section 110(a)(2)(D)(i)(II) SIP s ubmission with respect to the vi sibility prong to meet that statutory FIP obligation.

We note that we have previously acted on ot her portions of the s ection 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 nonattain ment” prong of section 110(a)(2)(D)(i) (75 FR 33174, June 11, 2010); and (2) the “interfere with ma intenance” and “interfere with measures to prevent significant deteriorati on” 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 subm issions, or were it contrary to the structure and pur pose 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 required93 by section 110 of CAA, is contrary to the purpos es and goals of the CAA. The CAA requires us to promulgate a FIP if a State has failed to ma ke 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 disappr oving 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 transpor t provisions of CAA 110(a)(2)(D)(i) for the 1997 8-hour ozone and PM 2.5 NAAQS. In this submission, the state indicated that it intended to meet the requireme nts 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 promulga te a final action prio r to the August 5, 2011

deadline.

Therefore, as previously stated, we have bot h a statutory obligation to promulgate a FIP to address the requirements of s ection 110(a)(2)(D)(i) wi th 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 ar e intertwined. As such, we consider it appropriate to promulgate one FIP that addresses both th e requirements of section 110(a)(2)(D)(i) with respect to visibility and the BART requi rements 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 th at 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 S ection 110 of the CAA because it provides too stringent a control for attaining visibility sta ndards, 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 pr ovisions adequate to pr ohibit emissions from

sources in that state from interfer ing with measures required to prot ect 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 sour ce, 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 SO 2 emissions used in the WRAP photoc hemical modeling, as part of this action in order to be in complian ce with section 110(a)(2)(D )(i). Our action is also based in part on our authority to address the NOx BART require ments 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 sect ion 110(a)(2)(D)(i)(II) in the proposal, and that EPA failed to explain adequately its inte rpretation of CAA secti on 110(a)(2)(D)(i)(II) and the relationship between that pr ovision, as interpreted by the Agency, and CAA sections 169A and 169B. In addition, the commenter asserted th at 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 guida nce to states for these SIP submission.

Response: We disagree with these assertions. First, in th e 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) requ ires states “to have a SIP, or submit a SIP revi sion, 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 ex plicitly stated that “[b] ecause of the impacts on visibility from the interstate transport of po llutants, we interpret th e ‘good neighbor’ provisions

of section 110 of the Act describe d above as requiring states to in clude in their SIPs measures to prohibit emissions that would inte rfere with the reasonable progre ss 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 whethe r a state’s SIP contains adequate provisions to prevent emissions from sources in that state from interfering with measur es 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 explaini ng our reading of the ambiguity in the statute in th is notice and comment rulemaking.

Thereafter, we articulated in detail the unde rlying premise for our 2006 guidance, and the recommendations that states address this requi rement through submission of the RH SIP. We specifically explained the basis for our belief th at 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 particul ar 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 ba sis 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 Ne w Mexico sources in the development of their reasonable progress goals in their respective vi sibility programs. Mo reover, our proposal articulated that evaluation of the analysis conducted by the WRAP is one means of gauging whether New Mexico has adequately contro lled its sources for this purpose.

We also disagree with th e 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 visib ility in mandatory class I Federal areas which95 impairment results from manmade air polluti on.” 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 re gulations 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 impair ment.” 45 FR 80084 (December 2, 1980). These regulations represented the first phase in addre ssing visibility impairment. We deferred action on RH that emanates from a variety of s ources until monitoring, modeling and scientific knowledge about the relationships between pollutant s and visibility impairment were improved.

Id

.

Congress added section 169B to the CAA in 1990 to a ddress RH issues, and we promulgated regulations addres sing RH in 1999. 64 FR 35714 (J uly 1, 1999), codified at 40 CFR part 51, subpart P (the RHR). The RHR re vised the existing visibi lity 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 vi sibility impairment no later than December 17, 2007. 40 CFR 51.308(b).

We disagree with the argument that b ecause section 169A and B create a specific program for protection of visibi lity, that compels the conclusi on that section 110(a)(2)(D)(i)(I) could not have any substantive bear ing on this issue. Such an argument is at odds with the clear provisions of the statute, and w ith the structure of the CAA. Section 110(a)(2)(D)(i)(II) of the CAA requires that SIPs shall incl ude adequate provisions “prohibiti ng . . . any source . . . within the State from emitting any air pollutant in amounts which will . . . interfere with measures required to be included in the applicable implem entation plan for any other State under part C . .

. to protect visibility .” (Emphasis added). Because sections 169A and 169B establish the national goal for visibility protec tion, including RH issues, we infer that when Congress included protection of required visibility programs in other states as part of sect ion 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 w ith 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 wh ether 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 th at 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 argumen t 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 not96 negate the requirement that states also meet th e requirement of the “significant contribution to

nonattainment” and “interference with maintena nce” prongs of section 110(a)(2)(D)(i)(I), and the authority of EPA to require substantive provi sions 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 inters tate transport of pollutants, we thus interpret the “good neighbor” provisions of section 110 of th e Act described above as requiring states to include in their SIPs measures to prohibit emi ssions that would interf ere 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 th e commenter’s views concerning the state’s September 2007, submission complying with the Agency’s 2006 guida nce, and even if it had complied with that guidance, the purported legal signi ficance of that fact for purpo ses 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 inte nded means of meeting the requirements of section 110(a)(2)(D)(i)(II) for visibi lity, but due to intervening even ts 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 guidan ce 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 “c urrently” premature for states to make a more substantive SIP submission for this element, because of the anticipat ed 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 m eet applicable RH program requirements and therefore be approved shortly ther eafter. Thus the premise of th e 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 inappropria te 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 recommendati ons 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, th e commenter was clearly in er ror 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 th e 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 sufficien t 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 th at section, must be ma de 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 overr ides the timing requirements of

the statute. We believe that there are means av ailable now to evaluate whether a state’s section 110(a)(2)(d)(i)(II) SIP submission meets the substantive requireme nt that it contain provisions to prohibit interference with the visi bility 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 st ates. Thus, this evaluation is supposed to

consider what other states should have in their SIPs as of this point in tim e, and is not limited by the fact that other states may or may not have made the requi red RH SIP submission, nor by the fact that we may or may not ha ve approved those RH SIP submissi ons 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 incl udes the RH program required in other states. As discussed above, we believe that one means to eval uate 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 emissi ons 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 ade quately 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 FI P is not legally supported. The FIP satisfies provisions in both section 110(a)(2)(D)(i)(I I) of the CAA regarding inters tate transport of pollutants affecting visibility in other st ates 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 pr otect visibility. Therefore, we are imposing through the FIP, specific emission limits upon the SJGS to prevent such interference. We are imposing an SO 2 limit and a NOx limit. To provide greater certaint y to the SJGS that controls needed to prevent

interference with other st ates’ visibility programs, as well as the controls needed to meet the RHR’s BART requirements, do not conflict w ith 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 postponi ng 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 Mexi co has met the requirements of the RHR for any other sources; we are not addressing wh ether the SJGS is meeting the RH BART requirements for any other pollutants; and we wi ll address those require ments in later actions.

We have the specific authority to promul gate 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 (J anuary 15, 2009). This finding started a two year clock for the promulgation of a RH FI P 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 possi ble conflict between a NO x 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 SO 2 from the SJGS based upon the WRAP determination of each member state’s contribution to visibility impairment of SO 2 emissions, of which New Mexico is a member. The SJGS’s existing SO 2 permit does not provide the necessary emission limits and enforceable mechanisms to ensure the

SO 2 emissions used in the WRAP photochemical modeling for the SJGS units will be met. Therefore, we assumed the SO 2 emission limit used in the WR AP 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 protecti on context of Section 110(a)(2)(D)(i)(II) for New Mexico, and that EPA should account for a broade r range of causes of visibility impairment when considering regulating interference with other states’ visibilit y. According to the commenter, EPA’s action should consid er 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 Ne w 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 emissions99 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 provisi ons 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 SO 2 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 re lied on WRAP modeling to determine the appropriate emission limits for sources in New Me xico in order to determine if New Mexico’s emissions were interfering with other state visibi lity 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 reason able progress goals for each area. Western states are relying on the WRAP assumed reduction in emi ssions levels modeled for sources in New Mexico including the SJGS in order to meet th eir 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 visibil ity impairment of federal class I areas. Thus, we proposed a FIP to prevent emissions fr om New Mexico sources from interfering with other states’ measures to protect vi sibility, and to implement NOx and SO 2 emission limits necessary at one source, the SJGS, to prevent su ch interference, as we ll 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 significantl y 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 Me xico sources on the WRAP analysis, and

consideration of the sources that other states would have assume d that New Mexico intended to control as part of that modeling. The stat e’s initial submission fo r section 110(a)(2)(D)(i)

indicated that the state intended to meet its obl igations with respect to the visibility prong by means of the RH SIP. Therefore, we have examin ed the issue in light of what other states would

have assumed such a SIP would achieve. Moreov er, 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 em issions from SJGS are a significant source

of NOx emissions that interfere with other stat e’s required visibility programs. In addition, based on the facts and information currently availa ble, we believe the most effective means of ensuring that emissions from New Mexico do not in terfere with other stat es’ visibility programs is to require further and federally enforceab le NOx reductions and federally enforceable SO 2 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 impair ment 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 consid er 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 co mmenter suggests we consider future growth in emissions from area sources such as oil and ga s development as part of our control strategy. We agree with the commenter that oil and gas ac tivity in New Mexico produces NOx and other

emissions. We understand the WRAP is curr ently 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 EP A’s rules and conflicts with th e 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 conflic ts with CAA Section 169 A. We disagree with the statement, because the NOx BART determinati on 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 r eceived. We cannot further evaluate or respond to this comment. In any event, the other comme nts are separately addre ssed 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 legisl ative history, where it stated th at “...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 comment er 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 aut hority 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 respons ibility to make a NOx BART determination for

SJGS.

187 70 FR 39104, 39120.101 Comment: One commenter argues that an eval uation of the amount of reasonable progress expected to be achieved in the Class I areas by other contro l 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 RH R that can be evaluated on its own. BART can be a part of a reasona ble progress strategy, and controls imposed under other CAA requirements can be cons idered to be BART, In fact, as we discuss elsewhere in our response to comments, we did evaluate the ex isting controls at the SJGS, but found them inadequate to satisfy NOx BART. However, ther e is not any requirement in the RHR that would require we first make an evaluation of r easonable progress prior to conducting a BART evaluation, nor is there any cons ideration of lessening the degree of a potential BART control in light of other CAA programs.

Comment: One commenter alleges our proposed ru le 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 neig hbor” 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 assert s that BART is more stringent than 169A requires, because it is being used “out of cont ext” in a limited Section 110 program designed to

ensure one state does not interfere with anothe r 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 we re 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 th e SJGS under section 110 of the CAA. We are requiring NOx BART for the SJGS unde r section 169A and the RHR. Further, we disagree with the statement that BART require ments were selectively borrowed from the RH program or that any provisions were selectively borrowed or cons idered 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 emission s unit. We then established BART for those

units under the RH Rule and the Guidelines fo r 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 acti on 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 commente rs 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 und er Section 110 and the determina tion under Section 169A have created any conflict or flaw in the im plementation of either program.102 Comment: A commenter states that a lthough a similar analytical a pproach 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 Fo ur Corners. EPA should reconsider the emission limit it assumed for San Juan in the site-spe cific, plant-wide ma nner employed by Region 9.

Another commenter states the pr oposal fails to consider ot her BART-eligible sources or other emission control strategies. In addition, the commenter is c oncerned that our proposed FIP for the SJGS may have been inappropriately in fluenced by the FIP proposed for Four Corners Power Plant by Region 9. Although the overall anal ytical 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 c onsistent 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 conclu de 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 a nd site congestion, were

factored into our SJGS NOx BA RT visibility modeling (baselin e emissions) and cost evaluation, respectively. Also, concerni ng the amount of review time (e .g., comment period), our consent decree deadline prevents us from extending the comment period more th an 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 em ission 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 em ission 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 atta ining 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 complia nce 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 simila rity 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 determ inations 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 Po wer Plant: Navajo Nation, 76 FR 10530103 Response: We disagree that the results (e.g., emission limits and controls) of our proposed NOx BART determinations for Oklahoma 189 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 di d not see the need to re fine 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— onl y that we did not see the need to refine it. With regard to the different BART compliance schedules between our pr oposals, we believed in SJGS’s case that the expected visi bility benefits were so signifi cant 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 emissi on limits within 5 years – rather than 3 years

– from the effective date of our final rule.

Comment: Some commenters have st ated that the proposed FIP does not satisfy other requirements of the RH Program.

Response: We are acting on a portion of the St ate’s SIP revision addressing Interstate Transport requirements, specifically visibility. We are not acti ng 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 SJ GS 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 requireme nt to install SCR at the SJGS is a fatally flawed and unnecessary approach to RH re duction, 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 genera lized statement. It s hould 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 anal ysis 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 au thority 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 fr om 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

Commen t: The MSR Public Power Agency (MSR) disagrees with our findings under the

Unfunded Mandates Reform Act of 1995 that th e 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 ($10 0 million in 1995 dollars) or more in any one year thus triggering a written a ssessment of the costs and benef its of the proposed FIP. MSR

believes that the cost of retrofit ting the four units at the SJGS is closer to PNM’s estimated cost of $908 million.

Response : The Unfunded Mandates Reform Act (U MRA) requires that Federal agencies

assess the effects of Federal re gulations on State, local, and tr ibal governments and the private sector. In particular, UMRA re quires 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 aggregat e, 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 fo r inflation. In other word s, even if the entire

Total Annual Cost of the installa tion of SCRs on the units of th e 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 subjec t to review under the

Executive Order.

Comment: One commenter states that the propose d 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 Pr esident issued the referenced Order on January 18, 2011, after we issued our proposed rule making. 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; pr omotes predictability and reduces uncertainty; identifies and uses the best, most innovative, an d least burdensome tools for achieving regulatory ends; and takes into account benefits and costs, both quantitative and qu alitative. However, nothing in the Order shall be cons trued to impair or otherwise a ffect 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 wa s 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 respons e to comments for a deta iled 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 131 75, and that consultation is required because of the impacts to Navajo workers, contractors, a nd subcontractors at San Juan Generating Station

and the San Juan Mine.

Response: Executive Order 13175, entitled ‘‘Consulta tion and Coordinati on 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 a nd 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 trib al implications, as specified in Executive Order 13175, because this action does not impose federa lly enforceable emissions limitations on any source located on tribal lands, a nd neither imposes substantial di rect compliance costs on tribal governments, nor preempts tribal law. However, in response to this comment, we engaged in government-to-government consultation at the reques t 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 reques ted 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 stat es that we have no sound basis in any event for disapproving New Mexi co'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 thatour proposal to adopt a FI P before NM completes its ongoing rulemaking process to adopt a RH SIP is premature and deprives the state of its significant discretion to establish an d administer its own RH program.

Response: We disagree that we should appr ove the SIP submitted in 2007 because it satisfies both our policy and the WEG Consent D ecree. Our consent decree with WEG requires that by August 5, 2011, we must appr ove a SIP, promulgate a FIP, or approve a SIP in part with promulgation of a partial FIP for New Mexi co to meet the requirement of section 110(a)(2)(D)(i)(II) regarding interfering with measures in othe r states related to protection of visibility. As stated elsewhere in this notic e, New Mexico’s 2007 submittal fails to meet this requirement. That SIP anticipated the timely s ubmission of a substantive RH SIP, which was due by December 17, 2007, as the means of meeti ng 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 SI P submissions, on January 15, 2009, we published a ‘‘Finding of Failure to Subm it State Implementation Plans Re quired by the 1999 regional haze106 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). Secti on 51.309(d)(4)(vii) states:

The implementation plan must contain any necessary long term st rategies 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 st ates, including New Me xico, 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 de termination for the SJGS. In response to the second commenter, we do not view it as premat ure to take action on one element of the RH requirements at this time. We chose to exercise this authority to conduc t 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 th eir sources of emissions to meet the requirements of the CAA.

Comment: One commenter argues that the Admi nistrative 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 elsewher e in our response to comments for a detailed description of what is addresse d 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 sc ope 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 C AA requirements that a SIP must have adequate provisions to prohibit emissions from adversely affec ting another state’s air quality through interstate transport and that certain facilitie s install BART to protect visibility in national parks and wilderness areas. The visibility proble m in these areas of great scenic importance has been recognized as a significant issue by policym akers from Federal, State and local agencies, industry and environm ental organizations. 191 Technical data, that are pa rt of the record, evidence

191 See RHR, 64 FR 35714 (July 1, 1999).107 that emissions of SO 2 and NOx from the SJGS are interfering with efforts to protect visibility in other states, as well as impacti ng 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 Me xico’s 2018 projected emissions and New Mexico’s current emissions that were developed for the WRAP photochemical modeli ng. 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 th at EPA’s summary of that analysis presents no relevant data to s upport the Agency’s conclusion. Because the WRAP

inventories are so extensive and difficult to re search and review, EPA at a minimum should have provided copies of the State’s emissions invent ories that were reviewed and the specific emissions data for SJGS that supports EPA’s c onclusion. SJCC stated that EPA should not have put the burden of interpre ting the WRAP technical support documents on the reader. Furthermore, in light of the substantial num ber and different types of emission sources throughout New Mexico, our conclu sion is suspect. EPA must pr oduce the specific emissions

information for SJGS and for all other emission sour ces in the State, which isolates SJGS as the only reason for New Mexico’s interstate in terference with visi bility protection.

Response : While we did point in the proposed ru le to the WRAP website as a reference for the emission data that we reviewed and comp ared, 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 Determina tion) and 4 (BART Guid elines and Modeling Protocols) of the TSD we di scussed the WRAP’s CALPUFF sc reening modeling and why we identified SJGS as the only source in New Mexi co 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 St ate 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 mode ling 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 “em its any air pollutant which may reasonably be anticipated to cause or contribute to any impairment of visi bility” 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 th reshold, of the 11 sources, only one source’s visibility impacts at any Class I area due to its combined SO 2, 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 th e potential to emit 250 tons or more of a visibilityimpairing air pollutant, that were put in place between Au gust 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 impa irment 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 contri butes to any visibility impairment for the purposes of BART. However, this threshold shoul d 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 conclusi on reached by both New Mexico and EPA would be unlikely to change. Therefore, these facil ities are not subject to BART. As such, New Mexico did not propose additiona l controls for these faciliti es nor did the WRAP modeling

include additional reductions for these 10 sources. These 10 sources are sufficiently controlled

to eliminate interferen ce with other states’ visibility programs.

Our review and the States’ particularly focu sed 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 r unning of the WRAP initial BART CALPUFF screening modeling that iden tified the one source subject to BART, the WRAP ran photochemical modeling for all the sources in the en tire 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 in puts, particularly the future year projections for all of the s ources in the region. All the part icipating WRAP states agreed to the emissions input for the base and future y ears. These states are relying upon the WRAP photochemical modeling’s future year projected em issions from all the sources in the region to establish their Reasonable Progress Goals. In consultation with New Mexico, the WRAP photochemical modeling included anticipated reducti ons in emissions at the SJGS. Through the WRAP consultation process, New Mexico provid ed 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 reasona ble progress plans toward s natural visibility conditions. New Mexico, however, di d 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 di scussed previously, SJGS, was found in the BART modeling to, by itself, contribute signif icantly to visibility impairment.

Our review of the WRAP BART CALPUFF sc reening 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 revi ew, 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 fu ture 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 agr eed 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 public ly available for review on the WRAP website.

Therefore, we adequately expl ained why our action is limited to the SJGS. In addition,

the information we relied on to reach our conclusi ons is available to the public and was validated109 by a voluntary group of state, federal and local ai r agencies dealing with regional air quality issues. Relying on WRAP data provides consiste ncy of analyses throughout the Western states,

and assures that our decisions ar e not arbitrary. Thus, EPA’s deci sion is based on data to support that the SJGS is the only source that requires th e enforceable measures in this action to ensure reductions needed to meet the anticipated leve l 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 Me xico 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 inventor ies” presented in the WRAP modeling for the SJGS reported in tons per year (tpy). The commenter states th at 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 averag ing time because the WRAP averaging periods were unenforceable. This methodology was not applie d to any other source. SJCC claims that if EPA had applied this methodology to the other Ne w 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 cu rrent 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 el sewhere 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 de veloping 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 r easonable 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 re gulations or other limitations and were based on the data

available at the time. As a result of the in itial BART analysis performed by the WRAP, identifying SJGS as subject-to-BART, and consultation with New Mexico, the WRAP photochemical modeling included anticipated re ductions in emissions at the SJGS. The reductions at SJGS were the only additional re ductions 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 impa cts adjusted the future year NOx emissions from SJGS after input from NM ED 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 c ontrol equipment and the actual achievable emission rate is110 approximately 0.30 lb of NOx/MMBtu on a longe r-term basis (30 day rolling average) as currently reflected in their pe rmit and 0.33 lb of NOx/MMBtu on a shorter-term basis. Clearly, the difference between what was assumed by the WR AP and what is actua lly being achieved and is enforceable should not be ignored.

We disagree that our use of lbs/MMBtu ve rsus the annual emissions rate compromised our evaluation. There is no compromise in integr ity using the lbs/MMBtu versus using an annual emission rate, since the annual NOx emission ra te for each EGU in the WRAP photochemical modeling is calculated using the short term emissi on 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 li mitations, 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 WR AP 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 yiel d 2018 emission estimates by applying a growth factor to the 2002 firing rate up to a capacity threshold of 0.85 193 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 th e installation of controls was anticipated, such as the SJGS, they utilized the short-term emissi on 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 a nd, 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 we re just about emission rate/calculations for the photochemical mode ling or the CALPUFF modeling. Because the comment is unclear, we have addr essed their comment for both t ypes 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 CALPUF F modeling, the July 2005 BART rules recommend using the actual 24-hour maximum em ission rate over the last severa l years as the basis for the baseline emissions, and when a source is controll ed in the future the em ission 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 mo deling pursuant to EPA regulation and guidance are a short-term (24-hour) em ission 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 em ission rates were used by the st ate 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 compar ison to how the WRAP calculated future year emission rates for EGUs, and we believe we ha ve followed our regulations and guidance in accurately assessing the impacts w ith appropriate emission rates.

As part of our action for 110(a)(2)(D)(i) of the CAA, we are also setting a SO 2 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 curren tly, but does not have an enforceable limit that

limits the SJGS units to 0.15 lb of SO 2 /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 project ed 2018 emissions, as EPA asserts, then that means the only emissions reductions that will occu r 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 interpretatio n, the SJCC turned to the New Mexico emissions inventories used in the WRAP modeling and noted that the WRAP modeli ng projects a reduction in NOx emissions of about 10,500 tpy from the SJGS by 2018. The SJCC not es 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 achie ving the emission levels assumed by the WRAP modeling is incorrect. Rather, the SJCC assert s, information shows that other New Mexico

sources besides the SJGS could be “interfering” with other states’ m easures to protect visibility. The SJCC concludes that although EPA’s interpreta tion of “interference” may be reasonable on its face, the application of its explanation of its meaning indi cates otherwise. EPA’s explanation provides no credible just ification for singling out the SJGS as the only New Mexico source of

emissions that is interfer ing with other states’ visi bility-protection measures.

194 NMED Proposed Re gional Haze SIP, available at AppxA_NM_SJGS_NOxBART Determination_06212010.pdf and modeling files provided by NMED to EPA for Review June/July 2009112 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. Fo r New Mexico point sources othe r than the SJGS, the current federally enforceable emission limits for these sour ces are consistent with those relied upon in the WRAP modeling. For the SJGS, the WRAP stat es considered the imp act of the RH BART requirements. As discussed in our proposal a nd 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 anticip ated 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 ru les (including those addressing mobile sources), na tional consent decrees , and mobile source fleet turnover, among other things. These projections were reviewed an d agreed to by the WRAP states as a part of their joint development of a co mplete WRAP emission inventory in support of their RH SIPs, and were relied upon by the WRAP states as a part of the reasonabl e progress goals. The

commenter is correct that other sources in New Mexico are projec ted to reduce their emissions as well. Those projections are base d on the states’ best estimate of the growth of emissions from some sources and the future impact of all comb ined regulatory programs. We conclude, for the purpose of satisfying section 110(a)(2)(D)(i)(I I), those projections were reasonable and adequately incorporated into the WRAP modeling.

As to the comment on how we defined “interference” in th e 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 “interfe re” in the context of the interstate transport requireme nts 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 r eaching 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 SO 2 baseline and future emission rate of 0.15 lbs/MMBtu was incorrect, and that an SO 2 emission rate of 0.18 lbs/MMBtu is more appropriate. PNM alleges that th is is based on the current, federa lly enforceable emission limit. PNM asserts that our justification for using the lower SO 2 rate is that the lower rate is expected

in the future. The commenter ar gues that utilizing the current SO 2 limit is the more appropriate modeling method even though the use of the curr ent 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 propos ed controls. Due to the nonlinear nature and113 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 fr om the NOx BART proposed controls, we included the SO2 emissions as relied upon in th e WRAP modeling in our CALPUFF modeling.

The SO 2 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 SO 2 limit of 0.15 lb/MMBtu federally enforceable . PNM’s requested baseline emission

rate of 0.18 lb/MMBtu of SO 2 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 shoul d include post control maximum emission rates. 196 We note that the SJGS currently has SO 2 control technology installed and has current actual SO 2 emissions below our proposed FIP limit. As a result, the facility will not have to install additional controls to

meet our SO 2 FIP limit. As we are setting the 0.15 lb/MMBtu SO 2 emission limit in the FIP for SJGS, we modeled an emission rate of 0.15 lb/MMBtu for SO 2 for both the baseline (current) and control (future) cases in estimating the antici pated visibility improveme nt due to installation of the NOx BART proposed c ontrols. By holding the SO 2 emissions constant in the revised baseline (current) and future (c ontrol) cases, the modeled predic ted improvements in visibility due to the NOx BART proposed controls are kept separate from any potential changes in visibility due to changes in SO 2 emissions. This means the fi nal CALPUFF analysis reflects only the benefits due to the additional NOx reductions beyond the baseline. Th is also reflects the SJGS’s flexibility to increase its SO 2 emissions up to the SO 2 FIP limit of 0.15 lb/MMBtu. It provides a more representative es timate of anticipated visibility improvements from installation

of NOx controls.

Comment: A commenter disagrees with the gene ral modeling approach and assumptions relied upon in EPA’s modeling analysis. The comme nter contends that we performed numerous different visibility models and chose the one wi th the highest visibility improvements, even though the chosen model results are the least cons istent and the least re alistic of the modeling runs prepared. The commenter claims that EP A’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 realis tic, site-specific background ammonia concentrations and the Method 6 post-processing that has been reli ed upon by PNM, NMED, and WRAP and by EPA itself with regard to SO 2 (by relying on the WRAP modeli ng). The commenter argues that EPA’s rejection of PNM’s modeling is unjustifi ed 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 exp ected from BART reductions (or for BART applicability)”, Pages 39107-3918 of BART Rule For assessing the fi fth 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-contr olled 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 regardi ng 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 techno logy available for NOx. The Guidelin es 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 c ontrols available may allow a sour ce or the state agency to skip conducting visibility impairment modeling. Theref ore, because NMED selected SCR, the most stringent control generally availa ble, consistent with our RHR re quirements (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 st ate rulemaking in May 2010.

When we developed the proposed FIP for NOx BART, we conducted our own visibility impact analysis (the degree of visibility impr ovement reasonably antici pated due to NOx BART at SJGS). In conducting modeling for our pr oposed 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 t echnical concerns with the CALPUFF modeling system version, modeling options selected in CALMET, calcula tion of emissions (including sulfuric acid mist), and bac kground 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 La nd Managers to allow fo r application of the revised IMPROVE equation (“Method 8”). So me problems have been identified in the CALPUFF modeling system (v6.2111) since the original WRAP CALPUFF screening modeling

was conducted which is also the versi on used by PNM’s contractors and NMED. 197 A detailed

discussion of CALPUFF model versions and th e 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/FL M guidance, and did not follow the EPA/FLM guidance about including upper air observational data 198 . 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/regionalstatelocalmodelin gworkshop/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_f inal.pdf); “CALPUFF Regulatory Update”, Roger W. Brode, Presentation at Regional/State/Local Modelers Workshop, June 10-12, 2008,

available at (http://www.cleanairinfo.com/regionalstatelocalmodelin gworkshop/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.g ov/ttn/scram/CALMET%20CLARIFICATION.pdf)115 overview of selected CALMET settings used by NM ED/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 a nd 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 su lfuric acid that penetrates through (or is lost to) the downstream equipmen t 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 consistenc y with the most current modeling guidance EPA and the FLM representatives have provided to the states.

We performed numerous modeling runs in orde r to evaluate the sensitivity of model results to the chosen model inputs and post proces sing methods to generally inform the process. The justification for selecti ng 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 furt her in a separate response to comments. We disagree with the commenter’s assertion we si mply picked the modeling results that best supported our position, without regard to consis tency and/or realism. Every parameter and model input was evaluated and selected sepa rately, 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 EP A modeling experts and FLM representatives on these modeling issues to ensure that our mode ling 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 sensitivit y to the use of the original IMPROVE equation. Utilizing the differe nt 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 bei ng modeled, the NOx BART controls adopted here result in significant and important visibility improvement . For example, our sensitivity modeling predicted significant visibility improve ment 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 Augu st 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 SO 2 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 in stalled 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 acc ounted for the visibility improvements achieved by existing controls at the SJGS by incorporating the SO 2 and NOx enforceable permit limits established under the March 10, 2005 c onsent decree between PNM and the Grand Canyon Trust, Sierra Club, and NMED (2005 Cons ent Decree) into the baseline emissions modeling scenario. Our analysis of the visibil ity 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 instal led 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 pe rformed 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 opera tion of SCR, rather than the 0.05 lbs/MMBtu

emission rate.

Response: Our modeling of the visib ility impacts and benefits of the installation of SCR as being NOx BART are based on the determinati on of the emission limit technically feasible

and achievable at the SJGS. This determination is discussed in respons e 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 re garded as a perceptible ch ange 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 improve ment due to installati on of SCR is significant

and at a level that is certai nly perceptible, including a 3.11 dv improvement at Canyonlands and 2.88 dv at Mesa Verde and an improvement of 1 d eciview or greater at 7 other Class I areas. Installation of SCR will result in significant a nd perceptible visibility improvements at a number

of Class I areas.

Furthermore, in a situation where the installa tion of BART may not re sult in a perceptible improvement in visibility, the visi bility benefit may still be significant. “Failing to consider lessthan-perceptible contributions to visibility impa irment would ignore the CAA’s intent to have BART requirements apply to sources that contribu te to, as well as cause, such impairment” (70117 FR 128; RH Regulations and Guidelines fo r Best Available Retr ofit Technology (BART) Determinations, July 6, 2005). In stallation 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 de termination 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 reduc tions 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 Me xico to comply with its visibility-related obligation under section 110(a)(2 )(D)(i)(II). The commenter alle ges that EPA did not provide

information on the extent that SJGS’s emissi ons 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 th at those discrepancie s are “significant” based on “changes in visibility projections” a nd states that EPA faile d to provide modeling results quantifying the visibility impact associ ated with those emission “discrepancies.” The commenter states our “discrepancies” are not di fferences between SJGS’s projected emissions used in the WRAP modeling and an EPA-adjusted level of “curre nt” emissions. Rather, those emissions “discrepancies” are the differences between SJGS’s current levels of NOx and SO 2 emissions used in the WRAP modeling and their EP A-adjusted counterparts, i.e., current levels of those emissions adjusted to va lues that EPA believes should ha ve been used in the modeling. The commenter questioned how, if New Me xico’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 10-10 0 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 mu st 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 “discrep ancies” are significant cannot be evaluated until EPA identifies (1) the magnitudes of those disc repancies 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 satis fy 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 a nd 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 consider ing the consent decree reductions of 8,411 tpy since 2002. They then commented that if SJ GS’s current (Plan02d) 2002 NOx emissions are “adjusted” in accordance with EPA’s approac h, those required emission reductions to reach SJGS’s projected level used in the WRAP modeling would increase by an unknown quantity, but118 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 in terference. 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 emi ssion 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)(I I) requirements from the NOx emission reductions required to meet the NO x 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 sepa rately and no requirement that we perform a 110(a)(2)(D)(i)(II) visibility analysis. See Lega l response to comments, above, regarding our general authority and obligati on to act on section 110(a)(2)(D)(i )(II) and RH SIP requirements.

The commenter takes issue with the fact th at we did not specifically quantify the

difference in emissions between the WRAP mode ling 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 cons ultation, are not federally enfo rceable. 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 modeli ng 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 its elf 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 photochemi cal modeling that was performed to yield daily (24-hour) visibility im pairment impacts included future emission estimates based on

emission rates of 0.27 and 0.28 lb of NOx/MMBtu and 0.15 lb of SO 2 /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 in stalling 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/M MBtu on a short-term basis as reflected in PNM’s visibility impact modeling for SJ GS. 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 m odeling for SJGS. We find that New Mexico

201 Id

.119 sources, other than the SJGS, are sufficiently co ntrolled to eliminate interference with the visibility programs of other states because the federally enforceable emission limits for these

sources are consistent with those re lied upon in the WRAP modeling. The SO 2 and NOx emissions relied upon in the WRAP modeling for the SJGS, however, are not federally enforceable. Therefore, we are establishing fede rally enforceable emission limits for SO2 and

NOx for the SJGS to eliminate interference with th e 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 im pact we modeled using 0.33 lb/MMBtu NOx

and 0.15 lb/MMBtu SO 2 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 SO 2 in our initial modeling to compare model results with those presented by PN M and NMED. We note that reducing SO 2 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), de monstrating a limited sensitivity to changes in SO2 emissions compared to the large changes in visibility due to decreasing NOx emissi ons 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 SO 2 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 sensiti vity 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 chemis try is not strictly linear in this case, if modeled, the combined differen ce 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 emi ssion rate levels included in the WRAP modeling.

The commenter claims that the SJGS total em issions 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 sma ll in comparison to the total State emissions and

therefore should not be si ngled out for control. The commenter fails to consider the proximity of

SJGS to Class I areas and the fact that its emissi ons 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 ar e close to a Class I area and have elevated stacks result in greater plume impa ct on the Class I area, and will have a greater impact on visibility impairment per ton of NO x, 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 stat e and nearer to the metropolitan areas of Albuquerque and Santa Fe and over 200 kms from Cla ss I areas in other states, in comparison to the SJGS which is just 42 km from the Mesa Ve rde 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 disa gree with the comments th at we have unfairly adjusted the emission calculations to overstate the benefit of our proposal. We have conducted

our calculations consistent w ith EPA methods and guidance, and the WRAP EGU modeling projections. 202 As documented in our TSD, we used th e 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 unfairl y adjusted the emissions to what we thought they should be.

Comment: We received comments from the NPS a nd USFS supporting the reporting of the cumulative visibility impact of SJGS and th e cumulative benefits of SCR. NPS and USFS believe it is appropriate to consid er both the degree of visibility improvement in a given Class I area as well as the cumulative effects of improvi ng visibility across all of the Class I areas affected. The BART guidelines do not consider th e geographic extent of visibility impairment. NPS and USFS believe the most prac tical 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 pr oposals for the Navajo Generating Station and the Four Corners Power Plant. They also note th at the improvements in visibility impairment

due to reductions in NOx emissions in other anal yses have been largest at Class I areas other than the closest Class I area, th erefore evaluation of a ll Class I areas within the modeling domain is appropriate.

Several commenters were opposed to the us e of a “cumulative deciviews” or “total” visibility improvement metric. These commenters claim that the ”cumulative deciviews” metric is misleading and that the modeli ng 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 obser ved by one viewer. They continued that one viewer would not perceive visibi lity impacts in more than one Class I area simultaneously, or even within relatively short periods of time, in n early every case. Furthermore, the visibility impacts to a region should not depend on the numb er of Class I areas present. The commenters state it is improper to consider a "cumulative" de ciview 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 othe r nearby Class I areas to determine where the impacts are greatest. Modeli ng 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 impact s at the most impacted area, not all areas. The

commenters add that states have already successfully dealt with th is 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 WR AP 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 Gribovicz121 approach to deciviews, even though comment ers 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 ot her visibility metrics we utilized and we do not agree that our approach is inc onsistent 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 th e 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 be nefits 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 mode led effects are observed at the nearest Class I area, you may choose not to analyze the other Cla ss 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 paragra phs 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 c onsider the frequency, magnitude, and duration components of impairment,” emphasizing the flexib ility in method and metrics that exists in assessing the net visi bility improvement.

As discussed in a separate response to comment, for any CALPUFF visibility modeling in a SIP, a protocol addressing procedures a nd analyses should be determined with the appropriate reviewing authority a nd affected FLMs. As identifie d 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 CALP UFF modeling in this action, and concluded, like PNM and NMED previously concluded in their 2009 modeli ng, 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 conducte d 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 s upport the conclusion that further analyses were warranted. In this specifi c case, our analysis indicated th e largest baseline impact was at the closest Class I area (Mesa Verde) but also indi cated very large impacts at other Class I areas. In fact, we found that th e 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 greate r are considered to cause a visibility impairment122 Therefore, had we stopped our analysis after modeling the visibility improvement at Mesa Verde, we would not have discovered that the la rgest visibility improve ment 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 ac ross all affected Class I areas a nd the BART guidelines provide the flexibility to do so. One approach as noted above is to qualitatively co nsider, 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 ar eas, and in no way exclude such analyses, as the commenter suggest s. We concluded that a quantitative analysis of visibility impacts and benefits at only the Mesa Verde ar ea would not be sufficient to fully assess the impacts of controlling NOx emissions from the SJGS.

Again, nothing in the RHR suggests that a stat e (or EPA in issuing a FIP) should ignore the full extent of the visibility impacts and im provements from BART controls at multiple Class I areas. Given that the national goa l of the program is to improve vi sibility 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 prev iously, NMED and PNM’s BART analyses also presented visibility impact and improvement projec tions 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 methodol ogy 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 (Meth od 6). The commenter further al leges that our use of Method 8 resulted in much higher visibility impacts a nd improvements than would have been predicted using Method 6. The commenter also claims that our NOx BART modeling an alysis is internally inconsistent because we rely on Method 6 for SO 2 (using the WRAP modeling) and on Method 8 modeling for NOx. Furthermore, the commenters a ssert 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 refe r 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 estim ating 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 the123 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 em issions of NOx. We believe that this, however, more accurately reflects r eal visibility conditions.

We are also aware that at the time the Stat es were working together in the WRAP to develop their RH SIPs, Method 6 was widely em ployed to develop RPGs and for initial BART analyses. By the time Method 8 was widely av ailable, some States were far enough along in their SIP development that a switch to the newe r method would have been disruptive. Because of this, we did not object to the use of Me thod 6 in the WRAP photochemical modeling or subject-to-BART screening modelin g. 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 conclusi on using either Method 6 or Method 8 in our modeling. New Mexico and the other WRAP Stat es 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 im provement, the choice of IMPROVE Method is not relevant. The commenter seems to imply that because the WR AP 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 equa tion is used, New Mexico did not provide federally enforceable limitations on SJGS’ SO 2 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 conclude d that it is appropriate to address the requirements for NOx BART for SJGS at the sa me 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 visibi lity impacts using this peer reviewed algorithm. We also evaluated modeling result s using Method 6 to quantify the sensitivity of our results to the choice in visi bility impairment algorithm. We note that using

205 Revised IMPROVE algorithm for Estimating Light Ex tinction from Particle Speciation Data, IMPROVE, January 2006 (http://vista.cira.colostate.edu/improve/P ublications/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/G rayLit/016_IMPROVEEeqRevie w/IMPROVEeqReview.htm)

206 U.S. EPA. Additional Regional Haze Questions. U.S. Environmental Pr otections 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 Cond itions 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 Pa rk 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 Me thod 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 CALP OST 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 th e following response to comment, the ultimate decision on the acceptable model version, formul ation, and set-up of CALPUFF and CALPOST for visibility modeling is our responsibility in a FIP situation.

Comment: We received a number of comments c oncerning the version of the CALPUFF modeling system EPA has used. We utilized CALPUFF Version 5.8 suite for visibility modeling. The commenter i ndicated revised CALPUFF m odel 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 inst ead of ours. A number of commenters stated

that Version 5.8 is outdated and overestimates visi bility impacts. The co mmenters argue that the latest version, CALPUFF Version 6.4, whic h includes updated chemistry and technical enhancements to improve the model’s performa nce and accuracy, should be used to evaluate visibility impacts. They alleged that this vers ion includes updated chemis try that is more robust and performs better and technical enhancemen ts 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), No rth Carolina along with representatives of the western states utility organization WEST Associ ates, 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 m eeting that the FLMs will

take the lead on a review and testing of the CALPU FF model code changes including the new chemistry modules, and Model Change Bulle tins (MCBs) and coor dinate with EPA.

Response : The commenter indicated that a revised version of the model is available and submitted modeling analyses using CALPUF F 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 chemis try and technical enhanc ements 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. Th e newer version(s) of

CALPUFF have not received the le vel of review required for use in regulatory acti ons 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 Pa rk 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 deci sion making process. Based on our review of

the available evidence we do not consider the mo dels to have been shown to be sufficiently documented, technically valid, and reliable for us e in a BART decision making process. In addition, the available evidence would not s upport 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 addi tional chemical mechanisms that have not gone through the public review process required for a pproval 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 we re 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-guidelin e 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 re sults of past PNM, NMED and EPA modeling. These discrepancies are large enough to lend further credence to th e 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 CA LPUFF model version updates has been a lengthy process due to lack of document ation and finding additional technica l issues that had to be fixed before an update could be a pproved. EPA was fully justified in following its modeling approach,

which was consistent with current EPA and FL M guidelines, as well as similar to modeling recently performed by NMED and PNM. EPA us ed the approved version of the model in accordance with the appropriate procedures, as di scussed 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 us e the latest version of CALPUFF (6.4) or an earlier version 6.112, we consider ed the regulatory status of CA LPUFF for visibility analyses and what analyses are needed to utili ze 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 concer n with CALPUFF’s treatment of chemical transformations, which affect AQRVs, EPA ha s not approved the chemistry of CALPUFF’s model as a ‘preferred’ model. The use of the re gulatory version is approved for increment and NAAQS analysis of primary pollutants only. Cu rrently CALPUFF Version 5.8, is subject to the requirements of GAQM 3.0(b) and as a screen ing 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 concer ns 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/r eports/calpuff_vistas_assessment_report_final.pdf);126 Under the BART guidelines, CALPUFF s hould be used as screening tool and appropriate consultation with th e reviewing authority is require d 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 obt ain approval through consultation w ith 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 Goal s for Ozone, PM2.5, and Regional Haze (EPA-454/B-07-002), that Appendix W doe s not identify a pa rticular modeling system as ‘preferred’ for modeling conducted in support of state implementation plans under 40 CFR 51.308(b). A model should meet several gene ral criteria for it to be a candidate for consideration. These ge neral criteria are cons istent with the require ments of 40 CFR 51.112 and 40 CFR 51, Appendix W. Therefore, it is correct to interpret that no mode l system is considered ‘preferred’ under 40 CFR 51, Appendix W, Sect ion 3.1.1 (b) for either secondary particulate matter or for visibility assessments. Under th is 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 ch emistry. 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 result s provided by the commenter indicate much lower results compared to the current regulatorly approved version of th e 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. Th e information provided indicates the new science includes chemistry for which this model was neve r approved so these ch anges would necessitate a notice and comment rulemaking and not a simply update as previously d one for this model to address bug-fixes and the like. We believe that wi th 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 woul d 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 m odel versions could not be approved because the information provided is not sufficient and does not comport with the requirements of Section 3.2, incl uding 3.2.2(b)(3) and (e), of GAQM . The model developer has relied upon several articles (Esc offier-Czaja and Scire, 2007; a nd Scire, et al., 2003) which describe the general reliability of the CA LPUFF 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 conferen ces, and therefore do not reflect the thoroughness of a for mal peer review process that would be associated with submission to mainline scientific journals. Therefore, we do not consider th ese references suitable for estab lishing the validity of the model127 or post-processing techniques or demonstrating that these models have undergone independent scientific peer review as nece ssary for reviewing models in ac cordance 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 di stances beyond 50-km to 200- to 300-km. CALPUFF usage, in the context of the Southweste rn Wyoming Air Quality Task Force (SWWYTAF) modeling data set presented in both Escoffier-Czaja and Scire (2007) and Scire et al. (2003), is treate d as a full photochemical modeling system such as the Comprehensive Air Quality Model with Extensio ns (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 chemis try models. Recommended methods and metrics for evaluation of photochemical models are discu ssed 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). Ther efore, we do not consider the analysis techniques presented by the model developer suffi cient 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 fo r review, no protocol or other complete documentation was provided outlining the methods and procedures of operating the alternative model in agreement with the appropriate revi ewing authority (EPA Region 6) prior to submission of comments, contrary to re quirements of Section 3.2.2(e)(v) of GAQM.

Therefore, on the basis of available inform ation 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, a nd was based on established and well-recognized

methods.

It would be problematic for us to allow th e use of any unapproved model variants with potentially significant changes to chemistry treatment without additional information regarding the model’s formulation, performance, and accep tability. In promulgati ng the BART guidelines

we made the decision in the final BART Guide line to recommend that the model be used to

estimate the 98 th percentile visibility impairment rather than the highest daily impact value as proposed. We made the decision to consider the less conservative 98 th percentile primarily because the chemistry modules in the CALPU FF 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 less128 conservative 98 th percentile. 211 The modeling that PNM’s c ontractor performed for PNM was based on CALPUFF versions that have been upda ted with an allegedly more robust chemistry and purportedly performs better according to the commenter than the current ve rsion of the model approved for regulatory act ions (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 (1 st High instead of the 8 th High) based on the pres umption that the updated chemistry of CALPUFF model would result in less conservative resu lts than Version 5.8. In past agreements in using the CAMx photochemical mode l, which has a robust chemistry module, the Region has recommended the use of the 1 st High value when sources we re 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 sy stem 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 c onsidered a screening model for visibility assessments. Therefore, we followed the requir ements of Appendix W fo r screening models in our modeling. 213 We conducted our modeling with the ve rsion 5.8 suite with a few exceptions that were discussed among modeling expert s from EPA Region 6, EPA/ OAQPS and FLM representatives. Our modeling procedures we re discussed more fully in our TSD.

We note that the CALPUFF Versions 6.4 a nd 6.112 have not been reviewed by EPA for potential regulatory use. PN M’s contractor has indicated th at a meeting was held with EPA/OAQPS representatives on Feb. 16, 2011 a nd FLM representatives participated via conference call. The commenter indicates that EPA was going to let the FLM representatives

take the lead on review and test ing of the new version of CALPUFF (6.4) and coordinate with EPA regarding this issue. Mr. Tyler Fox, Gr oup 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 chemistr y in CALPUFF and require s additional rule making and public review since CALPU FF 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, PM 2.5 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 re viewing all available models to determine their suitability for these analyses. We note that we have reviewed th e 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 TC EQ 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 su itability for use in various contexts.

Based on the applicable GAQM and BART Guidelines re gulations, the combination GAQM (2005) citations (6.2.1(e) and 3.0(b)), and the BART Guid elines outline that for any visibility modeling performed with the CALP UFF 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 mode l 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 O ffice has the final approv al 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 ta sk and could take 6 months to a year or longer to complete a protocol that detailed submission of informa tion for review including model sensitivity runs, evaluation of model performance, etc., so this ca n be a sizable hurdle in order for EPA to ensure that we are basing decisions on sound science and the best to ols for actions. Approval of updated CALPUFF versions has been such a large task that EPA/OAQPS ha s 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 elem ents 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 modeli ng 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 info rmation 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 woul d have to reconsider whether using the 98 th 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 ma king. We believe we have made the appropriate choice in using CALPUFF version 5.8.

In support of the discussion above concerni ng the regulations that apply when using CALPUFF, we have also include d a detailed overview of the re gulatory 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 issu ed a rule establishing the dispersion model, CALPUFF, as the preferred technique fo r assessing the long range transport of primary pollutants, including for assessi ng impacts on Class I increments Fe deral Class I areas. See 40 CFR Part 51 Appendix W, Guideline on Air Qu ality Models (GAQM). In this 2003 GAQM rulemaking, we approved CALPUFF for PSD Ambient Air Standard analyses of ambient air concentrations and increment consumption, and al so for complex wind situations (with case-bycase approval by the EPA Regional Office, s ubject to Secion 3.2.2.e), but not for AQRV analyses (i.e. visibility impacts). We de fined 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 subj ect to approval by the EPA Regional Office in accordance with Section 3.0 of the GAQM, includi ng Section 3.0(b). Because of concern in

CALPUFF’s treatment of chemi cal transformations, which aff ect AQRVs, we did not approve130 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 visibili ty 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 re gulatory 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 th e decision making process in determining if a full BART analyses is required and in estimating th e degree of visibility improvement that may reasonably be expected from controlling a si ngle source in order to inform the BART determination. In the BART Guidelines, we di d 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 re quired. 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 wh en assessment is needed of reasonably attributable haze impairment or atmospheric depo sition 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 procedur es 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 (inclu ding model version, inputs and parameters and processing, etc.) conducted fo r visibility (haze) impairment s 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 require d for a particular modeling technique or analytical procedure, we often refer to the ‘‘a ppropriate reviewing author ity’’. 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 ag encies are ‘‘representatives’’ of the respective regions. Even in these circumstances, the Regi onal Office retains the ultimate authority in decisions and approvals.

The combination of these GAQM (2003) citati ons (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 revi ewing 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 conductin g 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 representa tives 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 ma de this decision in response to comments we received expressi ng concern that the chemistry modules in the CALPUFF model

are less advanced and that use of the 1st Hi gh was conservative and the knowledge that CALPUFF’s simplified chemistry could lead to mode l 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 wa s appropriate to use the 98th percentile or 8th High value when modeling all days of the year in stead of the 1st High value, also described as the Highest Daily impact level for each year modeled.

In the context of the commenter’s assert ion 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 pur portedly performs bette r 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 ch emistry 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 th e CAMx photochemical model, which has a robust chemistry module, the Region has recommended th e 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 sp ace-dependent Gaussian puff model. CALPUFF treats primary pollutants and simula tes secondary pollutant formation using a parameterized, quasi-linear chemical conversi on mechanism. Pollutants treated include SO2, SO4 =, NOX (i.e., NO + NO2), HNO3, NO3-, NH 3, 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 th at are best described as quasi-linear chemical reactions. This additional language does not in dicate 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- Eligib le Sources in Texas”, December 2006.132 provides a more descriptive ch aracterization of the module for chemistry that had been incorporated in the approved version of CALPUF F since its initial limited promulgation in 2003. Some of the numbering of sections change d 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 wh en assessment is needed of reasonably attributable haze impairment or atmospheric de position 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 procedur es and analyses should be determined in consultation with the appropria te reviewing authority (parag raph 3.0(b)) and the affected FLM(s). 218

In summary, based on the applicable GAQM and BART Guidelin es regulations the combination GAQM (2005) citati ons (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 stat e has been delegated, the EPA Regional Office has the final approval decision on what constitutes appropriate/acceptable mode ling. In the specific situation of the BART FIP for the SJGS, EP A Region 6 is the revi ewing authority.

We note that the CALPUFF Versions 6.4 a nd 6.112 have not been reviewed by EPA for potential regulatory use. PN M’s contractor has indicated th at a meeting was held with EPA/OAQPS representatives on Feb. 16, 2011 a nd FLM representatives participated via conference call. The commenter indicates that EPA was going to let the FLM representatives

take the lead on review and test ing 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 re valuated to . Both Mr. Tim Allen, of US Fish and Wildlife, and Mr. Tyler Fox, of EPA RTP, have indicated that EP A will take the lead on the review of the new

version as EPA evaluates models to address curr ent modeling needs for models that can be used for analyses of secondary formation polluta nts for ozone, PM2.5 secondary, and regional haze/visibility impairment. At this time, EPA an d 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 CALPU FF, 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 fo r single source visibility analys es in GAQM. Therefore Section 3.2.2(b)(3) and (e) apply in this situation. Specifically, Sec tion 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. Th e Applicable CALPUFF section is in Appendix A to the GAQM in Section

A.4.133 An alternative model should be evaluated fr om both a theoretical and a performance perspective before it is selected for use. Ther e 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 applica tion, 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 appl icable 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 th e model have shown th at 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 in formation regarding a re view 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 th en conducted a detailed review including existing modeling databases to evalua te 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 p eer review” if each of the major components of the modeling system (i.e., air chemistry/deposi tion, meteorological and emissions models) has been described and tested, and the results have been documented and reviewed by one or more disinterested and independent qua lified parties. Even with su ch an independent review, EPA

would need to conduct an overall assessmen t in order to make a determination.

We note that EPA has reviewed and appr oved 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. Specif ically, we have conducte d rigorous analyses of CALPUFF modeling systems in acc ordance 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 conduc t a full review of a new model system suite can take a year or more if the upgrade is significant. The addi tion of a detailed chemistry would be considered significant. We would also have to address if the inclus ion of a more advanced chemistry negated the logic for using the 8th hi gh 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 c onstant 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 wi nter months to 1.0 ppb during the summer would

better reflect the seasonal varia tions in ammonia concentrations than would a constant, assumed134 ammonia concentration. PNM further argued th at the use of variable monthly ammonia

concentrations would still be conservative. Th erefore, PNM alleges, si nce a variable monthly ammonia scheme is more representative and cons ervative, 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 (ave raging about a factor of two) of the assumed

ammonia relative to observations.” PNM furthe r comments that our s upporting documentation

also states that “alternative le vels may be used if supported by data” and therefore we have no basis for criticizing the variable, monthly amm onia levels used in the modeling prepared by

PNM. PNM further comments that EPA’s deci sion 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 comm ents supporting the use of variable, monthly

ammonia concentrations. There ar e several factors to consider with selecting the appropriate ammonia background for estimating visibility im pacts, including the length and temporal resolution of the ammonia data collected, wh ether the ammonia data varies depending on location of collection in compar ison to proximity of SJGS plumes, the fluctuation of levels throughout the year, and the importance of plum e chemistry from the point of NOx and SO 2 emissions that react with emitted and background ammonia as the plumes transport to downwind receptors. We have examined the available amm onia 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 concen trations 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 determ ining visibility impacts from th e source due to the atmospheric chemical reactions that occur as the pollutants an d 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 rath er 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 r eaction 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 ex pected, the SJGS emissions react with ammonia levels near the SJGS resulting in decreasing am bient ammonia levels dow nwind from the SJGS. The Substation and Farmington airport sites, whic h 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 th e 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 ammoni a concentrations in the Fo ur 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 tw o 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 Ve rde 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 ou r decision to use a constant 1.0 ppb ammonia value as being representative of the area around the source rather th an 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 th at the ammonia levels we used in the model are appropriate.

We disagree with the use of the AL M. There is a lack of documentation, adequate technical justification, and validation for the de velopment and use of the ALM. This is discussed further in a separa te 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 th e 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 cons istent with the WRAP modeling, EPA should not need to alter PNM’s modeling Moreover, the modeling result s 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 accu rate and realistic predic tion of the visibility improvements that might result from installing SCRs at SJGS. The recommendations included modeling results from the use of (1) two upda ted 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 concen trations 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 techniqu es, PNM argues that these alternate modeling results show that the greatest vi sibility 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 cons istent with WRAP protocols for assessing the visibility impacts of SJGS. In this instance, the commenter appears to confuse two types of136 modeling. As we discuss elsewhere in this no tice, 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 CALP UFF 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 th at 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 esta blish the reasonable progress goals for the WRAP States. The source-specific CA LPUFF 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. Ou r CALPUFF visibility mo deling, performed using an accepted CALPUFF model version and fo llowing applicable guidance and EPA/FLM recommendations, showed significant visibility benefits due to th e 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 ra ise 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 be tween PNM’s CALPUFF modeling protocol and the EPA approved modeling techniques for s ource-specific modeling to support a BART

determination. As stated in the TSD that a ccompanied our proposal, however, we agree with

commenter that the PNM CALPU FF modeling generally followed th e 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 CALPUF F 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 laye r could artificially collapse cr eating unrealistic meteorological conditions and significantly impacting the modele d dispersion (refer to the TSD for additional details). This assessment leads to EPA’s a pproval of CALPUFF 5.8 as the approved version, announced on June 29, 2007. Furthermore, PNM di d 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 m odel settings and incorporation of data. we

220 CALMET/CALPUFF Protocol for BART Exemption Sc reening Analysis for Class I Areas in the Western United States (August 15,2006; available at: http://pah.cert.ucr.edu/aqm/308/bart/WRA P_RMC_BART_Protoco l_Aug15_2006.pdf ...)

221 “CALPUFF: Status and Update” , Dennis Atkinson, Presentation at Regional/State/Local Modelers Workshop, May 16, 2007. ( http://www.cleanairinfo.com/regionalstatelocalmodelin gworkshop/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_f inal.pdf); “CALPUFF Regulatory Update”, Roger W. Brode, Presentation at Regional/State/Local Modelers Workshop, June 10-12, 2008,

available at (http://www.cleanairinfo.com/regionalstatelocalmodelin gworkshop/archive/2008/presentations/BRODE_CA.pdf ).137 specifically noted several deviations from appropriate practi ce in PNM’s implementation of the meteorological processing mode l 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 th e EPA/FLM guidance about including upper air observational data. Finally, the CALPUFF m odeling system (including CALMET) versions used by PNM did not follow EPA and FLM reco mmendations and guidance. NMED received comment on not being consistent with establis hed BART modeling proce dures 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 inconsis tent with the WRAP’s BA RT 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 alternat e model version were not considered by the

commenter. These deviations are discussed further in the Technical S upport Document that accompanied our proposal.

As discussed in section 4.3.1 and table 4-6 of the TSD, our sensit ivity modeling results support the conclusion that the differences betw een the WRAP BART screening protocol and our current regulatory approach would not likely change the original determination by the

WRAP and NMED of which source s screen out of BART and which are subject to a full BART analysis. We disagree, however, that PN M’s modeling was acceptable modeling for evaluating the visibility impacts to inform a BART determina tion. It would have been inappropriate for us to use a CALPUFF model version with known pr oblems/errors to support our proposed BART determination instead of using the CALPUFF version we approved for regulatory review. Therefore, our BART CALPUFF visibility modeli ng sought to correct the deficiencies in the PNM BART CALPUFF visibility mo deling. In addition, given that the emission rates that we proposed as NOx BART differed from those us ed in PNM and NMED’s BART visibility modeling, it was necessary to perform our CA LPUFF visibility modeling, following EPA/FLM guidance and practices, to assess the anticipated visibility impr ovements 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 NO x/MMBtu for SCR). As discussed in the TSD, we also had updated emission estimates for su lfuric 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 an alysis. We used the approved version of the model in accordance w ith the appropriate procedures, as discussed further in other response to comments and we are confident in using our resu lts 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 th at more recent vers ions of CALPUFF be used, as discussed in more detail in another resp onse, 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 improv ement to the current version that is acceptable for regulatory actions. PNM did not submit the m odeling files as part of its comments. Instead,138 the PNM submitted report only includes a summa ry of the modeling results. Therefore, sufficient evidence has not been presented to su pport 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 a nd because we have no basis to conclude that these versions provide reliable results, we did not conduct a fu ll 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 valu es than our modeling that was

conducted with CALPUFF Version 5.8.

We disagree with the use of a higher grid-r esolution (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 reso lution meteorological fields,

the memorandum discusses five issues that shoul d be addressed in considering use of a 1-km meteorological grid. None of these five elemen ts were addressed by the commenter. Among the

elements that should have been considered were a discussion of the natu re of SJGS’s sourcereceptor relationship to Class I areas in the m odeling domain and meteorological characteristics which govern these source-receptor relationships, a statistical performance analysis showing the inadequacy of the 4-km CALMET fields, demons tration of the technical adequacy of CALMET diagnostic algorithms in a complex terrain situat ion, statistical evaluati on demonstrating that 1- km CALMET fields perform better than 4-km fiel ds in this specific situ ation, 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 th e original Numerical Weather Prediction files, the CALMET meteorological model performan ce must be examined through appropriate statistical analysis to understand if the CALM ET diagnostic adjustments perform appropriately. The Report presented no eviden ce to support the claim that a 1-km resolution increases the accuracy of the final wind field in specifica lly modeling the SJGS. The commenter has not provided any statistical or other analyses to justify such a devi ation for modeling of the SJGS.

The commenter did not establish the nature of source-receptor relationships and meteorological

characteristics that are associat ed with it in support that a finer resolution is necessary or

beneficial. The commenter has no t 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 establ ished the relationship between grid resolution and chemistry conversion equations. Since CALPU FF 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 m odel 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 ar e 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 be tween 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 inform ation establishing the technical ad equacy of CALMET diagnostic algorithms to139 address technical concerns with complex terrain effects with a 1 km grid. Consistent with EPAFLM recommendations for CALMET and the WR AP BART screening modeling protocol, we determined that a 4-km grid resolution should be used.

We also disagree with the us e 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 l ack of documentation, adequate technical justification, and valid ation 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 gene ral terms, one of the key issues is ALM is a

method to have emissions from other sources co nsume ammonia, so there is less ammonia to

react with the source of intere st being modeled. Since ammo nia levels from the local area around the plant were used by EPA, to do calcu lations 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 mode ling simulations of the EPA Community Multiscale Air Quality Modeling System (CMAQ) for 2002. The Report’s summary shows that monthly averages of predicted conc entrations for ammonia, sulfate, nitrate, and nitric acid at a grid resolution of 36 km were used as model inputs to a pply the ALM. As discussed in a separate response to comments, available am monia 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 c oncentrations measured near th e SJGS which are of greater concern for determining visibility impacts fr om 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 emissi ons since this CMAQ simulation of “background” concentrations already includes SJGS emissions a nd reactions they have in the atmosphere. The background ammonia concentration that the co mmenter input into the non-approved CALPUFF model has already been decr eased 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 ammoni a levels in another response to comment. We note that variable am monia levels were not approved in the WRAP’s BART screening modeling protocol, nor in pr otocols 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, ra ther than the 0.05 lb/MMBtu that we included140 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. More over, as noted in the BART Guidelines, the

CALPUFF model results are useful for considering the comparativ e impacts of single sources on visibility impairment in a re lative sense and relative to ot her sources, SJGS’s impacts are significant. We note that the SJGS is one of the single larges t sources of NOx in the United

States and located close to 16 Cl ass I areas. As such, even wit hout 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 improveme nts at 16 Class I areas and indicates even greater visibility benefits at ot her Class I areas than Mesa Verd e. 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 cl aim 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, su ch results would be surprising. We conclude that our modeling which was performed us ing an accepted CALPUFF model version and following applicable guidance and EPA/FLM recomm endations 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 th e requisite statutor y authorization in this proceeding to implement its proposed emission limits for H 2 SO 4 and NH 3 emissions from

the SJGS. The commenter indicated that if EP A has not shown that limits on emissions of

H 2 SO 4 and NH 3 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 H 2 SO 4 or NH 3 emissions, EPA has no authority to regulate these pollu tants 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 shor t of demonstrating a visibility-impairment contribution that is necessary to authorize regulation of those co mpounds under Section 169A.

The commenter indicated that if EPA has no other policy r eason 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 th e withdrawn regional haze SIP proposal under section 308 both demonstrates the State’s intent to regulate regional haze during the first planning period with c ontrols only on emissions of SO 2 , NOx and PM. The commenter concluded that any proposal by EP A to limit emissions of either H 2 SO 4 or NH 3 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 uncl ear from EPA’s proposal if its action is being141 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 BA RT determination for the SJGS.

Response: For the reasons discusse d elsewhere in our response to comments, we have

determined that neither an ammonia limit nor a mmonia monitoring requirem ents are appropriate. The design plans for the SCRs that will be subm itted will address design and operation of SCRs based on a maximum ammonia slip level of 2 pp m. 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 H 2 SO 4 . 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 H 2 SO 4 to minimize/limit the amount of degradation in visibility due to any increases in th ese pollutants.

As we discussed in our proposal, we have c oncluded that the low su lfur coal burned at the SJGS generates very lit tle sulfur trioxide (SO 3 ), and hence H 2 SO 4 , which is formed when SO3 combines with water in the flue gas to form H 2 SO 4 . In addition, SCR catalysts are available

with a low SO 2 to SO 3 conversion of 0.5%, further limiting the production of H 2 SO 4

. Nevertheless, several modeling runs were conducted with different H 2 SO 4 emission levels and that modeling indicated that increases in H 2 SO 4 did result in some visibi lity degradation at Class

I areas in New Mexico and surroundi ng states. Some of the H 2 SO 4 runs we performed were not used in the final decision modeling analysis, but provided a basis for being concerned about potential H 2 SO 4 impacts and thus limiting the amount of growth in H 2 SO 4 from our action.

To address questions from NMED re garding the inherent removal of SO 3 by existing control equipment and removal by sorbent inje ction, 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 emi ssions are significantly less than those estimated by PNM, and support the conclusi on that sorbent injection is not required. Furthermore, PNM’s modeling deviated from EP A 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 Cla ss 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 indica te that visibility impacts at Mesa Verde decrease by 1.34 dv when their H 2 SO 4 emission estimates were reduced and all other emissions are kept constant.

Our modeling similarly show s that emissions of H 2 SO 4 can adversely impact visibility conditions. We performed visibility modeling with estimated su lfuric 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_Fin al_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, 2009142 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 mode ling was updated to reflect these changes. Comparison of these two modeling scenarios pr ovides further evidence of the impact of relatively small changes in sulfuric acid emissi ons on visibility. The original estimate for sulfuric acid emissions calculated by NPS totale d 17.84 lb/hr, and the revised estimate totaled

1.99 lb/hr for the 4 units. Even at these low em ission rates, a small in crease 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 H 2 SO 4 will not be a significant concern at the SJGS. However, modeling conducted by us a nd some modeling results provided by PNM’s

contractors indicate that vi sibility impairment could worsen if emissions of H 2 SO 4 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 H 2 SO 4 to a reasonable level verified by annual stack testing. We are controlling H 2 SO 4 under the BART provisions of the RHR and CAA Section 110. Our regulatory aut hority includes CAA section 169A(b)(2), 40 C.F.R. 51.308(e)(1)(ii) a nd 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 res ources to maintain low cost reliable energy supplies,

• expanding the region's reliance on lower carbon a nd water efficient sources of energy,

• increasing energy efficiency and power ge neration from renewable sources,

• decreasing coal-fired power generation, and

• greenhouse gas emissions.

Response: While these and other comments not re lated to the proposal may be important topics for discussion, we are not addr essing 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 Augu st 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.