IN REPLY REFER TO:

N3615 (2350)

July 24, 2013

Ms. Rita Bates

Planning Section Chief, Air Quality Bureau

New Mexico Environment Department

525 Camino de los Marquez, Suite 1

Santa Fe, NM 87505

Dear Rita:

Thank you for the opportunity to review and comment on the proposed State Alternative for Best 

Available Retrofit Technology for nitrogen oxide (NOx) emissions from San Juan Generating 

Station (SJGS). The State Alternative was developed through negotiation between New Mexico 

Environment Department (NMED), Public Service of New Mexico (PNM), and the 

Environmental Protection Agency (EPA) Region 6, after EPA disapproved New Mexico’s 

BART determination for SJGS and proposed a Federal Implementation Plan (FIP) with more 

stringent controls. 

PNM did not demonstrate that the State Alternative (Selective Non-Catalytic Reduction (SNCR)

on two units and shut down of two units) is better than EPA’s proposed BART determination 

(Selective Catalytic Reduction (SCR) on four units). PNM did not follow the BART guidelines 

to model maximum 24-hour emissions, so model results do not accurately estimate the visibility 

impacts. Actual 24-hour maximum NOx emissions should have been used for the baseline, and 

compared to the percentage emissions reductions for each control technology (23% for SNCR 

and 83% for SCR). 

The State Alternative needs to demonstrate greater visibility improvement than the EPA FIP 

proposal. We recommend that PNM and NMED evaluate the feasibility of further lowering the

emissions limits for NOx and/or SO2 to demonstrate that the State Alternative is better than the 

EPA FIP proposal. 

We also note that PNM overestimated the costs of SCR. We recalculated costs consistent with 

the BART guidelines and found that SCR costs are in the same range as accepted by other states

as BART. Our detailed comments are enclosed. 

United States Department of the Interior

NATIONAL PARK SERVICE

Air Resources Division

P.O. Box 25287

Denver, CO 80225-0287

1

National Park Service (NPS) Comments to New Mexico Environment Department (NMED) 

Regarding Best Available Retrofit Technology (BART) for the 

San Juan Generating Station (SJGS)

July 24, 2013

SJGS Source Description: 

SJGS is operated by the Public Service Company of New Mexico (PNM) and consists of four 

pulverized coal-fired generating units located near Farmington, NM. Coal for the units is 

supplied by the adjacent San Juan Mine and is delivered to the facility by conveyor. There are 16 

Class I areas within 300 km of the SJGS facility, nine of which are administered by the NPS. At 

40 km, Mesa Verde National Park is the closest Class I area. According to EPA’s Clean Air 

Markets (CAM) database, of 1,213 facilities in 2012, SJGS ranked #176 for sulfur dioxide (SO2) 

emissions (4,604 tons) and #9 for nitrogen oxides (NOX) emissions (15,975 tons).

The SJGS Boiler Units 1 and 2 have a unit capacity of 350 and 360 MW, respectively. The units 

are equipped with Foster Wheeler subcritical, wall-fired boilers that operate in a forced draft 

mode. The SJGS Boiler Units 3 and 4 each have a unit capacity of 544 MW and are equipped 

with B&W subcritical, opposed wall-fired boilers that operate in a forced draft mode. Because 

plant capacity exceeds 750 MW, presumptive BART applies to each unit (greater than 200 MW).

The table below shows how each unit’s 2012 CAM emissions ranked among the 3,495 Electric 

Generating Units (EGUs) in the CAM database. 

Unit 

ID

 SO2 

(tons) 

 SO2 

(tons) 

Rank 

 Avg. SO2 

Rate 

(lb/MMBtu) 

 Avg. NOx 

Rate 

(lb/MMBtu) 

 NOx 

(tons) 

 NOx 

(tons) 

Rank CO2 (tons) 

1 952 626 0.081 0.278 3,352 133 2,473,030

2 864 653 0.078 0.290 3,302 136 2,319,354

3 1,137 579 0.074 0.271 4,278 91 3,227,133

4 1,652 475 0.089 0.267 5,042 58 3,886,720

Consent Decree and Best Available Retrofit Technology (BART) proposals: 

On March 5, 2005, PNM entered into a consent decree with the Grand Canyon Trust, the Sierra 

Club, and the New Mexico Environment Department (NMED) to settle alleged violations of the 

Clean Air Act. The consent decree required PNM to meet a particulate average emission rate of 

0.015 lb/mmBtu, and a 0.30 lb/mmBtu emission rate for NOx (daily rolling, thirty-day average), 

for each of Units 1, 2, 3, and 4. As a result, PNM installed Low-NOX burners with overfire air 

ports and a neural network system to reduce NOX emissions, and pulse jet fabric filters to reduce 

the particulate emissions. The consent decree also required that the annual rolling average SO2

percentage reduction for SJGS Units 1, 2, 3, and 4 shall not be less than 90 percent for each unit.

The NM SIP dated July 5, 2011 determined BART for NOX for all four units as Selective NonCatalytic Reduction (SNCR). The EPA Federal Implementation Plan (FIP) dated August 22, 

2011 determined BART for NOx for all four units is the more stringent technology, Selective 
2

Catalytic Reduction (SCR). PNM, NMED, and EPA negotiated the current proposed alternative 

BART that would shut down units 2 and 3 and install SNCR on units 1& 4. 

BART Analysis for Current Proposal

We agree with NMED that SNCR and SCR are feasible technologies and that the other 

technologies do not need to be evaluated further for SJGS (Steps 1 & 2). 

Step 3: Evaluate Control Effectiveness of Remaining Control Technologies

NMED assumed that SNCR could reduce emissions by 23% (to 0.23 lb/mmBtu) and SCR by 

83% (to 0.05 lb/mmBtu). However, we found seven wall- or tangentially-fired EGUs in EPA’s 

2012 CAM database operating at or below 0.04 lb/mmBtu (annual average). Three of these units 

(Morgantown #1 & #2, and W.A. Parish #7) were retrofit with SCR. (The other four units are 

new sources.) We believe that it is feasible for SJGS to achieve 0.04 lb/mmBtu on an annual 

average basis. This represents an 85% - 86% reduction in current NOX emissions, which is well 

within the capability of modern SCR. 

Step 4: Perform Impacts Analysis of Remaining Control Technologies

Black & Veatch (B&V) and Sargent & Lundy (S&L) prepared the design parameters and 

developed estimates of capital and annual costs for applications of SCR and SNCR. PNM 

evaluated the energy impacts, non-air quality environmental impacts, and remaining useful life 

of all additional technically feasible control options for NOX. The 2013 analysis for 4 SCR, 4 

SNCR and 2 SNCR/2 Shutdown used a remaining useful life of 30 years. The table below is a 

slightly-modified1version of NMED’s Table 10 that focuses on SNCR and SCR compared to the 

baseline set by the 2005 Consent Decree.

Table 10: Impact Analysis and Cost Effectiveness of Additional NOx Control Technologies 

Control 

Technology 

Emission 

Performance Expected 

Emission 

Rate (tpy) 

Expected 

Emission 

Reduction 

(tpy) 

Total 

Capital 

Investment 

(TCI) 

(1,000$) 

Total 

Capital 

Investment 

($/kW)

Total 

Annualized 

Cost Cost 

Effectiveness 

($/ton) 

Incremental 

Cost 

Effectiveness 

($/ton) 

Level 

(lb/MMBtu) 

(TAC) 

(1,000$) 

Unit 1 350 kW

Consent Decree 0.30 4,140

SNCR 0.23 3,174 966 17,392 50 5,400 5,590 $ 6,749 

SCR + sorbent 

(FIP) 0.05 690 3,450 180,862 517 22,165 6,425

Unit 2 360 kW

Consent Decree 0.30 4,119

SNCR 0.23 3,158 961 17,392 48 5,400 5,618 $ 7,752 

SCR + sorbent 

(FIP) 0.05 687 3,433 203,360 565 24,562 7,157

Unit 3 544 kW

 

1 Table 10 was modified to eliminate all control technologies except those under consideration in this proposal. 

Energy and non-air impacts were also deleted. EGU ratings were added.
3

Consent Decree 0.30 6,431

SNCR 0.23 4,931 1,501 17,163 32 8,224 5,480 $ 6,314 

SCR + sorbent 

(FIP) 0.05 1,072 5,359 264,208 486 32,585 6,080

Unit 4 544 kW

Consent Decree 0.30 6,309

SNCR 0.23 4,837 1,472 17,163 32 8,224 5,587 $ 5,623 

SCR + sorbent 

(FIP) 0.05 1,052 5,257 235,940 434 29,508 5,613

In previous comments by EPA2and NPS, it was noted that unit costs ($434 - $565/kW) for SCR 

presented by PNM were far greater than industry and vendor3data support. In conducting our 

cost analysis for SCR, we used an approach similar to that reported by EPA Region 8 in its 

analysis of costs for the Colstrip Power Plant in MT:

We relied on a number of resources to assess the cost of compliance for the control technologies under 

consideration. In accordance with the BART Guidelines (70 FR 39166), and in order to maintain and 

improve consistency, in all cases we sought to align our cost methodologies with the EPA CCM.4 

However, to ensure that our methods also reflect the most recent cost levels seen in the marketplace, we 

also relied on a set of cost calculations developed by Sargent & Lundy for the Integrated Planning Model 

(IPM) version 4.10.5 These IPM cost calculations are based on databases of actual control project costs and 

account for project specifics such as coal type, boiler type, and reduction efficiency. The IPM cost 

calculations reflect the recent increase in costs in the five years preceding 2009 that is largely attributed to 

international competition. Finally, our costs were also informed by cost analyses submitted by the sources, 

including in some cases vendor data. 

We used EPA’s IPM model to estimate Direct Capital Cost (DCC) and applied the Control Cost 

manual (CCM) factors (totaling 141%) for Indirect Capital Cost to estimate a Total Capital 

Investment (TCI). We then used the CCM to estimate (Direct and Indirect) Annual Costs. All 

SCR costs are normalized to 2010.

Unit Unit 1 Unit 2 Unit 3 Unit 4

SCR Control Efficiency 86% 86% 85% 86%

Controlled emissions (lb/mmBtu) 0.04 0.04 0.04 0.04

Controlled Emissions (tpy) 484 455 635 751

Emissions Reduction (tpy) 2,942 2,826 3,716 4,473

Capital Cost $ 83,713,596 $ 76,263,695 $ 105,336,653 $ 108,838,111 

Capital Cost ($/kW) $ 239 $ 212 $ 194 $ 200 

O&M Cost $ 2,526,966 $ 2,336,481 $ 3,219,734 $ 3,529,493 

Annualized Cost $ 9,273,143 $ 8,482,298 $ 11,708,436 $ 12,300,365 

Cost-Effectiveness ($/ton) $ 3,152 $ 3,001 $ 3,151 $ 2,750 

 

2

Five industry studies conducted between 2002 and 2007 have reported the installed unit capital cost of SCRs to be 

$79/kW to $316/kW, where the upper end of the range is for very complex retrofits that are severely site

constrained.

3

“The SCR System cost would range from $100/Kw to $200Kw. This was based on a unit size from 750 to 

250MW.” Email dated 4/21/10 from Anthony C. Favale P.E., Director - SCR Products, Hitachi Power Systems 

America, to Anita lee, EPA Region 9.

4

EPA Control Cost Manual Sixth Edition, January 2002, EPA 452/B–02–001

5 Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, August 2010, EPA #430R10010
4

Even with the increased catalyst volume necessary to meet the lower annual NOX emission rate

for SCR, our $194 - $239/kW estimates of TCI still fall within the range of industry norms. Our 

annual costs are less than estimated by PNM, resulting in $/ton estimates that are less than half 

PNM estimates.

Step 5: Visibility Impacts Analysis of Remaining Control Technologies

On April 1, 2013, PNM submitted updated visibility modeling for SJGS with revised emission 

estimates for SO2, sulfuric acid (H2SO4), and total particulate matter (TPM). The modeling 

analysis compared available NOX control technologies including SCR and SNCR, as well as unit 

retirements as an alternative operating scenario that had not previously been analyzed. PNM’s 

updated BART modeling incorporated SJGS’s new SO2 and TPM emission limits of 0.15 

lb/mmBtu and 0.034 lb/mmBtu, respectively, including the EPA’s FIP scenario representing four 

SCRs, and the NMED’s 2011 SIP scenario representing four SNCRs. PNM also modeled SO2 at 

0.10 lb/mmBtu. PNM utilized the EPA-approved CALPUFF version 5.8, the CALMET data set 

originally created by EPA, and modeling input files as modified by EPA to reflect the sourcespecific parameters for the specific modeling scenarios. The modeled CALPUFF domain, 

receptors, ozone data, and CALMET data came directly from EPA. Additionally, the surface, 

upper air, and precipitation stations used to make the CALMET files were also directly delivered 

from the EPA. In the 2013 analysis, the hourly ozone concentrations files that came directly from 

EPA were used and the ozone concentration of 80 ppb was used for the missing hours in the 

ozone data files. A constant ammonia background concentration of 1.0 ppb was used. 

The NMED approved the use of all of the input parameters and data compiled by EPA for the 

updated modeling analysis. The condensable particulate matter (PM) emission rates used in the 

2013 modeling were based on the facility’s total particulate matter emission limit as established 

in the NSR permit effective August 31, 2012. PNM utilized the default ammonia background 

concentration of 1 ppb and the revised IMPROVE equation (Method 8) to calculate the 98th

percentile delta deciview (dv) from modeled pollutant concentrations. 

The meteorology used for the SJGS BART analysis followed EPA’s methodology described in 

the Technical Support Document and included with EPA’s proposed 2011 FIP. The modeling 

analysis was performed on a year-by-year basis (2001 – 2003) for the facility-wide impact for 

the four scenarios (Baseline, EPA FIP, NMED SIP, State Alternative). 

Ammonia slip was not considered in the modeling analysis. According to NMED, 

“[C]onsidering the 1 ppb ammonia background and the reductions in NOx, ammonia slip would 

have a negligible impact on visibility from any of the scenarios. EPA had determined in the FIP 

that ammonia slip would not significantly impact visibility improvement due to reductions in 

NOx and SO2 anticipated in the 4-SCR scenario.” This is misleading because the EPA statement6

was in regard to SCR ammonia slip—EPA never addressed ammonia slip from SNCR, which 

can be much higher than from SCR.

 

6 EPA TSD: “We are proposing NOx reductions that would likely be met with the installation of SCR and would 

have associated ammonia slip (ammonia that is not fully reacted and is emitted to atmosphere). The ammonia slip 

limit may be higher than 1 ppb, but we don‘t think it would significantly impact visibility improvements due to the 

reductions in NOx and SO2 at the SJGS units.”
5

CALPUFF Inputs –Baseline and Control Options 

Source release parameters and emissions for baseline and control options for each unit are shown 

in NMED’s Tables 16 through 19. The following notes apply to each of these tables:

(1) Emissions levels (lb/mmBtu) are shown on an annual average basis. 

(2) Emissions (lb/hr) calculations were based on the emissions level (lb/mmBtu) and design heat 

basis. 

(3) Emissions levels listed were based on performance guarantees provided by the equipment 

vendor. 

(4) The 2013 analysis utilizes the Electric Power Research Institute (EPRI) methodology to 

estimate H2SO4 emissions.

The 2013 analysis used the revised IMPROVE equation (Method 8) and the Annual Average 

Natural Conditions.

However, the emissions modeled do not follow the BART Guidelines. Instead of modeling the 

maximum 24-hour emission rates as required by the BART Guidelines7, the 2013 analysis relies 

upon annual/30 day rolling? (please clarify) average emissions, which do not properly reflect the 

variability in 24-hour emissions. To represent control technology, PNM should have used actual 

maximum 24-hr emissions modified by the percentage emissions reduction from Table 2, 

Appendix D (23% for SNCR and 83% for SCR). As would be expected, the baseline annual 

average SO2 and NOX emissions modeled in the 2013 analysis are consistently lower than the 

corresponding 24-hour maxima, as shown in the table below. (The “NMED” values are the 

modeled emission rates, while the “CAMD” values are the 24-hour maxima and the dates on 

which they occurred.)

Baseline Unit 1 Date 2 Date 3 Date 4 Date

NMED SO2 (lb/hr) 556.1 553.2 863.7 847.4

CAMD SO2 (lb/hr) 598.3 4/17/2010 598.1 6/22/2012 988.0 12/22/2012 1,360.7 8/1/2012

NMED NOx (lb/hr) 1,112.1 1,106.4 1,727.4 1,694.7 

CAMD NOx (lb/hr) 1,203.8 8/30/2012 1,105.2 7/25/2012 1,795.5 7/19/2012 1,893.1 6/3/2010

PNM also erred by assuming that future 24-hour maximum emissions would be the same as the 

longer-term emission limits. Even though no additional SO2 control measures are proposed, 

PNM has assumed that SO2 emissions will be reduced by one-third from the “baseline” 

condition. PNM appears to be lowering allowable emissions limit closer to the demonstrated 

actual emissions without changing operational conditions. Thus the emissions reduction that 

SJGS is taking credit for is not actually a reduction. This significant, but “paper” , reduction in 

SO2 emissions is likely to have played a major role in in NMED’s conclusion that the State 

Alternative is almost as good as BART. Without this paper SO2 reduction, it is likely that 

reductions from the State Alternative would be much less. Instead of modeling this “paper” SO2

 

7

Scenarios would be run for the pre-controlled and post-controlled emission rates for each of the BART control 

options under review. The maximum 24-hour emission rates would be modeled for a period of three or five years of 

meteorological data.
6

reduction, PNM should model future maximum 24-hour emission based upon application of 

expected improved control efficiencies to the actual baseline emissions from CAM data.

Discussions and Conclusions 

Because of the modeling errors discussed above, we cannot evaluate the State’s conclusion that:

The State Alternative Plan (2 SNCR/2 Shutdown) and the EPA FIP (4 SCR) achieve greater visibility 

improvement than projected for the NMED SIP scenario of 4 SNCR. The State Alternative Plan provides 

for nearly the same visibility improvement as the EPA FIP in improving visibility, with a difference of less 

than 0.5 dv at any one Class I area. The largest average differences in visibility improvement from the 4 

SCR (FIP) and 2 SNCR/2 Shutdown (State Alternative) scenarios are 0.28 dv at Mesa Verde National Park, 

and 0.16 dv at Canyonlands National Park.

Instead, NMED should address the modeling issues we have identified and present corrected

results and conclusions. (It would also be helpful in NMED would present its results in tabular

form, in addition to the chart format.)

2013 BART Determination 

NMED states that it “considered the terms of the non-binding agreement between the EPA, 

NMED and PNM, signed February 15, 2013 (the “State Alternative”), and the resulting 

significant environmental improvements of this alternative and compared this scenario to the 4 

SNCR and 4 SCR scenarios previously evaluated:”

The retirement of Units 2 and 3 will reduce the facility annual NOx emissions by an additional 10,550 tons. 

When added to the controlled emission rate of Units and 1 and 4, total annual NOx emission will be 

reduced by 12,989 tons. 

We are not clear on the bases for the statement above. 

Under this BART alternative, PNM is to conduct performance testing to determine if the SNCRs 

installed on Units 1 and 4 can achieve significantly less than 0.23 lb/mmBtu. Given that a similar 

optimization condition8is contained in the consent decree, please describe how that condition in 

that consent decree has been implemented.

NMED states that: 

 

8 No later than sixty (60) days after the first twelve (12) months of operation of the new NOX combustion control 

technology installed at each unit, PNM shall submit a report to Plaintiffs and the Department (a) identifying the 

daily average NOX emission rate for each unit for every operating day in the period and the thirty (30) day rolling 

average emission rate for every calendar day of the period, (b) describing the performance of the NOX control 

technology at each unit, and (c) evaluating the extent to which the 0.30 lb./mmBtu limit can be lowered at each unit 

based on the performance of each unit during the first twelve (12) months of operation of the new NOX combustion 

control technology. The report shall be reviewed pursuant to the procedure in Section IX (Approvals). Upon 

approval of Plaintiffs and the Department, the 0.30 lb./mmBtu limit shall be adjusted to a lower limit for the unit if 

the data gathered during the first twelve (12) months of operation indicate that a given unit is capable of meeting a 

lower limit, provided, however, that any final NOX limit for a given unit shall add a ten (10) percent margin of 

safety to the most representative thirty (30) day average emission rate achieved during the first twelve (12) months 

of operation.
7

The visibility improvements from the State Alternative of SNCR on two units and two units shutdown 

compare very closely with the SCR installation scenario as contained in the FIP...the degree of visibility 

improvement anticipated, the 2 SNCR/2 unit shutdown scenario is superior to the 4 SNCR scenario, and 

substantially equivalent to the 4 SCR scenario. 

Even if the visibility modeling results are accepted at face value, they do not demonstrate that the 

2 SNCR/2 unit shutdown alternative is “better-than-BART.” And, both the EPA FIP and the 

State Alternative continue to show more than a 2 dv impact at Mesa Verde NP, continued

visibility impairment at Canyonlands NP, and continued contributions to impairment at four 

more Class I areas.

NMED concludes that: 

The total capital investment of the FIP 4 SCR scenario is estimated at nearly $861,871,000, as compared to 

$34,556,000 for the installation of SNCR at Units 1 and 4. This additional and significant capital 

expenditure that would be required to comply with the FIP 4 SCR scenario is not justified given the slight 

and undetectable improvement in visibility of the FIP 4 SCR scenario over the State Alternative 2 SCR/2 

Shutdown scenario. 

We have shown that the total capital investment estimates cited by NMED for SCR are

overestimated (our $194 - $239/kW estimates versus $434 - $565/kW by PNM), and that the 

visibility modeling needs revision.

Conclusions 

 Cost estimates for SCR are significantly overestimated.

 The visibility modeling analysis was not done according to the BART Guidelines.

 The visibility modeling analysis does not demonstrate that the 2 SNCR/2 unit shutdown 

alternative is “better-than-BART.”

 Without additional SO2 or NOX reductions beyond those proposed in the State 

Alternative, the National Park Service does not agree that the State Alternative is better 

than the BART determination in EPA’s FIP. 

Recommendations

While addressing the problems noted above, NMED should also evaluate the possibility of 

reducing actual SO2 emissions and setting a limit on SO2 lower than the proposed 0.10 lb/mmBtu 

(30-day rolling average). For example, our review of CAM data shows that Unit #1 operated 

with 30-day rolling averages at or below 0.080 lb/mmBtu between 5/17/2010 and 3/26/2012. 

During 2010 – 2012, Unit #4 operated with 30-day rolling averages below 0.080 lb/mmBtu 52% 

of the time, and below 0.09 lb/mmBtu 77% of the time. So, it appears that the scrubbers have the 

capability to operate with lower than 0.10 lb/mmBtu SO2 emissions. It may be feasible to

improve operation and maintenance of the scrubbers on units #1 & #4 such that they can 

consistently meet a lower SO2 limit.