Testimony of Elizabeth Bisbey

- Kuehn Page 1 of 19 STATE OF NEW MEXICO BEFORE THE ENVIRONMENTAL IMPROVEMENT BOARD

IN THE MATTER OF PROPOSED REVISIONS TO THE STATE IMPLEMENTATION PLAN FOR THE SAN JUAN GENERATING STATION BEST AVAILABLE RETROFIT TECHNOLOGY DETERMINATION No. EIB 13

- 02(R)

_____________________________________________________________________________
NMED EXHIBIT 1 1

– WRITTEN TESTMONY OF ELIZABETH BISBEY

- KU EHN

______________________________________________________________________________

Statement of Witness Qualifications
Elizabeth Bisbey

- Kuehn is currently the Acting Technical Services Manager for the Air Quality Bureau of the New Mexico Environment Department (NMED) . She has served in the Bureau since February of 2005 as a Permit Specialist

– a role she continues to perform in addition to her managerial responsibilities. She also served as Acting Minor Source Section Manager from May through October of 2012. Ms. Bisbey

- Kuehn holds a Bachelor of Scien ce degree in Environmental Studies from the University of Iowa. Her resume is attached as Exhibit 1 1 a.

Testimony

B ackground

T he visibility provisions of the Clean Air Act (CAA) include a requirement that States 1

determine the Best Available Retrofit Tec hnology (BART) for certain large stationary sources
, 2
and require those sources to install and operate such technology as expeditiously as possible. 3

BART

- eligible sources are those sources which (1) have the potential to emit 250 tons 4
per year or more of a visibility impairing air pollutant; (2) were put in place between August 7, 5
1962 and August 7, 1977; and (3) whose operations fall within one or more of 26 specifically 6
listed source categories. 7Testimony of Elizabeth Bisbey

- Kuehn Page 2 of 19 For fossil

- fu e led generating power plants having a total g enerating capacity in excess of 1
750 megawatts (MW) , the Act requires that States determine BART pursuant to guidelines 2
developed by the E nvironmental Protection Agency (E PA ) . CAA § 169A(b)(2). EPA 3
promulgated such guidelines in 2005, and they are codifie d at Appendix Y to 40 CFR Part 51. 4
As described in more detail below, Appendix Y sets forth a 5

- step procedure for considering the 5
factors required by the CAA when making BART determinations. 6
In addition to providing guidance for BART determinations for g reater

- than

- 750 MW 7
power plants, the BART guidelines at Appendix Y also provide guidance on how to determine 8

which sources in a state are BART

- eligible, and which of those sources are subject to BART 9
requirements based on their visibility impacts. 10
Appendix D to New Mexico’s 2011 regional haze State Implementation Plan ( SIP )
, 11
submitted pursuant to 40 CFR § 51.309(g) , described New Mexico’s findings and determinations 12
with respect to BART
, which were made in accordance with Appendix Y

. Specifically
, 13
Appendix D contained a description of the process by which NMED analyzed the BART eligible 14
sources within the State and determined that only one such source , the San Juan Generating 15

Station (San Juan or SJGS)
, is subject to BART requirements. Appendix D also cont ained the 16
BART determinations for San Juan for particulate matter (PM) and nitrogen oxides (NOx). 17
(New Mexico’s BART obligations with respect to sulfur dioxide (SO 2 ) were satisfied by 18
implementation of a voluntary backstop SO 2 trading program pursuant to 40 CFR 51.309 (d)(4). ) 19
In this 2013 proposed SIP revision, Appendix D has been revised to include within the 20
BART analysis for San Juan a new scenario (the “State Alternative”) involving the voluntary 21

shutdow n of two of San Juan’s four units. This scenario , which was the result of negotiations 22Testimony of Elizabeth Bisbey

- Kuehn Page 3 of 19 between NMED, Public Service Company of New Mexico ( PNM ) , and EPA, is a new alternative 1
not previously considered by the Department. 2
Much of Appendix D as revised remains unchanged from the 2011 determination. The 3
sections that remain unchanged include the determination of sources eligible and subject to 4

BART ; the description of the SJGS ; the background of the BART regulation ; the history of 5
submissions made by PNM in response to NMED requests, with the exception of an addition of a 6
2013 update ; the 5

- step analysis and BART determination for PM ; and the conclusion of the 5

- 7
step analysis for NOx as of 2011. 8

The 5

- step analysis for NOx has been revised to include consideration of PNM’s revised 9
BART analysis in accordan ce with the State Alternative. This analysis included an updated cost 10
estimate for installing selective non

- catalytic reduction ( SNCR ) on Units 1 and 4 and installing 11
selective catalytic reduction ( SCR ) on Units 1 through 4. The cost estimates were based on 12
vendor quotes and represent the most current cost analyses by air pollution control equipment 13
vendors and engineering firms. The analysis also included updated emissions reduction 14

information that would result from the shutdown o f Units 2 and 3, and the continued operation of 15

Units 1 and 4 , and new visibility modeling to demonstrate the visibility improvements achieved 16
by the new scenario. 17

Determination of S ources “E ligible ” for and S ubject to BART 18
Certain large stati onary sources that are on a list of defined source categories in the 19

C AA lean Air Act
, which w ere not in operation prior to August 7, 1962, and were in existence on 20
August 7, 1977 , and that have the potential to emit over 250 tons per year of a defined visi bility 21
impairing pollutant are considered to be a BART eligible source. Visibility impairing pollutants 22

include
, but are not limited to
, N Ox , S O 2 , and P M

. 23Testimony of Elizabeth Bisbey

- Kuehn Page 4 of 19 In 2006, the Department reviewed all sources for BART eligibility using the criteria 1
required in Appendix Y. The Department first developed a list of all sources operating in New 2
Mexico under the Department’s regulatory jurisdiction. We then s creened the list for only those 3

sources that are on the defined list of source categories in the C AA lean Air Act . We then 4
reviewed the startup date and status of operation of the remaining sources. Finally, the 5
Department reviewed the potential to emit for those re maining sources that have the potential to 6
emit over 250 tons per year of any visibility impairing pollutant. New Mexico identified 11 7

sources as BART

- eligible sources as part of this review. 8

Once the Department determined which sources were BART eligib le, the Department 9

needed to determine which sources were subject to the BART rule requi rements. The BART 10

rule allows S tates to either make BART determinations for all BART

- eligible sources or 11
consider exempting some sources be cause they may not be reason ably anticipated to cause or 12

contribute to visibility impairment at any nearby Class I area. 13
The Department determined that it would perform an initial examination to identify 14

which BART

- eligible sources cause or contribu te to visibility impairment at subject Class I 15

area s

. The guidelines direct that S tates that choose this option need only perform a full BART 16
analysis for those sources show n to cause or contribute to visibility impairment at any of the 17
subject Class I area s

. 18
The first step to determine which sources cause or contribute to visibility impairment is to 19

establish a threshold in deciviews to measure the impact of a source’s operation. A deciv i ew 20

(dv) is a measurement of visibility impairment

. A single source that shows greater than 1 dv 21
impact is considered to cause visibility impairment and a source that shows less than 1 dv impact 22
may contribute to visibility impairment. States need to evaluate how many BART

- eligible 23Testimony of Elizabeth Bisbey

- Kuehn Page 5 of 19 sources impact any of the subject Class I ar ea s to determine an appropriate threshold . If there are 1
multiple sources impacting Class I areas, S tates may choose to establish a threshold less than or 2
equal to 0.5 dv. The rule states that the threshold to determine if a source contributes to visibili ty 3
impairment should not be larger than 0.5 dv. The Department reviewed the number of BART

4
eligible sources and the sources’ proximity to subject Class I areas. The Department concluded 5

that the BART eligible sources in the S tate were not concentrated in one region, and therefore 6
were not concentrating impacts at any one of the subject Class I area s . Based on this review, the 7
Department established a 0.5 dv thre shold for determining whether a BART

- eligible source 8
contributed to visibility impairment. 9

The next step was performing the visibility modeling of each BART

- eligible source’s 10

emissions to determine the lev el of impact the source had on any subject Class I area. The 11
Department worked with the Western Regional Air Partnership (WRAP) to perform the i nitial 12
BART modeling for the state of New Mexico. The WRAP modeled NOx, SO 2 and PM 13

emissions for the 11 BART eligible facilities using the CALPUFF model. Of the 11 source 14
complexes a nalyzed, only one source ’s visibility impact at any subject Class I area due to 15

combined SO 2 , NOx, and PM emissions exceeded the 0.5 dv threshold. This source was PNM 16
San Juan Generating Station, Boilers #1

- 4 (“SJGS”). The applicable Class I areas that were 17
evaluated in the BART process for SJGS are located within 300 km of the S JGS ; there are 16 18

Class I areas that meet this criteria. 19
On November 9, 2006, the Department informed PNM that the modeling performed by 20
the WRAP indicated the visibility impairment from the SJGS was over the 0.5 dv threshold, and 21

SJGS was therefore subject to a BART analysis. In response, Black & Veatch (B&V), on behalf 22

of PNM, submitted the BART m odeling p rotocol to the Department for review

. 23Testimony of Elizabeth Bisbey

- Kuehn Page 6 of 19 The modeling protocol describes the CALPU FF modeling methodologies and procedures 1

for the v isibility impact assessment that will be performed for the BART analysis. The protocol 2
contains all the meteorological and terrain data that will be used as well as the source specific 3

data for the SJGS . The protocol outlines where the receptors will be located at the subject Class 4
I areas to determine visibility impacts. The protocol was reviewed and the Department found 5
one area of concern regarding the use of average visibility improvement. PNM updated its 6
analysis and the Department determined that the protocol was approvable. 7

BART determination for PNM 8
Source Description 9

The SJGS consists of four coal

- fired generating units and associated support facilities. 10

Each coal

- fired unit burns pulverized coal and No. 2 diesel oil (for startup) in a boiler and 11
produces high

- pressure steam, which powers a steam turbine coupled with an electric generator. 12
Electric power produced by the units is supplied to the electric power grid for sale. Coal for the 13
units is supplied by the adjacent San Juan Mine and is delivered to the facility by conveyor. 14
The SJGS Boiler Units 1 and 2 have a unit capacity of 350 and 360 MW, respectively. 15
Units 3 and 4 each have a unit capacity of 544 MW. 16

Five

- Factor Analysis 17
The NOx and PM BART determinations for San Juan were pe rform ed in accordance with 18

the 5

- Step Process set forth in Appendix Y. In brief, the process is as follows: 19
Step 1

– Identify All Available Retrofit Control Technologies 20 Step 2

– Eliminate Technically Infeasible Options 21 Step 3

– Evaluate Control Effectiveness of Remaining Control Technologies 22 Step 4

– Evaluate Impacts and Document the Results 23 a) Costs of Compliance 24 b) Energy Impacts 25 c) Non

- air environmental impacts 26 d) Remaining useful life 27Testimony of Elizabeth Bisbey

- Kuehn Page 7 of 19 Step 5

– Evaluate Visibility Impacts 1 2 The NOx and PM BART determinations for San Juan involved numerous requests and 3
responses for more information from PNM, over a period of years (from June of 2006 through 4
May of 2013). Below is a description of how ea ch s tep in the 5

- step process was satisfied. 5
Step 1

– Identify All Available Retrofit Control Technologies 6
The main strategies for reducing NOx emissions take two forms: 1) modification to the 7
combustion process to control fuel and air mixing and reduce flame temperatures, and 2) post

8

combustion trea tment of the flue gas to remove NOx. Particulate matter emissions can only be 9
controlled by post

- combustion control technologies. 10

I n the original BART submittal, PNM identified fourteen separate available retrofit NOx 11
control technologies and four separa te available retrofit PM control technologies that have 12
potential application at the SJGS. The Department reviewed the list of NOx control technologies 13

and did not identify any additional alternative technologies that should have been considered in 14

the ana lysis. The Department reviewed the PM control technologies and requested that PNM 15
consider wet electrostatic precipitator (WESP) in Step 1 of the BART analysis. PNM 16
subsequently submitted a complete five factor analysis for this technolog y in a submittal dated 17
August 29 , 2008. 18
Please refer to Appendix D and the exhibits for the list of identified available retrofit 19
control technologies and a description of how each of the control s operates

. 20
Step 2

– Eliminate Technically Infeasible Options 21
Step 2 of the 5

- step process eliminates technology that is considered technically 22

infeasible . The basis for technical infeasibility is defined in the regulation and may be due to 23
limited application at sources similar to the BART

- subject source or to tech nology that is 24Testimony of Elizabeth Bisbey

- Kuehn Page 8 of 19 commercially unavailable. Other considerations for technical infeasibility include limitations 1

due to source

- specific design factors. 2
PNM initially proposed eliminat ion of SNCR, rotating opposed fire air ( ROFA ) , and 3

Rotamix technology bec ause the control technology would not achieve the presumptive NOx 4
emission limits prescribed in the BART rule. The Department did not agree that SNCR , ROFA, 5

or Rotamix should have been determined to be technically infeasible NOx control technology 6

and so reque sted PNM to perform a full five

- factor analysis for these technologies. 7
PNM submitted an updated Final SNCR analysis to the Department on May 30, 2008 and 8

a Final RO FA

- Rotamix analysis on August 29 , 2008. PNM also submitted an updated SNCR 9
analysis on February 9, 2011 and a n update to the analysis on February 11, 2011. This submittal 10

described and included new information on the lowest achievable emission rate for this 11
technology , and included a ratepayer impact analysis

. 12
The Department did agree that six types of NOx control technology should be considered 13
technically infeasible and agreed that those technologies should not be considered in the 14
remaining five

- factor analysis. Five of these technologies ha ve limited or no application at 15

sources similar to the SJGS and the sixth, natural gas reburn
, is infeasible due to limited boiler 16
space and resulting insufficient residence time in the natural gas reburn zone. 17

PNM eliminated all additional PM retrofit tec hnologies because either the controls would 18
not achieve better emissions reduction than the pulse jet fabric filters (PJFF) that were currently 19

installed at the SJGS , or there was limited application of the technology

. The Department 20

determined that two o f the remaining PM control technologies should be considered in the five

21
factor analysis and requested PNM to include the WESP technology and an enhanced pulse jet 22Testimony of Elizabeth Bisbey

- Kuehn Page 9 of 19 fabric filter ( PJFF ) installation in an updated submittal. An updated analysis of the two P M 1
control technologies was submitted on August 29 , 2008. 2
Step 3

– Evaluate Control Effectiveness of Remaining Control Technologies 3
Step 3 of the BART analysis includes a control effectiveness evaluation of the remaining 4

NOx and PM control technologies

. PNM contracted with B&V and Sargent & Lundy ( S&L ) to 5
determine the control effectiveness of each remaining available NOx and PM control technology 6

for Units 1

- 4. 7
The original analysis included only SCR and SNCR/SCR Hybrid NOx control 8
technology in Step 3. The control effectiveness evaluation for the remaining NOx and PM 9
technologies were submitted as updates to the Department in separate submittals. 10

The control effectiveness analyse s of SNCR , ROFA, and Rotamix was included in the 11

Final SNCR and Final Nalco

- Mobotec a n alyse s submitted May 30 and August 29 , 2008. The 12
control effectiveness analyses of PJFF and WESP te chnology was submitted August 29 , 2008. 13
PNM submitted in 2011 another updated control effectivenes s analysis for SNCR based 14
on a new manufacturer guaranteed emission rate of 0.23 lb/MMbtu. 15
The control effectiveness of the PM and NOx control technologies considered are 16
presented in Appendix D, Tables 2

- 9

. 17
Step 4

– Evaluate Impacts and Document the Res ults 18
The Guidelines require S tates to consider four types of impact analysis in Step 4 of the 19
BART analysis. These four types of impacts consider the costs of compliance, energy impacts, 20

non

- air quality environmental impacts, and remaining useful life of the facility. These impacts 21

are included in the cost

- effectiveness of each additional control technology and allow 22Testimony of Elizabeth Bisbey

- Kuehn Page 10 of 19 comparisons to be made between the remaining controls. B&V performed an impact analysis for 1
the remaining NOx and PM control technologies i n accordance with the Guidelines. 2
B&V and S&L prepared the design parameters and developed estimates of capital and 3

annual costs for the application of SCR, SNCR, SCR/SNCR Hybrid, ROFA, Rotamix, 4
ROFA/Rotamix, PJFF, and WESP technologies. B&V relied on a n umber of sources to prepare 5
the design parameters, including information from the Nalco Mobotec equipment vendors, SCR 6
and SNCR equipment vendors, EPA cost manuals, engineering and performance data, and 7

B&V’s own in

- house engineering estimates. 8

PNM evalu ated the energy impacts, non

- air quality environmental impacts, and 9
remaining useful life of all additional technically feasible control options for NOx and PM. 10
Energy impacts from control equipment that consume auxiliary power during operation were 11

consi dered for all control options. For SCR, SNCR and SCR/SNCR Hybrid technology, the non

12
air quality environmental impacts included the consideration of water usage and waste generated 13
from each control technology. For WESP technology, PNM considered the aux iliary power 14
consumption to operate the WESP and fans, and the additional water consumption and waste 15
water disposal requirements from operating the WESP. Lastly, the remaining useful life was 16
defined as 20 years, except for the 2013 analysis for 4 SCR, 4 SNCR and 2 SNCR/2 Shutdown
, 17
which used a remaining useful life of 30 years. Therefore, no additional cost adjustments for a 18
short remaining useful boiler life need to be considered. 19
The original submittal contained an impact analysis for only the SC R a nd SNCR/SCR 20
Hybrid technologies . The impact analyses for all remaining technologies were submitted as 21
separate updates to the Department. 22Testimony of Elizabeth Bisbey

- Kuehn Page 11 of 19 In the origi nal submittal, the cost estimates for SCR and the SNCR/SCR Hybrid 1
technology were based on engineering es timates prepared by B&V, without a detailed 2
explanation of the line items submitted in the estimate. PNM responded to a request for 3

additional information on July 11, 2007
, with updated cost estimates for both SCR and the 4
SNCR/SCR Hybrid technology. The update included additional details on the basis of 5
assumptions in the cost estimate. 6
On September 14, 2007 PNM submitted additional information to the Department in 7
response to a National Park Service l etter dated August 16, 2007 and a U.S. Forest Servic e l etter 8
dated August 23, 2007. In this update, PNM provided additional explanation of the cost estimate 9
development, and of the $/ton metric. 10
In a letter dated December 21, 2007, the Department requested PNM perform an updated 11
cost analysis for SCR based on the EPA’s Control Cost Manual. The Department requested this 12

information because we did not find that PNM provided fully sufficient just ification for using 13
engineering

- based cost estimates in lieu of the Control Cost Manual, which is the recommen ded 14
methodology to use when possible. 15
PNM responded with the Discussion of OAQPS Control Cost Manual submitted March 16
29, 2008. In their response, PNM discussed why the Control Cost Manual is not a sufficient 17
methodology for estimating the costs of air q uality control equipment, provided a scope of items 18
that are missing from the manual for SCR , and provided a comparison bet ween the estimated 19
costs based on the manual and the B&V estimate used in PNM’s cost analysis. 20
In a letter dated April 25, 2008, the Department requested PNM prepare and submit a full 21

five

- factor analysis for ROFA, Rotamix, and SNCR technology . The Department received the 22

full five

- factor analysis for SNCR technology on May 30, 2008, and the full 5 factor analysis for 23Testimony of Elizabeth Bisbey

- Kuehn Page 12 of 19 ROFA and Rotamix technology on August 28, 2008. Both of these updates contained an 1
updated engineering and impact analysis. 2
On December 29, 2009, the Department requested additional information regarding acid 3

mist emissions from PNM. Acid mist emissions result from t he conversion of SO 2 to SO 3 across 4
the SCR catalyst. The Department requested that PNM consider the inherent removal of SO 3 5
generated from SCR technology. The inherent removal is based on the existing air pollution 6

control devices and other process equip ment . In addition, the Department requested PNM to 7

consider the combined effect of SO 3 removal from existing technologies and with the installation 8

of sorbent injection control technology. Sorbent injection removes SO 3 in the flue gas by 9

reaction of the SO 3 with an alkaline sorbent material to form a particulate that can be removed by 10

the PM control device. 11
PNM submitted the requested update on March 16, 2009. This analysis considered SO 3 12
emissions removal both from existing equipment and sorbent injection technology, as requested 13
by the Department. The analysis quantified the SO 3 emissions and calculated the cost of the 14
sorbent injection system and included these costs into the cost esti mates of the SCR and 15
SNCR/SCR Hybrid technology. 16
On February 9, 2011, PNM submitted an updated engineering and impacts analysis based 17
on new information related to SNCR technology. The submittal included new cost estimates 18

based on 2010 dollars and a ne w manufacturer guaranteed NOx emission rate of 0.23 lb/MMbtu. 19
This slightly lower emission rate was a result of better emission control effectiveness for the 20
technology. The submittal also included an updated impact analysis and cost effectiveness 21

estima tes for SCR, SNCR/SCR Hybrid, ROFA/Rotamix, Rotamix (SNCR), SNCR (Fuel Tech) 22

and ROFA

. 23Testimony of Elizabeth Bisbey

- Kuehn Page 13 of 19 On February 11, 2011, PNM submitted an additional update that replaced the February 9, 1
2011 submittal. This new update included a unit

- specific level of information wi th respect to 2
visibility and cost effectiveness. PNM also submitted information regarding the updated rate 3
impact costs for SNCR and SCR plus sorbent injection to PNM customers based on PNM’s 4
ownership share of 46.3% of SJGS. 5
On April 1, 2013, PNM submi tted an updated impacts analysis based on new information 6
related to a voluntary shutdown of two units (Units 2 and 3). This update considers the impacts 7
analysis from three specific control scenarios at the SJGS; the installation of SCR on all four 8

units , the installation of SNCR on all four units, and the installation of SNCR on Units 1 and 4 9

and shutdown on U nits 2 and 3. 10

For the 2013 submittal, PNM contracted with (S&L) to develop a conceptual design, 11
project cost estimate, and technical portions of an Engineering, Procurement and Construction 12
specification for SCR control systems on SJGS Units 1

- 4. Site specific factors that had a 13
significant effect on the SCR design basis and costs include the site congestion at SJGS, NOx 14
emission reduction requireme nts, balanced draft conversion and the inclusion of a sorbent 15
injection system to meet sulfuric acid mist emission limits. 16
In the analysis S&L updated the cost analysis to reflect the approach described in the 17

EPA’s Control Cost Manual. The NMED reviewe d the cost analysis based on the methodology 18

in the Control Cost Manual and finds that the cost estimation methodology is acceptable to the 19

Department

. The cost estimates in the report provide an overview of the approach, the design 20
parameters, and the ba sis for the assumptions used to develop the costs estimates. The Control 21
Cost Manual does not allow the consideration of a number of specific types of cost, including 22Testimony of Elizabeth Bisbey

- Kuehn Page 14 of 19 owner’s costs and Allowance for Funds Used During Construction (AFUDC), and t hese costs 1
were specifically excluded from the cost estimates prepared by S&L. 2
Lower cost estimates for SCR installation have been provided for a four unit SCR 3
installation by the National Park Service ( NPS )

. T he Department does not necessarily agree with 4

the me thodology of the NPS cost analysis. Nonetheless, t he Department reviewed those 5

estimates and finds that this information would not impact the Department’s final 6
recommendation for BART at the SJGS. For example, the NPS estimates submitted to the 7

Departme nt indicate the total capital investment for SCR technology would be around 8
$374,152,055 for a four unit installation. However, the total capital investment e stimated for the 9

2 SNCR/2 Unit s hutdown scenario is only $34,556,000, making this proposal the most cost 10
effective proposal, especially considering the emissions reduction and visibility improvement 11
that would be achieved by this proposed alternative. 12
Step 5

– Evaluate Visibility Impacts 13

The Guideline s require S tates to assess vis i bility improvement based on the modeled 14
change in visibility impacts for the pre

- control and post

- control emission scenarios. This is Step 15

5 of the 5

- factor BART analysis. As noted previously, visibility impacts were review ed for 1 6 16
Class I areas located within 300 km of the SJGS. There were multiple updates to the original 17
visibility modeling analysis that was submitted to the Department

. 18
The first visibility analysis of additional control technology was submitted in the original 19
BART submittal. In the original submittal, only SCR and SCR/SNCR Hybrid technology was 20
reviewed as technically feasible additional control technology. The analysis was based on a 21
constant ammonia background concentration and nitrate repartition ing. Because PNM had 22
recently installed low NOx burners and overfire air (OFA) technology at the SJGS as the result 23Testimony of Elizabeth Bisbey

- Kuehn Page 15 of 19 of a consent decree, the analysis also considered the pre

- con sent decree and post

- consent dec ree 1
emissions to determine the visibility impr ovement achieved by the technology retrofit. 2

In an email dated June 30, 2007, t he NMED requested that PNM update their $/deciview 3
impact analysis to be based on the maximum visibility improvement, and not on average 4
visibility improvement as had been ori ginally submitted. On August 23, 2007, PNM submitted 5
the updated visibility cost

- effectiveness data to the Department. 6

On November 5, 2007, PNM submitted an additional refined BART modeling report to 7
the Department. PNM had investigated nitrate repartitioning and ammonia background 8

concentration refinements in the air dispersion modeling analysis and determined these 9
refinements more accurately predicted visibility modeling results. Nitrate re partitioning 10
eliminates impacts from overlapping puff s and the background ammonia concentration was 11
modified to assume monthly variable concentrations instead of a continuous 1 ppb background 12

amount. 13
In a letter dated December 21, 2007, the NMED requested additional modeling analyses 14
to determine plant

- wid e and individual unit specific visibility impact analysis. PNM submitted 15
the updated analysis on March 31, 2008. The report considered both plant

- wide and individual 16
unit specific impacts as well as both the refined and unrefined ammonia background and n itrate 17
repartitioning analysis. 18
On May 30, 2008, PNM submitted an additional modeling analysis to include SNCR 19
technology, which the NMED had determined should have been reviewed in the full 5

- factor 20
analysis. As in the March 31, 2008 update, PNM submitte d two reports, one including the 21
constant ammonia background with nitrate repartitioning and the other report with variable 22
ammonia background with the new nitrate repartitioning methodology. 23Testimony of Elizabeth Bisbey

- Kuehn Page 16 of 19 On August 29, 2008, PNM submitted an additional visibility mode ling analysis to include 1
Nalco Mobotec NOx control technologies. Specifically, the NMED requested modeling of 2
ROFA with Rotamix, Rotamix, and ROFA control technologies. Rotamix and ROFA are a 3
variant of SNCR and overfire technologies, respectively, and t he NMED determined these 4
technologies should have been evaluated in the full 5

- factor analysis. This report also contained 5
an update of the discussion of PM control technologies. A full visibility impact analysis of 6
WESP technology was submitted as part of this updated report. 7
On December 29, 2008, the NMED requested additional information regarding the acid 8

mist emissions from the SJGS and how these emissions impact the modeling analysis . To 9
comply with the NMED’s request
, PNM submitted an updated modeling analysis on March 16, 10

2009, that included consideration of the inherent removal of SO 3 emissions from existing control 11
technologies and consideration of the installation of a sorbent injection system control 12
technology th at would control acid gas emissions. 13
On February 9 and 11, 2011, PNM submitted a full new 5

- factor analysis of SNCR 14
technology after PNM received a lower vendor guaranteed emission rate from an equipment 15
vendor. For consistency, PNM assumed the monthly va riable ammonia concentration and the 16
nitrate repartitioning methodology based on the November 6, 2007 modeling refinements. 17

On A pril 1, 2013, PNM submitted new, updated modeling to reflect the voluntary 18
shutdown of Units 2 and 3, and a lower federally enfo rceable SO 2 emission rate of 0.10 19
lb/MMbtu at the remaining Units 1 and 4. In this modeling analysis, PNM relied on many of the 20
modeling assumptions used in the EPA’s modeling of the Federal Implementation Plan (FIP), 21
including constant ammonia background concentration, to allow for comparisons to be made 22
between modeling by both EPA and PNM. The three control technology scenarios modeled 23Testimony of Elizabeth Bisbey

- Kuehn Page 17 of 19 were the proposed S IP tate Implementation Plan (SNCR on Units 1

- 4), the FIP (SCR on Units 1

- 1

4) and a new State A lternat ive (SNCR on Units 1 and 4, shutdown Units 2 and 3). 2
The updated visibility analysis for the installation of SCR on all four units and SNCR on 3
all four units incorporated the SO 2 and total particulate matter (TPM) emission rates of 0.15 4

lb/MMBtu and 0.034 lb/MMBtu, respectively, from the current NSR Permit issued August 31, 5
2012. The updated visibility analysis for the installation of SNCR on Units 1 and 4 and a two

6
unit retirement incorporated the new TPM emission rate of 0.034 lb/MMBtu and an SO 2 7

emissio n rate of 0.10 lb/MMBtu. This new SO 2 emission rate will be incorporated into the 8
facility’s NSR p ermit as a federally

- enforceable permit condition should this scenario be 9

determined as BART for the source. 10
Conclusion of analysis (Determination of BART) 11

I n accordance with Section 169A(g)(7) of the C AA lean Air Act , the Department 12
considered the five statutory factors in the BART analysis for the SJGS: (1) the costs of 13
compliance; (2) energy and non

- air quality environmental impacts of compliance; (3) any 14
existing pollution control technology in use at the source; (4) the remaining useful life of the 15
source; and (5) the degree of improvement in visibility which may reasonably by anticipated to 16
result from the use of such technology. 17

PM BART Assessment 18

The D epartment’s BART determination for PM in Appendix D is unchanged from 2011, 19
and was approved by the EPA in November 2012. 77 FR 64,908 (Nov. 27, 2012)

. 20

2011 NOx BART Determination 21

Based on the five

- factor analysis, the Department determined in 2011 that, for the f acility 22
comprising Units 1, 2, 3, and 4, BART for NOx is SNCR technology at an emission rate of 0.23 23Testimony of Elizabeth Bisbey

- Kuehn Page 18 of 19 lb/MMBtu on a 30

- day rolling average. The Department’s determination of BART was based on 1

the resu lts of the five

- factor analysis. 2

2013 NOx BART Determination

. 3
The Department analyzed the scenario contained in the non

- binding agreement (Term 4

Sheet) between the EPA, NMED and PNM, signed February 15, 2013 (the “State Alternative”), 5
and the resulting significant environmental improvements of this alt ernative

. The Department 6
revised the BART analysis to compare this scenario to the 4 SNCR and 4 SCR scenarios 7
previously evaluated. The Department’s determination of BART was based on consideration of 8
the BART statutory factors in the context of the elem ents of the State Alternative (2 SNCR/2 9

Shutdown). 10

1) PNM will retire Units 2 and 3 by December 31, 2017. These retirements do not 11
give rise to control equipment costs requiring amortization. The remaining useful life of 12
the source is defined as 30 years for the three scenarios described (4 SCR, 4 SNCR, 2 13
SNCR/2 Shutdown). Therefore, the statutory factor of the remaining useful life of the 14
source does not weigh in favor of any option over another. 15

2) PNM will obtain the necessary construction permit modif ication to limit the SO 2 16
emission rates at Units 1 and 4 to 0.10 lb/MMBtu on a daily rolling 30

- day average basis. 17

These SO 2 emission reductions occur separately and apart from the SO 2 backstop trading 18
program that EPA has already approved as satisfying B ART. In addition to increased 19
visibility improvement, these SO 2 reductions will lead to non

- air quality environmental 20
benefits, such as decreased acid deposition. 21

3) The retirement of Units 2 and 3 will reduce the facility annual NOx emissions by 22

an addit ional 10,550 tons. When added to the controlled emission rate of Units 1 and 4, 23Testimony of Elizabeth Bisbey

- Kuehn Page 19 of 19 total annual NOx emission will be reduced by 12,989 tons. Additionally, PNM will 1
conduct performance testing to determine if the SNCRs installed on Units 1 and 4 can 2

achieve s ignificantly less than 0.23 lb/MMBtu. 3

4) The 2 SNCR/2 Shutdown scenario would result in less material usage than the 4 4

SCR and 4 SNCR scenarios. See Table 23 in Appendix D . This will result in less 5
limestone required to be transported and mined, less diesel fuel that would need to be 6
refined for this power plant, less coal mi ning and processing, and less carbon that would 7
need to be activated. Closure of two units will result in up to 53 percent less water used, 8

from 21,000 acre

- feet to 10,161 acre

- fee t; wastewater generated will be reduced by up to 9
50 percent, from 41 million gallons to 21 million gallons; and solid waste generated will 10
be reduced by up to 50 percent, from 1.71 million tons per year to 854,130 tons per year. 11
Based on this analysis, th e Department determined that BART for NOx at the SJGS is the 12
installation of SNCR technology on Units 1 and 4 , with performance testing , coupled with the 13

retirement of Units 2 and 3
, as outlined in the Term Sheet. 14