State of Utah 

GARY R. HERBERT

Governor

SPENCER J. COX

Lieutenant Governor

Department of 

Environmental Quality

Amanda Smith

Executive Director

DIVISION OF AIR QUALITY

Bryce C. Bird

Director

DAQ-086-14

M E M O R A N D U M

TO: Air Quality Board

THROUGH: Bryce C. Bird, Executive Secretary

FROM: Colleen Delaney, Environmental Scientist

DATE: September 16, 2014

SUBJECT: PROPOSE FOR PUBLIC COMMENT: Amend Utah SIP. Section XX.D.6. Regional 

Haze. Long-Term Strategy for Stationary Sources. Best Available Control Technology 

(BART) Assessment for NOx and PM. Add new Utah SIP Subsections IX.H.21 and 22. 

General Requirements: Control Measures for Area and Point Sources, Emission Limits and 

Operating Practices, Regional Haze Requirements; and Source Specific Emission 

Limitations: Regional Haze Requirements, Best Available Retrofit Technology. 

______________________________________________________________________________________ 

On December 14, 2012, EPA approved the majority of Utah’s Regional Haze SIP (RH SIP), but 

disapproved Utah’s best available retrofit technology (BART) determinations for nitrogen oxides (NOx)

and particulate matter (PM) for PacifiCorp’s Hunter Unit 1, Hunter Unit 2, Huntington Unit 1, and 

Huntington Unit 2 that were adopted by the Board in 2008. Utah’s BART determination met the 

presumptive BART emission rate for NOx that was established by rule in 40 CFR part 51 Appendix Y 

(BART Rule) and required the installation of fabric filter baghouses, the most stringent control technology 

available, for PM. The 2008 RH SIP contained a 5-factor BART analysis that relied on the extensive 

technical work that EPA had completed to establish the presumptive BART emission rates for coal-fired 

electric generating units (EGUs) in the BART rule. EPA disapproved Utah’s BART determination for 

NOx and PM because EPA did not agree that their own analysis satisfied the 5-factor analysis requirement. 

EPA, therefore, determined that the SIP did not contain a 5-factor analysis as required by the rule. 

In June 2012, PacifiCorp prepared a new 5-factor BART analysis to satisfy the requirements of the BART 

rule. PacifiCorp submitted an update to that analysis on August 5, 2014, to address issues that EPA had 

raised with other regional haze SIPs. DAQ staff’s detailed review of PacifiCorp’s 5-factor analysis is 

attached to this memo. After weighing the five factors, the following changes to the 2008 BART 

determination are recommended. 

195 North 1950 West • Salt Lake City, Utah 

Mailing Address: P.O. Box 144820 • Salt Lake City, Utah 84114-4820 

Telephone (801) 536-4000 • Fax (801) 536-4099 • T.D.D. (801) 536-4414 

www.deq.utah.gov

Printed on 100% recycled paper
DAQ-086-14

Page 2

Staff Recommendation: Staff recommends the Board retain the 2008 BART determination with the 

following changes: 

1. Correct the typographical error in Table 5 of the SIP to reflect the 0.015 lb/MMBtu PM limit in the 

approval orders for Hunter Units 1 and 2 and include the 74 lb/hr emission rate for Huntington 

Unit 1 and the 70 lb/hr emission rate for Huntington Unit 2.

2. Add an enforceable requirement to shut down Carbon Unit 1 and Carbon Unit 2 by April 15, 2015.

3. Add enforceable BART conditions to Part H of the SIP to address EPA’s determination that the 

approval orders and operating permits for PacifiCorp’s Hunter and Huntington plants are not 

practicably enforceable. 
Utah Division of Air Quality

Staff Review of 2008 Best Available Retrofit 

Technology (BART) Determination

September 12, 2014

Table of Contents

Introduction ..............................................................................................................................................1

BART Determination in 2008 RH SIP.........................................................................................................3

Partial Approval, Partial Disapproval of Utah’s Regional Haze SIP ...........................................................5

New 5-Factor Analysis...............................................................................................................................6

Analysis of Controls for SO2, NOx, and PM Established as BART in 2008.................................................6

Energy and Non-Air Quality Environmental Impacts............................................................................6

Remaining Useful Life ...........................................................................................................................6

Economic Impact...................................................................................................................................6

Visibility benefit ....................................................................................................................................6

Analysis of Particulate Matter Control Options......................................................................................19

Analysis of NOx Control Options.............................................................................................................20

Energy Impacts....................................................................................................................................20

Non-Air Quality Environmental Impacts.............................................................................................20

Remaining Useful Life .........................................................................................................................21

Economic Impact.................................................................................................................................22

Visibility Impact...................................................................................................................................25

Seasonal Differences...........................................................................................................................26

Other Considerations..............................................................................................................................27

Timing of Other Regulations...............................................................................................................27

2018 SIP Revision ................................................................................................................................28

Weighting of 5-Factors for PM BART Determination..............................................................................28

Weighting of 5-Factors for NOx BART Determination ............................................................................28

Staff Recommendation ...........................................................................................................................31

i
Tables

Table 1. BART Emission Rates in Utah's 2008 SIP ........................................................................................4

Table 2. Mercury Emission Trends...............................................................................................................5

Table 3. Modeled visibility benefit at Canyonlands due to 2008 BART determination...............................7

Table 4. NOx Emissions from the Oil and Gas Industry..............................................................................17

Table 5. NOx Control Options ....................................................................................................................20

Table 6. NOx Control Options Cost ............................................................................................................23

Table 7. Cost Range to Reflect Uncertainty Due to Proposed Clean Power Plan ......................................24

Table 8. Modeled Visibility Impact for Control Options ............................................................................25

Figures

Figure 1. Speciated Annual Average Light Extinction at Canyonlands.........................................................1

Figure 2. SO2 Milestones and Emission Trends............................................................................................2

Figure 3. Utah RH SIP Expected NOx Reductions 2002-2018.......................................................................2

Figure 4. Modeled number of days improved at Canyonlands due to 2008 BART determination..............8

Figure 5. SO2 Emission Trends .....................................................................................................................9

Figure 6. NOx Emission Trends.....................................................................................................................9

Figure 7. Deciview Trends on 20% Worst and 20% Best Visibility Days ....................................................10

Figure 8. Sulfate Trends .............................................................................................................................11

Figure 9. Nitrate Trends.............................................................................................................................12

Figure 10. Nitrate and Sulfate on High Nitrate Days..................................................................................13

Figure 11. Sulfate and Nitrate Trends in Winter and the Rest of the Year................................................14

Figure 12. Ammonia Trends.......................................................................................................................15

Figure 13. NOx Emission Trends from EGUs..............................................................................................17

Figure 14. Modeled days improved at Canyonlands..................................................................................26

Figure 15. Seasonal Variability of Ammonium Nitrate Impact and Visitation at Canyonlands .................27

ii
Introduction

Utah’s Regional Haze State Implementation Plan (RH SIP), originally adopted in 2003, was based on the 

Recommendations of the Grand Canyon Visibility Transport Commission (GCVTC). The GCVTC evaluated 

haze at Class I Areas on the Colorado Plateau, and determined that stationary source reductions should 

be focused on sulfur dioxide (SO2) because it is the pollutant that has the most significant impact on 

haze on the Colorado Plateau. Utah’s BART determination was developed within the context of the 

overall SIP and reflected this focus on SO2. Figure 1 shows the contributions of various species to 

visibility impairment at Canyonlands National Park. As can be seen, sulfate (ammSO4) is the most 

significant contributor to haze. Fire (OMC) and dust (CM) are also a significant components but the 

impact is variable from year to year. 

Figure 1. Speciated Annual Average Light Extinction at Canyonlands.

Utah’s 2003 RH SIP included SO2 emission milestones with a backstop regulatory trading program to 

ensure that SO2 emissions in the 3-state region of Utah, Wyoming, and New Mexico decreased 

substantially between 2003 and 2018. The milestones were adjusted in 2008 and 2011 to reflect 

changes in the number of states participating in the regional program. Actual SO2 emissions decreased 

by 55% between 2003 and 2012 in the current 3-state region, and in 2012 were significantly below the 

2018 milestone in Utah’s RH SIP (See Figure 2).

1
Figure 2. SO2 Milestones and Emission Trends

While Utah’s RH SIP is focused on achieving SO2 reductions from stationary sources, substantial 

reductions in nitrogen oxide (NOx) emissions will also occur. Figure 3 shows the projected decrease in 

NOx emissions between 2002 and 2018 as documented in Utah’s RH SIP.

Figure 3. Utah RH SIP Expected NOx Reductions 2002-2018.

2
BART Determination in 2008 RH SIP

On September 3, 2008, the Utah Air Quality Board adopted a revision to Utah’s RH SIP to include Best 

Available Retrofit Technology (BART) requirements for NOx and particulate matter (PM) as required by 

40 CFR 51.309(d)(4)(vii). PacifiCorp’s Hunter Unit 1, Hunter Unit 2, Huntington Unit 1, and Huntington 

Unit 2 fossil fuel fired electric generating units (EGUs) were determined to be subject to BART. The 2008 

RH SIP required PacifiCorp to install the following BART controls at these EGUs:

Hunter Units 1 and 2:

• Conversion of existing electrostatic precipitators to pulse jet fabric filter bag-houses

• The replacement of existing, first generation low-NOx burners with Alstom TSF 2000TM lowNOx firing system and installation of two elevations of separated overfire air.

• Upgrade of existing flue gas desulfurization system to > 90% sulfur dioxide removal.

Huntington Units 1 and 2:

• Conversion of existing electrostatic precipitators to pulse jet fabric filter bag-houses

• The replacement of existing, first generation low-NOx burners with Alstom TSF 2000TM low-NOx

firing system and installation of two elevations of separated overfire air.

• Installation of a new wet-lime, flue gas de-sulfurization system at Unit 2 (FGD).

• Upgrade of existing flue gas desulfurization system to > 90% sulfur dioxide removal at Unit 1.

The emission rates established in the RH SIP for Hunter Units 1 and 2 and Huntington Units 1 and 2 are 

more stringent than the presumptive BART emission rates for SO2 and NOx established in 40 CFR Part 51 

Appendix Y, Guidelines for BART Determinations under the Regional Haze Rule as shown in Table 1. 

(Note, Table 1 corrects a typographical error in Table 5 of the RH SIP where the permitted rate for PM 

was listed as 0.05 lb/MMBtu when it should have been 0.015 lb/MMBtu, the limit established in the 

approval orders for each of the units.) 

3
Table 1. BART Emission Rates in Utah's 2008 SIP

Units Utah Permitted Rates1 Presumptive BART Limits2

Rate: lb/MMBtu SO2 NOx PM SO2 NOx

Hunter 1 0.12 0.26 0.015 0.15 0.28

Hunter 2 0.12 0.26 0.015 0.15 0.28

Huntington 1 0.12 0.26 0.015 0.15 0.28

Huntington 2 0.12 0.26 0.015 0.15 0.28

The 2008 RH SIP relied on EPA’s presumptive BART emission rate for NOx as the appropriate benchmark

to determine whether the BART requirement had been met. EPA had completed extensive technical 

work for all EGUs in the country to develop presumptive limits for NOx, now codified in Appendix Y3

, and 

the Utah SIP referenced this technical work to meet the requirement to conduct a 5-factor BART analysis 

for NOx, as required by 40 CFR Part 51, Appendix Y. On December 20, 2010, the Division of Air Quality 

(DAQ) submitted to EPA a Supplement to the Technical Support Document for Utah’s 2008 Regional Haze 

SIP that described in detail how Utah used EPA’s extensive technical analysis to meet the requirements 

for a 5-factor analysis for NOx. The 2010 Supplement also described Utah’s determination that the 

baghouses required by Utah’s RH SIP were the most stringent control available for particulate matter.

The 2008 BART determination was influenced by a concurrent effort to reduce mercury emissions that 

was a priority for DAQ. A baghouse, in conjunction with wet or dry flue gas de-sulfurization, was needed

to meet the mercury emission rate of 6.5 x 10-7 lbs/MMBtu or 90% mercury control required by Utah’s 

rule R307-424, Permits: Mercury Requirements for Electric Generating Units. This rule was adopted in 

2007 and was designed to work in conjunction with EPA’s 2005 Clean Air Mercury Rule (CAMR) to 

reduce mercury emissions both nationally and locally. Mercury was a concern in Utah due to elevated 

1 Utah Division of Air Quality Approval Orders: Huntington Unit 2 - AN0238012-05, Huntington Unit 1 - DAQEAN0102380019-09 (note – on January 19, 2010 an administrative amendment was made to the 2009 AO), 

Hunter Units I and 2 - DAQE-AN0102370012-08. As described later in this review, the emission rate for 

Huntington is expressed as pounds per hour but was based on 0.015 lb/MMBtu. 

2 40 CFR Part 51 Appendix Y Guidelines for BART Determinations under the Regional Haze Rule (70 Federal Register 

39135)

3 40 CFR Part 51, Appx Y, Table 1, Presumptive NOx Emission Limits for BART-Eligible Coal-Fired Units, note 20, 

says:

These [presumptive NOx] limits reflect the design and technological assumptions discussed in the 

technical support document for NOx limits for these guidelines. See Technical Support Document for 

BART NOx Limits for Electric Generating Units and Technical Support Document for BART NOx Limits for 

Electric Generating Units Excel Spreadsheet, Memorandum to Docket OAR 2002–0076, April 15, 2005.

4

 
mercury levels measured in Utah fish and waterfowl. There are currently 24 waterbodies in Utah that 

have health advisories due to elevated mercury levels in one or more species of fish and there are also 

waterfowl advisories for several duck species around the Great Salt Lake. The source of mercury in 

Utah’s waterways is currently unknown and has not been attributed to Utah’s power plants. However, 

the Utah Department of Environmental Quality has worked to reduce mercury emissions throughout the 

state as a proactive measure. Utah’s 2003 RH SIP and the PM/NOx BART determination in 2008 were 

intended to work in conjunction with R307-424 and CAMR to reduce emissions from SO2, PM, and 

mercury.

The CAMR rule was vacated on February 8, 2008, and has since been replaced by the Mercury and Air 

Toxics Standards (MATS) rule that was adopted on December 16, 2011. The MATS rule requires controls 

by 2015. Despite the delay in the federal rule, Utah’s rule and permits remained in effect and the 

mercury reductions were achieved as planned, and were achieved earlier than required nationwide.

Table 2 shows mercury emissions reported in Utah’s triennial inventory. Mercury emission reductions 

due to the upgrades at Hunter 1 will be reflected in the next triennial inventory in 2014. 

Table 2. Mercury Emission Trends

Mercury Compound Emissions (lbs/yr)

2005 2008 2011

Hunter 381 104.84 63.52

Huntington 242 46 12.16

Note: Reported emissions for Hunter include Unit 3 which is not subject to BART. Unit 3 is equipped with a 

baghouse and WFGD Scrubber.

Partial Approval, Partial Disapproval of Utah’s Regional Haze SIP

On December 14, 2012, EPA approved the majority of Utah’s Regional Haze SIP, but disapproved Utah’s

BART determinations for NOx and PM for PacifiCorp’s Hunter Unit 1, Hunter Unit 2, Huntington Unit 1, 

and Huntington Unit 2. EPA disapproved these BART determinations because EPA did not agree that 

their own analysis satisfied the 5-factor analysis requirement in the BART rule. EPA therefore 

determined that the SIP did not contain a 5-factor analysis as required by the rule. 

EPA’s disapproval of Utah’s BART determination did not comply with the Clean Air Act’s required 

timeline for acting on State SIPs. Utah’s Regional Haze SIP was submitted to EPA on September 9, 2008. 

Under section 110(k)(1) of the Clean Air Act EPA is required to determine whether the SIP is complete 

within 6 months, otherwise the SIP is determined to be complete. EPA did not take action so it was 

automatically determined to be complete in March 2009. EPA was then required to take action on the 

SIP within 12 months of the completeness determination (March 2010). EPA’s proposed disapproval of 

the BART determination did not occur until May 2012 with the final action occurring in December 2012. 

The timing is important because during the intervening years Utah’s BART determination was in place

and enforceable under state law and state permits. PacifiCorp incurred significant expense to comply 

with those requirements. The required controls were already installed and operating on 3 of the 4 EGUs 

5
prior to EPA’s proposed disapproval, and were installed on the 4th EGU in 2014 as required by Utah’s SIP

under state law. The 2008 BART determination was implemented in good faith by both the State of 

Utah and PacifiCorp, controls were installed within 5 years as required by the BART rule, and the 

emission rate met the presumptive limits established by EPA in Appendix Y.

New 5-Factor Analysis

In June 2012 after EPA had proposed to disapprove Utah’s BART determination, PacifiCorp prepared a 

new 5-factor BART analysis to satisfy the requirements of the BART rule. PacifiCorp submitted an 

update to that analysis on August 5, 2014, to address issues that EPA had raised with other regional haze 

SIPs. 

Analysis of Controls for SO2, NOx, and PM Established as BART in 

2008

Energy and Non-Air Quality Environmental Impacts

PacifiCorp determined that installation of low-NOx burners (LNBs) with overfire air (OFA) did not 

significantly impact boiler efficiency or power usage, but could result in higher carbon monoxide 

emissions and unburned carbon in the ash. While not included as an impact in PacifiCorp’s analysis, 

DAQ staff considers the mercury reductions achieved by the installation of baghouses in conjunction 

with flue gas de-sulfurization as a positive non-air quality environmental impact due to possible impact 

on mercury levels in lakes and streams.

Remaining Useful Life

PacifiCorp assumed a remaining useful life for all 4 units of 20 years. 

Economic Impact 

PacifiCorp’s 5-factor analysis documented the cost of the controls for SO2, NOx, and PM that were 

installed on the 4 subject-to-BART EGUs as required by Utah’s 2008 RH SIP. The total capital cost for the 

controls was $588,436,5524

. When operating costs were included, the total annualized cost of the new 

controls was $70,847,852/year. Focusing specifically on NOx, 11,480 tons of NOx were reduced from 

the 4 subject-to-BART EGUs with an average cost of $307/ton. These costs were consistent with EPA’s 

analysis in the BART rule that meeting the presumptive limits for NOx would cost an average of $100/ton 

to just over $1,000/ton.

Visibility benefit

Early Reductions

Because Utah’s RH SIP was developed under section 309, the SIP was originally submitted to EPA in 2003 

and the emission reduction strategies were implemented 5 years earlier than in most other states. The 

SO2 milestones established steady and continuing reductions through 2018, but as can be seen in Figure 

2, the emission reductions necessary to meet the 2018 milestone were achieved 7 years early in 2011,

4 PacifiCorp provided actual costs for installing SO2 and PM controls on 3 of the 4 EGUs and estimated costs for 

Hunter 1. Costs for NOx controls were updated August 5, 2014.

6

 
and since that time, SO2 emissions have continued to decrease. The NOx and PM reductions required 

by Utah’s 2008 BART determination also occurred earlier than was achieved under the BART rule for 

most western states, with controls installed in 2006, 2010, and 2011 for Huntington 2, Huntington 1, and 

Hunter 2, respectively. The early visibility benefits due to these reductions are a consideration when 

evaluating the degree of visibility improvement due to BART at Class I areas on the Colorado Plateau.

Modeling Results

PacifiCorp performed visibility modeling as outlined in the June 2012 modeling protocol. DAQ required 

the use of the approved version of CALPUFF (Version 5.8 level 070623), CALMET (Version 5.8 level 

070623), POSTUTIL (Version 1.56 level 070627), CALPOST (Version 6.292 level 110406), Method 8 

visibility analysis, and the constant 1 ppb ammonia rate used in the 2006 WRAP BART protocol. The 

baseline results are representative of operations and meteorology in 2001-2003.

The model indicates significant visibility improvement due to the new controls for SO2, NOx, and PM as 

required by the 2008 BART determination. Table 3 shows the modeled improvement for each of the 4 

subject-to-BART EGUs at Canyonlands National Park, the Class I area with the greatest overall impact. 

Table 3. Modeled visibility benefit at Canyonlands due to 2008 BART determination

Baseline Permitted Controls 

98th 

Percentile 

(∆dv)

No. of days 

>0.5 ∆dv

98th 

Percentile 

(∆dv)

No. of days 

>0.5 ∆dv

Huntington 1 3.00 130 1.65 64

Huntington 2 3.66 156 1.65 65

Hunter 1 3.07 131 1.75 61

Hunter 2 3.08 132 1.75 61

Figure 4 shows that the modeled visibility improvement was distributed throughout the year, including 

the high visitation months of April – September (results are shown for one unit from each plant). 

7
Figure 4. Modeled number of days improved at Canyonlands due to 2008 BART determination

These modeled improvements are significant in both the magnitude of expected improvement as well as 

the number of days with improvement. 

Monitoring Data

Because controls have been installed on 3 of the 4 units since 2011, monitoring data can also be used to 

validate the actual benefit achieved. Controls were installed on the EGUs as follows: Huntington Unit 2 

at the end of 2006, Huntington Unit 1 in the Fall of 2010, and Hunter Unit 2 in the Spring of 2011. 

Controls were installed on Hunter Unit 1 in the Spring of 2014 but are not yet reflected in the 

monitoring data. Figures 5 and 6 show the emission trends for SO2 and NOx from the 4 subject-to-BART 

EGUs.

8
Figure 5. SO2 Emission Trends

Figure 6. NOx Emission Trends

9
DAQ staff evaluated the monitoring data using several different metrics. First, the overall trend in 

deciviews and the contribution of individual species to light extinction during the 20% worst and 20% 

best days at Canyonlands were evaluated. Canyonlands was chosen because the highest overall 

modeled impacts occurred at Canyonlands. The 20% best and 20% worst day metric is used to measure 

progress towards the national visibility goal under the regional haze rule. The significant reductions at 

Huntington 2 at the end of 2006 and the additional reductions at Huntington 1 and Hunter 2 in 2010 and 

2011 did not result in any identifiable visibility improvement on either the 20% worst or the 20% best 

days, but overall visibility is improving. 

Figure 7. Deciview Trends on 20% Worst and 20% Best Visibility Days

10
DAQ staff also evaluated changes in the individual species that contribute to visibility impairment. The 

98th percentile (3rd high) and the median values of sulfate and nitrate mass are shown in Figures 8 and 9. 

Emission trends from the 4 subject-to-BART units are also included. The significant reductions in SO2

and NOx have not led to corresponding improvements on the high sulfate and nitrate days, but the 

median values do show overall improvement.

Figure 8. Sulfate Trends

11
Figure 9. Nitrate Trends

Ammonia

Surprisingly, the high nitrate values are increasing over time, despite the significant reduction in NOx 

emissions from the 4 subject-to-BART EGUs, as well as on-going reductions from mobile sources and 

other power plants throughout the region. This unexpected result may occur because ammonium 

sulfate forms more readily than ammonium nitrate when both SO2 and NOx are available to react with 

ammonia. As SO2 emissions decline and SO2 is no longer available, the reaction shifts to form 

ammonium nitrate from available NOx. Figure 10 shows the nitrate and sulfate mass on the 98th

percentile (3rd high) nitrate day showing the possible shift from formation of sulfate to nitrate. One

explanation for the lack of improvement is that ammonia is limiting the reaction. This would be 

significant because reductions in SO2 and NOx emissions may not lead to visibility improvements under 

ammonia limited conditions.

12
Figure 10. Nitrate and Sulfate on High Nitrate Days

The high nitrate values occur primarily during the winter when ammonia is typically lowest, so winter 

values (December – February) were compared to values during the rest of the year (March – November) 

to determine if there were seasonal differences. Figure 11 shows that the decreases in sulfate are 

offset by increases in nitrate during the winter while ammonium levels show little change. This would 

make sense if ammonia is limiting the reaction because two molecules of ammonium nitrate (NH4)NO3 

would be created for every molecule of ammonium sulfate (NH4)2SO4 that was decreased. During the 

summer sulfate, nitrate, and ammonium are all decreasing, indicating that ammonia is not limiting the 

reaction. 

13
Figure 11. Sulfate and Nitrate Trends in Winter and the Rest of the Year

14
DAQ required PacifiCorp to use a constant background ammonia concentration of 1 ppb for the visibility 

modeling in the 5-factor analysis to be consistent with the visibility modeling protocols used by EPA and 

other western states. PacifiCorp had requested to use a variable ammonia concentration based on 

monitoring in the Four Corners area that showed lower ammonia levels during the winter months. 

Figure 12 shows the monitored ammonia values at Navajo Lake, NM. This site was identified as a 

regional background site during a 2007 study of ammonia emissions in New Mexico and Oklahoma5

. 

The shaded bands highlight the winter months of December – February and as can be seen the ammonia 

values during the winter are typically much lower than 1 ppb. 

Figure 12. Ammonia Trends

DAQ agreed that ammonia rates are likely lower in the winter, but the data set was so sparse that it was 

difficult to determine the appropriate levels that should be used. The Navajo Lake site is about 250 

miles from the PacifiCorp EGUs and the only other monitoring sites in Utah were affected by urban 

emissions or agriculture. Ammonia emission sources are primarily livestock, agriculture, and human 

populations in urban areas and there are few of these types of emission sources in southern Utah. 

Because local data were not available and there were so few western ammonia sites, DAQ required 

PacifiCorp to use the conservative constant ammonia rate that had been used by EPA and other western 

5 Sather et al., Baseline ambient gaseous ammonia concentrations in the Four Corners area and eastern Oklahoma, 

USA, J.Environ. Monit., 2008, 10, 1319-1325

15

 
states. Modeling performed by the Colorado Department of Public Health and Environment 

demonstrated that under certain conditions CALPUFF is sensitive to the assumed level of ammonia at 

levels below 1 ppb6 so the model may be overpredicting the formation of ammonium nitrate during the 

winter if ammonia levels are near 0.2 ppb as measured at Navajo Lake during most winters.

In May 2014 DAQ began monitoring ammonia at Canyonlands to gain a better understanding of 

background ammonia levels. Figure 12 shows that the initial few measurements at Canyonlands are 

similar to values at Navajo Lake. The dataset is sparse, but indicates that ammonia data from Navajo 

Lake may be representative for the area. 

The ammonium in particulate matter must also be considered when evaluating wintertime ammonia 

rates. Figure 13 shows the combined ammonia and ammonium (ppm) at Canyonlands, using Navajo 

Lake ammonia values as a surrogate. The sample frequency is different for the two datasets. The 

ammonium data are from the IMPROVE network that collects a 24-hour filter every 3 days while the 

ammonia data are two week average samples so the Figure 13 is best used to determine seasonal trends 

rather than daily values. This figure illustrates that total ammonia values are lower in the winter and are 

typically below the 1 ppb level that was used in the modeling in the winter.

Figure 13. Seasonal Variation in Ammonia.

6

 Colorado Department of Public Health and Environment, BART CALPUFF Class I Federal Area Individual Source Attribution 

Visibility Impairment Modeling Analysis for Public Service Company of Colorado Hayden Station Units 1 and 2, November 1 

2005, page 31.

16

 
Other NOx Emission Sources

DAQ staff also evaluated the possibility that NOx could be increasing from other sources in the region. 

Figure 14 shows that NOx emissions are decreasing at other EGUs in the area. Mobile source NOx 

emissions are decreasing nationwide due to implementation of the Tier 1 and Tier 2 emission standards

and should continue to be reduced through the implementation of Tier 3 emission standards. 

Figure 14. NOx Emission Trends from EGUs

Table 4 shows that oil and gas NOx emissions in the surrounding basins are increasing, but the overall 

scale of the emission increase is small when compared to the decrease in emissions from EGUs in the 

region.

Table 4. NOx Emissions from the Oil and Gas Industry

Oil and Gas Inventory

2006 2012 Change

Uinta Basin 13,093 16,641 3,458

Northern San Juan 5,700 4,195 (1,505)

Southern San Juan 42,075 43,050 975 

Piceance 12,390 9,951 (2,439)

Total 73,258 73,747 489 

Source: WRAP Phase III Inventory 2012 projection

17
Other Modeling Considerations

DAQ staff considered several other reasons why the model might indicate a greater improvement in 

visibility than is measured by the monitoring data. 

1. The modeling protocol uses conservative assumptions. The model assumes background 

“natural conditions” while current conditions are affected by regional and international 

emissions. EPA requires this approach because the goal established in the regional haze rule is 

to achieve natural conditions by 2064. The impact of an individual emission source is decreased 

when other emission sources are included in the model because the human eye can perceive 

differences in visibility more readily under pristine conditions. The deciview metric is designed 

to reflect this difference. DAQ staff do not disagree with the goal of achieving natural conditions 

but believe that some consideration must be also be given to visibility improvements that are 

likely to be experienced within the next few decades. In addition, the emission rate used in the 

model to evaluate worst case conditions is higher than would typically occur.

2. The model may need refinements. PacifiCorp performed additional visibility modeling using 

CALPUFF version 6.42, an updated version of the CALPUFF model that has not yet been 

validated by EPA. This latest version of the model predicted significantly less visibility impact 

from the 4 subject-to-BART EGUs at Utah’s Class I areas. DAQ does not have the resources or 

staff expertise to determine whether the updated version of the CALPUFF model provides more 

accurate results than the currently approved version (CALPUFF 4.8). Therefore, DAQ required 

PacifiCorp to use the approved version of the model for the 5-factor analysis. EPA is currently 

reviewing CALPUFF version 6.42. If EPA validates the new version of the model in the near 

future DAQ will update this staff review to include the results of the new modeling.

The bottom line is that the modeled improvement may be significantly overestimated. When evaluating 

the 5th factor in the 5-factor analysis (the degree of improvement in visibility which may reasonably be 

anticipated to result from the use of such [best available retrofit] technology) DAQ is therefore viewing 

the CALPUFF modeling results as part of a broader analysis of visibility that also considers monitoring 

data, emission inventory trends, and the regional modeling that was developed by the WRAP to show 

changes in visibility between 2002 and 2018. This approach is consistent with EPA’s Guidelines in 

Appendix Y. Appendix Y outlines “an approach you may use to determine visibility impacts for the BART 

determination7

” using CALPUFF, but also states, “you have flexibility to assess visibility improvements 

due to BART controls by one or more methods. “ 8 The preamble to the BART rule provides additional 

support for the use of a broader analysis. 

“Because each Class I Area is unique, we believe States should have flexibility to assess 

visibility improvements due to BART controls by one or more methods, or by a 

combination of methods, and we agree with the commenters suggestions to do so. We 

believe the maximum 24-hour modeled impact can be an appropriate measure in 

7 70 FR 39170

8 Ibid

18

 
determining the degree of visibility improvement expected from BART reductions (or for 

BART applicability). We have pointed out, however, that States should have flexibility 

when evaluating the fifth statutory factor. A State is encouraged to account for the 

magnitude, frequency, and duration of the contributions to visibility impairment caused 

by the source based on the natural variability of meteorology. These are important 

elements to consider as they would provide useful information on both the short term 

peak impact and long term average assessments which are critical in making the 

visibility assessment.”9

Analysis of Particulate Matter Control Options

PacifiCorp’s 5-Factor analysis identified three technologies that were available prior to the 2008 BART 

determination: upgraded electrostatic precipitator (ESP) and flue gas conditioning (0.040 lb 

PM10/MMBtu); polishing fabric filter (0.015 lb PM10/MMBtu); and replacement fabric filter (0.015 lb 

PM10/MMBtu). The 2008 BART determination required PacifiCorp to install a fabric filter baghouse with 

a PM emission rate of 0.015 lb/MMBtu at Hunter Units 1 and 2; a PM10 emission rate of 74 lb/hr at 

Huntington Unit 1; and a PM emission rate of 70 lb/hr at Huntington Unit 2. The pound per hour 

emission rate for the Huntington units was based on a 0.015 lb/MMBtu emission rate and a maximum 

hourly heat input. The baghouse technology is considered to be the most stringent technology available 

and 0.015 lb PM10/MMBtu represents the most stringent emission limit. 

Appendix Y allows a streamlined 5-factor analysis when the most stringent controls are already required. 

“If you find that a BART source has controls already in place which are the most 

stringent controls available (note that this means that all possible improvements to any 

control devices have been made), then it is not necessary to comprehensively complete 

each following step of the BART analysis in this section. As long as these most stringent 

controls available are made federally enforceable for the purpose of implementing BART 

for that source, you may skip the remaining analyses in this section, including the 

visibility analysis in step 5. Likewise, if a source commits to a BART determination that 

consists of the most stringent controls available, then there is no need to complete the 

remaining analyses in this section.” (40 CFR Part 51, Appendix Y, Section D.9)

Because the most stringent technology is in place and the approval orders and operating permits for the 

Hunter and Huntington plants contain a federally enforceable emission limit for PM10 of 0.015 

lb/MMBtu (30 day rolling average) no further analysis is required.

9 70 FR 39129

19

 
Analysis of NOx Control Options

PacifiCorp evaluated 18 different NOx control options, and determined that the following were 

technically feasible10: low NOx burners and overfire air (LNB + OFA – option required by 2008 BART 

determination), selective non-catalytic reduction (LNB + OFA + SNCR), and selective catalytic reduction 

(LNB + OFA + SCR). Table 5 shows the emission rates and annual emissions for the different control 

options. Historic baseline emissions are also shown to illustrate the emission reductions that have 

already been achieved, but these emissions have little relevance when evaluating future scenarios 

because LNB + OFA have already been installed on all four EGUs. 

Table 5. NOx Control Options

Hunter 1 Hunter 2 Huntington 1 Huntington 2

Historic Baseline (2001-2003)

Actual Emission Rate 

(lb/MMBtu)a

0.4 0.38 0.37 0.39

Actual Emissions (tons/yr)a 6,380 6,092 5,944 5,816 

Current Operations (LNB+OFA)

Permitted Emission Rate

(lb/MMBtu)

0.26 0.26 0.26 0.26

Actual Emissions (2012/13)a 6,032 3,412 3,593 3,844 

Actual Emission Rate (2012/13)a 0.38 0.20 0.22 0.22

LNB + OFA + SNCR

Emission Rate (lb/MMBtu) 0.160 0.160 0.166 0.166

Emissions (tons/yr) 2,485 2,703 2,685 2,838 

LNB + OFA + SCR

Emission Rate (lb/MMBtu) 0.05 0.05 0.05 0.05

Emissions (tons/yr) 775 843 809 856 

a

Source: EPA Clean Air Markets Division

Energy Impacts

PacifiCorp’s analysis notes that SNCR and SCR will result in increased parasitic load due to the injection 

of urea or ammonia. An SCR retrofit will impact the existing flue gas fan systems, due to the additional 

pressure drop associated with the catalyst. 

Non-Air Quality Environmental Impacts

PacifiCorp’s analysis notes that both an SNCR and SCR installation could impact the salability and 

disposal of fly ash due to increased ammonia levels. In addition, ammonia slip could potentially create a 

visible stack plume or increase the background ammonia concentrations which may negate any 

10 Neural network optimization system (NNOS) is also technically feasible but was not evaluated because the 

potential for significant and consistent NOx reduction was minimal.

20

 
perceived visibility improvements. Other environmental impacts involve the storage of ammonia, 

especially if anhydrous ammonia is used, and the transportation of the ammonia to the power plant. 

The potential increase in background ammonia concentrations is a concern during the winter months if 

the area is ammonia limited. In this case, the efforts to reduce NOx could actually increase the 

formation of ammonium nitrate due to the ammonia slip. The overall impact on regional ammonia 

levels, however, is likely to be minimal and would therefore have a limited negative impact on visibility 

during the winter months. The potential creation of a visible stack plume in the area surrounding the 

Hunter and Huntington plants is a concern. A visible stack plume could be seen from some of Utah’s 

Class I areas affecting the vista in those areas. In addition, the San Rafael Swell is a large natural area 

located in close proximity to the two plants. The San Rafael Swell, 2,000 square miles of public land, is 

known for its scenic sandstone formations, deep canyons, desert streams, and expansive panoramas. 

The San Rafael Swell is not a Class I area, but visibility is an important factor in all of Southern Utah. 

Utah’s Visibility SIP, Section XVII.J contains the Air Conservation Committee’s (since renamed Air Quality 

Board) Policy Statement for the Protection of Visibility 

“The State recognizes that visibility and the ability to see the great scenic views in 

Southern Utah is a rare and unique treasure and should be preserved, both for the 

benefit and pleasure of Utah residents, and to support our large tourist industry. In 

addition to the distance one can see, the clarity, color, and detail of the visible features 

are also important.”

EPA’s Air Pollution Control Fact Sheets for SNCR (EPA-452/F-03-031) and SCR (EPA-452/F-03-032)

indicates that ammonia slip may cause increased plume visibility; however, ammonia slip at a level of 2 

to 10 ppm, the typical permitted level, does not result in plume formation. SNCR has typically been 

installed on smaller EGUs due to the difficulty with consistent mixing of the reagent (ammonia or urea) 

in a large boiler. Inconsistent mixing could also lead to increased ammonia slip. EPA’s fact sheet 

indicates that advancements in SNCR injection and control systems have improved mixing in large 

boilers (greater than 300 MW). Because SNCR is a relatively new technology for larger boilers there is 

not a long track record regarding the effectiveness of SNCR at EGUs at plants comparable to Hunter and 

Huntington.

Remaining Useful Life

The remaining useful life for all 4 subject to BART EGUs is assumed to be 20 years. However, PacifiCorp

raised a significant issue in the August 4, 2014, update to their 5-factor analysis. 

“EPA’s proposed Carbon Pollution Emission Guidelines for existing Stationary Sources

[Clean Power Plan], published June 18, 2014, introduces considerable uncertainty 

surrounding many of the assumptions that go into any BART determination. For 

example, the proposed [Clean Power Plan] rule establishes state-specific carbon 

emission targets based on the calculation of the best system of emission reduction that 

includes a significant improvement in plant efficiency and an overall reduction in each 

coal plant’s utilization and remaining useful life beginning in 2020. The objectives of the 

[Clean Power Plan] rule must be reconciled with EPA’s required approach to BART 

21
determinations which do not take these issues into account. EPA recognizes in the 

[Clean Power Plan] rule that the development of regional haze and other SIPs may ‘have 

significant implications for existing fossil fuel-fired EGUs, as well as the states that are 

responsible for developing them.”

...Unless the 111(d) and regional haze SIPs are coordinated and reconciled, PacifiCorp 

may be in an untenable position with the prospect that BART determinations could 

require SCR as NOx BART based on assumptions of higher plant utilization and 20-year 

useful lives (while at the same time lowering plant efficiencies), only to have those 

assumptions case aside by the [Clean Power Plan] rule requirements. PacifiCorp 

requests that Utah consider these aspects as part of its BART analyses and consider 

these aspects as part of its BART analyses and determine that the intended impacts of 

the proposed [Clean Power Plan] rule provide yet another reason why NOx BART for the 

affected Hunter and Huntington units is LNB/OFA as originally ordered by the state and 

currently installed.

DAQ staff agrees that the current uncertainty regarding future requirements under the Clean Power 

Plan rule is a significant concern and the possibility of stranded costs should be considered. In addition, 

potential control requirements under the 2010 SO2 NAAQS and the expected new 2015 ozone NAAQS 

are additional areas of uncertainty.

Economic Impact

Cost of Control

PacifiCorp provided cost estimates for installing SNCR or SCR. The cost information for SNCR is based 

upon generally available industry information. The SCR cost information was provided by Sargent & 

Lund and reflects the methodologies and costing methods that EPA has found acceptable in other 

SIP/FIP determinations, including those performed for Wyoming facilities. A summary of the costs is 

shown in Table 6.

22
Table 6. NOx Control Options Cost

SNCR Total Hunter 1 Hunter 2 Huntington 1 Huntington 2

Capital Cost (Including LNB+OFA) $ 67,793,347 $ 19,238,047 $ 16,444,561 $ 15,976,323 $ 16,134,416

Annualized Cost (including LNB+OFA) $ 17,039,977 $ 4,423,789 $ 4,160,103 $ 4,220,581 $ 4,235,504

NOx Emissions 10,711 2,485 2,703 2,685 2,838

Incremental tons removed 3,275 652 709 907 1,006

Incremental Capital Cost $ 30,447,246 $ 7,651,274 $ 7,572,349 $ 7,651,274 $ 7,572,349

Incremental Annualized Cost $ 13,514,769 $ 3,330,080 $ 3,322,629 $ 3,434,755 $ 3,427,305

Incremental $/ton $ 4,246 $ 5,106 $ 4,684 $ 3,787 $ 3,407

SCR Total Hunter 1 Hunter 2 Huntington 1 Huntington 2

Capital Cost (including LNB+OFA) $711,080,071 $ 180,791,743 $ 177,483,372 $ 176,287,506 $ 176,517,450

Annualized Cost (Including LNB+OFA) $ 96,914,271 $ 24,539,094 $ 24,144,098 $ 24,101,813 $ 24,129,266

NOx Emissions 3,282 775 843 809 856

Incremental tons removed 10,704 2,362 2,569 2,784 2,988

Incremental Capital Cost $673,733,970 $ 169,204,970 $ 168,611,160 $ 167,962,457 $ 167,955,383

Incremental Annualized Cost $ 93,389,063 $ 23,445,385 $ 23,306,624 $ 23,315,987 $ 23,321,067

Incremental $/ton $ 8,794 $ 9,925 $ 9,072 $ 8,375 $ 7,804

Potential Effect of EPA’s Clean Power Plan on Cost Estimates

In the Technical Support Document (TSD) of EPA’s Clean Power Plan Proposed Rule (“proposed rule”), 

the agency lays out the technical basis for the development of the Best System of Emission Reduction 

(BSER), which includes a combination of four “blocks,” including: Block 1 -- a 6% heat rate improvement 

in a given state’s coal EGU fleet, Block 2 -- redispatching to existing natural gas combined cycle (NGCC) 

plants to a proposed 70% capacity factor, Block 3 -- increased reliance on renewable energy (RE) and 

some nuclear generation, and Bock 4 -- increased end-use energy efficiency (EE). Specifically the Goal 

Computation Technical Support Document, Goal Computation Appendix 1 and 2 Data File (XLS) (found 

here: http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-state-goal-datacomputation_1.xlsx) demonstrates that a 70% redispatch to existing NGCC plants in Utah (Block 2)

would result in a 23.9% reduction in electricity generation from Utah’s coal plants from 27,332,140

MWh in 2012 to 20,797,210 MWh. While EPA does not require a state to utilize the four blocks to reach 

its emissions goal, the blocks illustrate a potential approach – in fact, EPA’s BSER approach – that a state 

might choose to comply with its goal. As a result, any controls for non-GHG emissions at coal plants 

could be more costly since coal generation in Utah could decrease by as much as one quarter under 

Block 2. As an example, if the current actual emissions for Hunter Unit 2 were reduced by 23.9% (to 

2,596 tons/yr) and the estimated emissions with SCR controls were also reduced by 23.9% (to 641

tons/yr) to reflect the assumed decrease in utilization of coal plants, then the overall reduction due to 

the installation of SCR would be 1,955 tons/yr, increasing the cost/ton from $9,072/ton to $11,921/ton. 

The ultimate requirements and resulting state strategy under the Clean Power Plan are not yet 

determined so the effect on utilization is unknown. Therefore, the cost of control is most appropriately 

expressed as a range that reflects current utilization on the lower end, and EPA’s BSER utilization on the 

upper end.

23
Table 7. Cost Range to Reflect Uncertainty Due to Proposed Clean Power Plan

Hunter 1 Hunter2 Huntington 1 Huntington 2 Average

SCR

Lower end of range $9,925 $9,072 $8,375 $7,804 $8,794 

Upper end of range (BSER) $13,041.76 $11,921.22 $11,005.51 $10,255.04 $11,556 

SNCR

Lower end of range $5,106 $4,684 $3,787 $3,407 $4,246 

Upper end of range (BSER) $6,709 $6,155 $4,976 $4,477 $5,579 

The bottom line is that the proposed Clean Power Plan creates a high degree of uncertainty regarding 

the cost of control.

System Wide Impact

In addition to the potential costs for further NOx controls at the Hunter and Huntington plants, 

PacifiCorp is also affected by the costs due to the installation of controls required by EPA’s Regional 

Haze FIP in Wyoming (published January 30, 2014), Wyoming’s Regional Haze SIP, and additional 

regional haze actions in Arizona and Colorado. PacifiCorp outlined their concerns about system wide 

costs in a letter to EPA dated July 12, 2012.11 PacifiCorp stated that “more than 80% of PacifiCorp’s 

6,157 total owned megawatts of coal-fueled generating capacity are BART-eligible and approximately 

half (more than 3,000 megawatts) of PacifiCorp’s coal-fueled generating capacity will be subject to the 

installation of controls within the next five years... If EPA ultimately attempts to require four additional 

SCR on PacifiCorp’s Utah units as BART controls, which is beyond the NOx controls already installed or 

planned for those units under the existing Utah SIP, then the impact on PacifiCorp, its customers, and 

system reliability will be even more severe.” EPA recognized the system wide impact on PacifiCorp in 

their proposed partial approval of Wyoming’s SIP, although EPA did not ultimately rely on this 

justification in their final BART determination in Wyoming.

EPA is proposing to determine that BART for all units at Jim Bridger would be SCR if the 

units were considered individually, based on the five factors, without regard for the 

controls being required at other units in the PacifiCorp system. However, when the cost 

of BART controls at other PacifiCorp- owned EGUs is considered as part of the cost 

factor for the Jim Bridger Units, EPA is proposing that Wyoming’s determination that 

NOX BART for these units is new LNB plus OFA is reasonable. Considering costs broadly, 

it would be unreasonable to require any further retrofits at this source within five years 

of our final action. We note that the CAA establishes five years at the longest period 

that can be allowed for compliance with BART emission limits.12

11 www.regulations.gov, EPA-R08-OAR-2012-0026-0044, 7-12-2012 PacifiCorp Comments

12 78 FR 34756

24

 
Carbon Power Plant

PacifiCorp has announced plans to shut down the Carbon Power Plant in 2015 due to the high cost to 

control mercury to meet the requirements of EPA’s Mercury and Air Toxics Standards (MATS). This plant 

is located about 30 miles northeast of the Huntington Plant and about 40 miles northeast of the Hunter 

Plant. Average SO2 emissions from 2012-13 were 8,005 tons/yr, and average NOx emissions were 3,342 

tons /yr. PacifiCorp and ultimately Utah rate payers must pay the cost to replace the electricity 

generated by this plant, but there will also be a visibility benefit due to the emission reductions. Overall 

emission reductions of SO2 and NOx due to the closure of this plant will be equivalent to the NOx 

reductions that could be achieved by installing the most stringent NOx control, SCR, on the 4 subject-toBART EGUs and the emission reductions will occur close to the location of the Hunter and Huntington 

plants. The SO2 emission reductions from the closure of this plant will be in addition to what was 

required under the SO2 milestones in Utah’s SIP because regional emissions in 2011 and 2012 were 

already below the 2018 milestone target.

While PacifiCorp has announced plans to shut down the Carbon Plant, this decision is not enforceable. 

An enforceable requirement in the Regional Haze SIP to close the Carbon Plant would lock in this 

substantial emission reduction.

Visibility Impact

PacifiCorp’s 2012 modeling showed an improvement in visibility impact due to the installation of either 

SNCR or SCR (Table 8). Figure 15 shows how the improved days are distributed through the year (results 

are shown for Huntington 2, similar results are seen for the other 3 units).

Table 8. Modeled Visibility Impact for Control Options

Current Operation SNCR SCR

98th 

Percentile 

(∆dv)

No. of 

days 

>0.5 ∆dv

98th 

Percentile 

(∆dv)

No. of 

days 

>0.5 ∆dv

98th 

Percentile 

(∆dv)

No. of 

days >0.5 

∆dv

Huntington 1 1.65 64 1.45 57 0.96 38

Huntington 2 1.65 65 1.45 57 0.97 38

Hunter 1 1.75 61 1.51 54 1.00 39

Hunter 2 1.75 61 1.51 54 0.99 39

25
Figure 15. Modeled days improved at Canyonlands

As discussed earlier in the document, the modeled visibility improvement during the winter months of 

December – February may be overpredicted. DAQ is in the process of remodeling the 2001 – 2003 

episodes to incorporate the updated emission rates submitted by PacifiCorp on August 4, 2014. The 

updated regulatory version of CALPUFF and CALMET will be used along with POSTUTIL to properly 

apportion ammonia impacts due to multiple units at the plant. DAQ intends to perform a sensitivity 

analysis for ammonia due to the possibility that Southern Utah is ammonia limited during the winter 

months. The results of the modeling and the sensitivity analysis will be included in the TSD for public 

review and comment prior to the start of the comment period. Because the current model results are 

not validated by the monitoring data, DAQ staff is placing less weight on the modeling results when 

determining the degree of improvement in visibility which may reasonably be anticipated to result from 

the use of different technologies. 

Seasonal Differences

Sulfate is a problem year round, while the nitrate impact is most significant during the winter months 

when visitation is low at Utah’s national parks, as can be seen in Figure 16. The experience of every 

visitor is important, but the seasonal differences are important when evaluating the cost/benefit for 

difference control strategies. A high cost strategy that primarily benefits visibility during low visitation 

months may not be justified. Utah’s RH SIP was weighted to achieve SO2 reductions because sulfates 

are a problem year round and sulfates are overall the most significant anthropogenic contributor to 

haze on the Colorado Plateau. 

26
Figure 16. Seasonal Variability of Ammonium Nitrate Impact and Visitation at Canyonlands

Source: IMPROVE, http://vista.cira.colostate.edu/improve/

National Park Service, http://www.nature.nps.gov/stats/park.cfm

Other Considerations

Timing of Other Regulations 

There are a number of new federal regulations that may affect the four subject to BART EGU’s. DAQ 

recognizes that a comprehensive strategy that considers multiple requirements would provide the best 

outcome for Utah rate payers who will pay for any new pollution controls.

• October 2015, EPA is required to finalize its review of the ozone NAAQS, potentially 

tightening the standard. 

• 2016, plan required to reduce carbon emission from existing power plants under EPA’s 

proposed Clean Power Plan.

• 2017-2019, Source-specific SO2 monitoring is required under the proposed SO2 data 

requirements rule to determine attainment status under NAAQS

27
2018 SIP Revision

The Regional Haze Rule requires states to submit a new SIP every 10 years with the next major revision 

due in 2018. The 2018 SIP must establish goals that provide for reasonable progress towards achieving 

natural visibility conditions by 2064. While BART focused on the direct visibility impact of individual 

plants including source specific modeling, reasonable progress is a broader goal that will require an 

evaluation of additional emission reductions that could be achieved from all significant emission sources 

in Utah. The first planning period was focused on SO2 reductions. DAQ anticipates that NOx reductions 

will be important in the next planning period to address the dual requirements of reasonable progress 

towards the national visibility goal and ozone attainment. NOx controls beyond BART may be required 

to achieve reasonable progress in the next planning period. By 2018 many of the uncertainties 

regarding other upcoming regulations will have been resolved providing Utah an opportunity to develop 

a comprehensive strategy that addresses multiple air quality goals.

Weighting of 5-Factors for PM BART Determination

Because the most stringent technology is in place and the approval orders and operating permits for the 

Hunter and Huntington plants contain a federally enforceable emission limit for PM, no further analysis 

is required. 

Weighting of 5-Factors for NOx BART Determination

Appendix Y, Section IV(E) establishes the general process for selecting the best alternative for BART and 

Section IV(E)(5) provides specifics for nitrogen oxide limits for utility boilers. This section states,

“For coal-fired EGUs greater than 200 MW located at greater than 750 MW power 

plants and operating without post-combustion controls (i.e., SCR or SNCR), we have 

provided presumptive NOx limits differentiated by boiler design and type of coal 

burned. You may determine that an alternative control level is appropriate based on a 

careful consideration of the statutory factors.”

The four subject to BART EGUs are all tangential-fired units that burn bituminous coal. The presumptive 

NOx emission limit for these units is 0.28 lb/MMBtu. Under Utah’s 2008 RH SIP all four EGU’s meet the 

presumptive limit as required by Appendix Y and have met the standard established by EPA as BART. 

Utah has the option to demonstrate that an alternative control level is appropriate if that is justified by 

the 5-factor analysis. Since the presumptive BART limit was met by the 2008 BART determination and 

the controls have already been installed on all four units as required by Utah’s SIP, the discussion in this 

section will focus on whether Utah should choose to go beyond the federal requirement and establish 

an alternative control level based on a consideration of the five statutory factors.

Utah’s Regional Haze SIP demonstrated reasonable progress based on the significant SO2 emission 

reductions required by the regional milestones, Utah’s smoke management program, and the significant 

NOx reductions due to the 2008 BART determination and mobile source reductions. Utah’s reasonable 

progress demonstration was fully approved by EPA in 2012 and further emission reductions are not 

necessary to demonstrate reasonable progress.

28
The 5-factor analysis provides information about the effect of various control options for BART. States 

are “free to determine the weight and significance to be assigned to each factor.”13 The preamble to 

the BART rule states, 

“we also recommend that the States use CALPUFF as a screening application in 

estimating the degree or visibility improvement that may reasonably be expected from 

controlling a single source in order to inform the BART determination. As we noted in 

2004, this estimate of visibility improvement does not by itself dictate the level of 

control a State would impose on a source; ‘the degree of improvement in visibility which 

may reasonably be anticipated to result from the use of [BART]’ is only one of the five 

criteria that the State must consider together in making a BART determination. The 

State makes a BART determination based on the estimates available for each criterion, 

and as the CAA does not specify how the State should take these factors into account, 

the States are free to determine the weight and significance to be assigned to each 

factor.” 70 FR 39123 

DAQ staff weighted heavily two aspects of the first factor, “cost of compliance”: the incremental cost of 

control between the currently required operations and the SNCR and SCR control scenarios, and the 

overall cost of control. EPA did not act in a timely manner on Utah’s 2008 SIP, allowing controls to be 

installed on 3 of the 4 EGUs before notifying Utah that the 2008 RH SIP was not adequate and proposing 

disapproval of Utah’s BART determination. PacifiCorp has already incurred capital costs of $587,253,269

to install controls as required by Utah’s 2008 BART determination. The 2008 SIP was implemented in 

good faith by Utah prior to EPA’s disapproval, and therefore the cost/benefit analysis must focus on the 

incremental cost of installing post-combustion controls rather than assuming that the upgrades required 

in 2008 had never occurred. Even if the upgrades had not occurred, post-combustion controls would 

have been evaluated as an addition to LNB + OFA rather than an independent control so incremental 

costs would have been a significant factor. It is also appropriate to weight the incremental cost of 

control to determine whether an alternative control level is appropriate rather than relying on the 

presumptive BART level for NOx that EPA has already determined is “highly cost-effective” and “would 

result in significant improvements in visibility and help to ensure reasonable progress toward the 

national visibility goal.”14 Focusing specifically on NOx, 11,480 tons of NOx have already been reduced 

from the 4 subject-to-BART EGUs with an average cost of $307/ton of NOx reduced. 

The most stringent control option, SCR would reduce NOx emissions by 2,676 tons/yr (average reduction 

per EGU) for an incremental cost of $8,794/ton to $11,556/ton (range reflects uncertainty due to Clean 

Power Plan) while SNCR would reduce NOx emissions by 819 tons/yr (average per EGU) for an

incremental cost of $4,246/ton to $5,579/ton (range reflects uncertainty due to Clean Power Plan). The 

incremental cost to install SCR is very high and is not cost effective. The incremental cost to install SNCR 

is high and is difficult to justify unless the emission reductions would achieve a significant visibility 

benefit.

13 40 CFR Appendix Y, section IV.D.5

14 70 FR 39131

29

 
When considering the second aspect of the “cost of compliance,” the overall cost of control, the fact 

that the Carbon Power Plant is scheduled to close in 2015 resulting in significant reductions of SO2 and 

NOx was an important consideration. These reductions will achieve a comparable visibility benefit to 

the installation of SCR on the Hunter and Huntington EGUs with no additional cost, but would need to 

be made enforceable to ensure that the plant is not reopened at a later date. DAQ staff also considered 

the system wide costs that PacifiCorp has already incurred due to the regional haze requirements in 

Wyoming, Arizona, and Colorado.

DAQ staff weighted heavily the fifth factor, the “degree of improvement in visibility which may 

reasonably be anticipated to result from the use of BART.” Four aspects of visibility improvement were 

considered equally:

1) The results of the CALPUFF visibility modeling that estimated a significant visibility 

improvement, using conservative assumptions (natural conditions, highest emission rate, 98th

percentile impact).

2) The results of the regional modeling conducted by the WRAP and referenced in Section K of 

Utah’s RH SIP that shows a more modest improvement despite significant regional emission 

reductions. 

3) The monitoring data that do not show visibility improvement at Canyonlands on high nitrate 

days during the months of December – February. The significant reductions in both SO2 and 

NOx that have already occurred due to the 2008 BART determination have resulted in a shift 

from sulfate to nitrate during the winter at Canyonlands rather than a decrease in total aerosols. 

4) The low visitation at Utah’s Class I areas during the winter months of December – February

when nitrate is most likely to impair visibility. Utah’s RH SIP appropriately focused on SO2,

achieving significant benefits during the high visitation months of March – November.

DAQ staff also weighted heavily the uncertainty created by upcoming regulations, particularly the

proposed Clean Power Plan rule. The Clean Power Plan rule, as proposed, significantly affects the fourth 

factor, “remaining useful life,” and the first factor, “cost of compliance.” Cost of compliance is 

expressed as cost/ton (a reduction in “remaining useful life” would increase the annualized cost in the 

numerator while lower utilization would decrease the emission reductions in the denominator leading 

to an overall higher cost of compliance). DAQ staff also considered that a new RH SIP revision is due in 

2018 and potential emission reductions from all significant sources, including EGUs, must be evaluated 

for the next planning period. NOx reductions are expected to be important in the next RH SIP to address 

the dual requirements of regional haze and ozone. By 2018 the state plan required by the Clean Power

Plan rule will be completed, providing greater certainty regarding the cost and potential emission 

reductions due to the installation of post-combustion NOx controls.

30
Staff Recommendation

Staff recommends that the Board retain the 2008 BART determination with the following changes:

1. Correct the typographical error in Table 5 of the SIP to reflect the 0.015 lb/MMBtu PM limit in 

the approval orders for Hunter Units 1 and 2 and include the 74 lb/hr emission rate for 

Huntington Unit 1 and the 70 lb/hr emission rate for Huntington Unit 2.

2. Add an enforceable requirement to shut down Carbon Unit 1 and Carbon Unit 2 by April 15, 

2015.

3. Add enforceable BART conditions to Part H of the SIP to address EPA’s determination that the 

approval orders and operating permits for PacifiCorp’s Hunter and Huntington plants are not 

practicably enforceable. 

31
1

2

3

4 Utah State Implementation Plan

5

6 Section XX

7

8 Regional Haze

9

10

11 Addressing Regional Haze Visibility Protection for the Mandatory Federal Class I 

12 Areas Required Under 40 CFR 51.309

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36 Adopted by the Air Quality Board

37 [April 6, 2011]January 7, 2015

Page 1
1

Section XX - Regional Haze. Page 2

 
1

2 6. Best Available [Control]Retrofit Technology (BART) 

3 Assessment for NOx and PM.

4 a. Regional Haze Rule BART Requirements 

5 Pursuant to 40 CFR 51.309(d)(4)(vii), certain major stationary sources are required to 

6 evaluate, install, operate and maintain BART technology or an approved BART 

7 alternative for NOx and PM emissions. BART requirements can be addressed through a 

8 case-by-case review under 40 CFR 51.308(e)(1) or through an alternative program under 

9 40 CFR 51.308(e)(2). The State of Utah has chosen to evaluate BART for NOx and PM 

10 under the case-by-case provisions of 40 CFR 51.308(e)(1). BART for SO2 is addressed 

11 through an alternative program under 40 CFR 51.309 that is described in Part E of this 

12 plan.

13

14 EPA issued guidelines for BART determinations on July 6, 2005 that are codified in 

15 Appendix Y to 40 CFR Part 51. These guidelines establish a three step process.

16 • States identify sources which meet the definition of BART eligible 

17 • States determine which BART eligible sources are “subject to BART” 

18 • For each source subject to BART States identify the appropriate control 

19 technology. 

20

21 The determination of NOx limits for fossil-fuel fired power plants having a total 

22 generating capacity greater than 750 megawatts must be made pursuant to the guidelines 

in 40 CFR 51 Appendix Y, Section E.5. 1 23

24 b. BART-Eligible Sources. 

25 BART-eligible sources are those sources that fall within one of 26 specific source 

26 categories, were built during the 15-year window of time from 1962 to 1977, and have 

27 potential emissions of at least 250 tons per year of any visibility impairing air pollutant 

28 (40 CFR 51.301). Pursuant to 40 CFR 51.308 (e)(1)(i) a State is required to list all 

29 BART-eligible sources within the State.

30

31 Four BART-eligible electric generating units have been identified in the State of Utah: 

32 PacifiCorp’s Hunter Units 1 and 2 and Huntington Units 1 and 2. The units are located at 

33 fossil-fuel fired steam electric plants of more than 250 million Btu per hour heat input,

34 one of the 26 specific BART source categories. The units have potential emissions greater 

35 than 250 tons per year of a visibility impairing pollutant. The units had commenced 

36 construction within the BART time frame of August 7, 1962 to August 7, 1977. 

37

1 40 CFR Part 51 Appendix Y Guidelines for BART Determinations under the Regional Haze Rule (70 FR 

39158)

Page 3

 
1 Table 1. BART-Eligible Sources in Utah.

SOURCE

UNIT

ID

SERVICE 

DATE

NET 

DEPENDABLE 

CAPACITY 

(MWn)

BART 

CATEGORY COAL TYPE

BOILER 

TYPE

Hunter 1 1978 430 Fossil fuel fired Bituminous Tangential

Hunter 2 1980 430 Fossil fuel fired Bituminous Tangential

Huntington 1 1977 430 Fossil fuel fired Bituminous Tangential

Huntington 2 1974 430 Fossil fuel fired Bituminous Tangential

2 Note: Hunter Unit 3 commenced construction after 1977 and is therefore not BART3 eligible.

4 c. Sources Subject to BART

5

6 Pursuant to 40 CFR 51.308(e)(1)(ii) the State is required to determine which BART7 eligible sources are also “subject to BART.” BART-eligible sources are subject to BART 

8 if they emit any air pollutant that may reasonably be anticipated to cause or contribute to 

9 any impairment of visibility in any mandatory Class I Federal area. 

10

11 PacifiCorp’s Hunter Units 1 and 2 and Huntington Units 1 and 2 were determined by the 

12 State to be subject to BART. The State utilized the technical modeling services of the 

13 WRAP Regional Modeling Center (RMC). Modeling was performed according to the 

RMC modeling protocols2 14 . For the WRAP BART exemption screening modeling, the 

15 RMC followed the EPA BART Guidelines in 40 CFR 51, Appendix Y and the applicable 

16 CALMET/CALPUFF modeling guidance (e.g., IWAQM, 1998; FLAG, 2000; EPA, 

17 2003c) including EPA’s March 16, 2006 memorandum: “Dispersion Coefficients for 

Regulatory Air Quality Modeling in CALPUFF”.3 18

19

20 The basic assumptions of the WRAP BART CALMET/CALPUFF modeling protocols 

21 are as follows:

22 • Three years of modeling (2001, 2002 and 2003) were used.

23 • Visibility impacts due to emissions of SO2, NOx and primary PM emissions were 

24 calculated

25 • Visibility was calculated using the Original IMPROVE equation and Annual 

26 Average Natural Conditions.

27 • The effective range of CALPUFF modeling was set at 300km from the sources

28 • For pre-control modeling, maximum 24-hour average actual emissions from the 

29 Acid Rain database were used in CALPUFF model.

2 CALMET/CALPUFF Protocol for BART Exemption Screening Analysis for Class I Areas in the Western 

United States

3 Atkinson and Fox, 2006

Section XX - Regional Haze. Page 4

 

 
1 • For post-control modeling, expected New Source Review (NSR) permitted limits

2 were used in the CALPUFF model. 

3

4 According to 40 CFR Part 51, Appendix Y, a BART-eligible source is considered to 

5 “contribute” to visibility impairment in a Class I area if the modeled 98th percentile 

6 change in deciviews is equal to or greater than the “contribution threshold.” The State of 

7 Utah evaluated BART exemption screening modeling results at the EPA-suggested 

8 contribution threshold of 0.5 deciviews within a 300 Km radius of the BART-eligible 

sources.

4 9 BART-eligible sources Hunter Unit 1, Hunter Unit 2, Huntington Unit 1, and 

10 Huntington Unit 2 had a modeled impact greater than the threshold level of 0.5 change in 

11 deciviews in at least one of the seven Class I areas within a 300 km radius of the sources.

12

4 WRAP RMC BART Modeling for Utah Draft #6 April 21, 2007

Page 5

 
1 Figure 1. Relationship between Utah potential BART-eligible sources and Class I 

2 areas. Hunter Units 1 and 2 and Huntington Units 1 and 2 modeled separately at 

3 maximum 300 km.

4

5

6 Table 2. Subject to BART Modeling

Subject to BART Modeling - 98th Percentile 3 year average Delta Deciview

Capitol 

Reef Canyonlands Arches

Bryce 

Canyon Zion

Grand 

Canyon

Black 

Canyon 

Gunnison

Mesa 

Verde

Hunter 1 2.13 1.87 1.53 0.55 0.46 0.59 0.60 0.53

Hunter 2 1.89 1.62 1.36 0.47 0.41 0.52 0.53 0.47

Huntington 1 1.92 1.64 1.39 0.48 0.43 0.55 0.56 0.48

Huntington 2 2.43 2.26 1.89 .091 .078 .099 1.14 0.91

Section XX - Regional Haze. Page 6

 
1

2 d. BART [Determination]Analysis

3 As required under 51.308 (e)(1)(A) the determination of BART must be based on an

4 analysis of the best system of continuous emission control technology available. In the 

5 analysis the State must take in to account five factors:

6 • Available technology

7 • Costs of compliance

8 • Energy and non-air quality environmental impacts

9 • Existing control equipment and the remaining useful life of the facility

10 • The degree of improvement in visibility reasonably anticipated to result from 

11 the use of such technology

12

13 40 CFR Part 51 Appendix Y (Appendix Y) requires coal-fired electric generating plants 

14 of greater than 750 MW to meet BART presumptive limits. The four subject-to-BART 

EGUs meet the presumptive limit for SO2 and NOx as required by Appendix Y5 15 While 

16 EPA considers presumptive limits to be appropriate for all coal-fired power plants greater 

17 than 750 MW, the State may establish different requirements if the State can demonstrate 

18 that an alternative is justified based on a consideration of the five BART factors. 

19

20 “For Coal-fired EGU’s greater than 200 MW located at greater than 750 MW 

21 power plants and operating without post-combustion controls (i.e. SCR or 

22 SNCR), we have provided presumptive NOx limits, differentiated by boiler design 

23 and type of coal burned. You may determine that an alternative control level is 

24 appropriate based on careful consideration of the statutory factors.” (Appendix Y 

Part 51 – IV (E)(5)).6 25

26

27 In 2008 Utah determined that BART for NOx and PM was the emission rate established 

28 in approval orders for the subject-to-BART EGUs that met the presumptive BART 

29 emission rate established in Appendix Y. Utah relied on EPA’s extensive technical work 

30 that was developed to support the presumptive limits to meet the requirement for a 5-

31 factor analysis. PacifiCorp installed the control technology, as required, and significant 

32 emission reductions of SO2, NOx, and PM were achieved.

33

34

35

36

5 Utah developed an alternative to BART program for SO2 in Part E of this plan, however, the four subjectto-BART EGU’s also meet the presumptive BART limits for SO2 independently of the alternative 

program.

6

 70 Federal Register 39171

Page 7

 
1 Table 3. [Table 6.]Change in Actual Emissions (tons/yr) for Retrofitted Subject-to2 BART EGUs.

Unit PreControl

SO2

PreControl

NOx

PostControl 

SO2

PostControl 

NOx

Delta 

SO2

Delta 

NOx

Hunter 1 2,535 6,380 * * * * 

Hunter 2 2,531 6,092 1,529 3,412 -1,003 -2,680 

Huntington 1 2,380 5,944 1,033 3,593 -1,213 -2,352 

Huntington 2 12,308 5,816 1,168 3,844 -11,121 -1,973 

3

4 Note: Pre-control emissions 2001-2003 (2002 excluded for Huntington 2 due to partial operation), Post5 control emissions 2012-2013. The upgrades were completed on Hunter 1 in the Spring of 2014 therefore 

6 actual emissions are not yet available but should be comparable to Hunter 2. PM emissions are not 

7 comparable due to significant changes in reporting methodology.

8

9 On December 12, 2012, the EPA disapproved Utah’s BART determination for NOx and 

10 PM after concluding that EPA’s own technical analysis did not satisfy the 5-factor 

11 analysis requirement in the BART Rule. In June 2012 PacifiCorp provided a new 5-

12 factor analysis for each of the four subject to BART EGUs. On August 4, 2014 

13 PacifiCorp provided additional information to supplement that analysis.

14

15 The Division of Air Quality’s detailed review of the 5-factor analysis is included in the 

Technical Support Document.7 16 The currently installed baghouse technology is the most 

17 stringent technology available for control of particulate matter. The currently installed 

18 low-NOx burners with overfire air meet the presumptive BART emission rate established 

19 in Appendix Y and were cost-effective with an average cost of $307/ton. After carefully 

20 considering the 5 factors, post-combustion controls for NOx are not justifiable. 

21

22 Significant emission reductions (8,005 tons/yr SO2 and 3.342 tons/yr NOx) beyond those 

23 achieved through the installation of BART will occur due to the expected closure of 

24 PacifiCorp’s Carbon Plant in 2015. The Carbon Plant is located 30 miles northeast of the 

25 Huntington Plant and 40 miles northeast of the Hunter Plant and affects visibility in the 

26 same general area as the Hunter and Huntington Plants.

27

28

29

30

31

32

7 Utah Division of Air Quality, Staff Review of 2008 Best Available Retrofit Technology (BART) 

Determination, September 12, 2014.

Section XX - Regional Haze. Page 8

 

 
1 e. BART Determination

2 The State of Utah reaffirms the 2008 determination that the following retrofit control 

3 equipment at the Hunter Unit 1, Hunter Unit 2, Huntington Unit 1, and Huntington Unit 2 

4 EGUs is BART.

5

6 [PacifiCorp has installed or has received permits to install the following retrofit control 

7 equipment at the Hunter Unit 1, Hunter Unit 2, Huntington Unit 1, and Huntington Unit 2 

8 fossil fuel fired electric generating units (EGU):]

9

10 Hunter Units 1 and 2:

11 • Conversion of existing electrostatic precipitators to pulse jet fabric filter bag12 houses

13 • The replacement of existing, first generation low-NOx burners with Alstom TSF 

14 2000TM low-NOx firing system and installation of two elevations of separated 

15 overfire air.

16 • Upgrade of existing flue gas desulfurization system to > 90% sulfur dioxide 

17 removal.

18

19 Huntington Units 1 and 2:

20 • Conversion of existing electrostatic precipitators to pulse jet fabric filter bag21 houses

22 • The replacement of existing, first generation low-NOx burners with Alstom TSF 

23 2000TM low-NOx firing system and installation of two elevations of separated 

24 overfire air.

25 • Installation of a new wet-lime, flue gas de-sulfurization system at Unit 2 (FGD).

26 • Upgrade of existing flue gas desulfurization system to > 90% sulfur dioxide 

27 removal at Unit 1.

28

29 Carbon Units 1 and 2

30 • PacifiCorp shall retire Carbon Units 1 and 2 by April 15, 2015

31

32 The BART emission rates for NOx and PM are summarized in Table 6. While Utah has 

33 chosen to meet the SO2 BART requirement through an alternative to BART program 

34 established in Part E of this plan, the SO2 emission rate established in the approval orders 

35 for the four EGUs meets the presumptive SO2 emission rate established in Appendix Y 

36 independently of the alternative program. The enforceable BART emission limits and 

37 monitoring requirements are included in Section IX, Part H.21 and H.22 of the State 

38 Implementation Plan.

Page 9
1

2 Table 4. [Table 5.]Emissions Rates [(lb/MMBtu) ]for the Retrofitted Hunter and 

3 Huntington Units

4

5

6 Table 6. Change in Emissions (tons/yr) for Retrofitted BART Units

Unit PreControl

SO2

PreControl

NOx

PreControl

PM10

PostControl

SO2

PostControl 

NOx

PostControl

PM10

Delta 

SO2

Delta 

NOx

Delta 

PM10

Hunter 1 2741 6833 533 2239 4851 280 -502 -1981 -253

Hunter 2 2425 5922 533 2185 4734 273 -240 -1187 -260

Huntington 1 2538 5676 444 2052 4445 256 -486 -1231 -188

Huntington 2 13703 5582 443 1743 3776 218 -11960 -1806 -225

TOTALS 21,407 24,013 1,953 8,219 17,807 1,027 -13,189 -6,206 -926

7

8

9 Pursuant to 51.308(e)(1)(C)(iv) each source subject to BART is required to install and 

10 operate BART no later than 5 years after approval of the implementation plan. The 5-year 

11 deadline was met for all four units.[The PacifiCorp schedule for the four EGUs at 

12 Huntington and Hunter sources is as follows.] 

13

14

Source Notice of Intent 

Submitted

Permit Issued Estimated In 

Service Date

Hunter 1 June 2006 March 2008 Spring 2014

Hunter 2 June 2006 March 2008 Spring 2011

Huntington 1 April 2008 August 2009 Fall 2010

Huntington 2 October 2004 April 2005 Dec 2006

15

8 Utah Division of Air Quality Approval Orders: Huntington Unit 2 - AN0238012-05, Huntington Unit 1 -

DAQE-AN0102380019-09 (note – on January 19, 2010 an administrative amendment was 

made to the 2009 AO), Hunter Units I and 2 - DAQE-AN0102370012-08 

9 40 CFR Part 51 Appendix Y Guidelines for BART Determinations under the Regional Haze Rule (70 

Federal Register 39135)

Units

Utah [Permitted Rates]BART 

Emission Rate8 Presumptive BART Limits9

Rate: lb/MMBtu

SO2

lb/MMBtu

NOx

lb/MMBtu PM lb/MMBtu

SO2

lb/MMBtu

NOx

lb/MMBtu

Hunter 1 0.12 0.26 0.015 0.15 0.28

Hunter 2 0.12 0.26 0.015 0.15 0.28

lb/hr

Huntington 1 0.12 0.26

[0.05]

74 (PM10) 0.15 0.28

Huntington 2 0.12 0.26 [0.05]70 0.15 0.28

Section XX - Regional Haze. Page 10

 

 
1 [EPA under the BART Rule requires coal-fired electric generating plants of greater than 

2 750 MW to meet BART presumptive limits. While EPA considers presumptive limits to 

3 be appropriate for all coal-fired power plants greater than 750 MW, the State may 

4 establish different requirements if the State can demonstrate that an alternative is justified 

5 based on a consideration of the five BART factors. 

6

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

8 MW power plants to meet these BART emission limits... a State may establish 

9 different requirements if the State can demonstrate that an alternative 

determination is justified based on a consideration of the five statutory factors.”10 10

11

12 “For Coal-fired EGU’s greater than 200 MW located at greater than 750 MW 

13 power plants and operating without post-combustion controls (i.e. SCR or 

14 SNCR), we have provided presumptive NOx limits, differentiated by boiler design 

15 and type of coal burned. You may determine that an alternative control level is 

16 appropriate based on careful consideration of the statutory factors.” (Appendix Y 

Part 51 – IV (E)(5).11 17

18

19 EPA determined presumptive limits for SO2 and NOx for EGUs based on a methodology 

20 equivalent to that required in 50 CFR 51 Appendix Y for BART Rule. The EPA 

21 determination of presumptive limits included: 

22 • Identification of all potential BART-eligible EGUs (all BART-eligible 

23 EGU’s were assumed to be Subject to BART)

24 • Technical analyses and industry research to determine applicable and 

25 appropriate SO2 and NOx control options, 

26 • Economic analysis to determine cost effectiveness for each potentially 

27 BART-eligible EGU

28 • Evaluation of historical emissions and forecast emission reductions for 

each potentially BART-eligible EGU12 29 . 

30 • NOx and SO2 CALPUFF modeling of emission impacts at model Class I 

31 area. 

32

33 The analysis included 491 potential BART EGUs including Hunter Units 1 and 2 

34 and Huntington Units 1 and 2. The technical analysis conducted by EPA to 

35 determine presumptive BART limits for SO2 and NOx is in effect a BART 

10 Ibid. (70 Federal Register 39131).

11 70 Federal Register 39171 

12 Ibid. (70 Federal Register 39134)

Page 11

 
1 determination analysis for 419 EGUs including Hunter Units 1 and 2 and 

Huntington Units 1 and 2.

13 2

3

4 Section IV (E) (5) of Appendix Y Part 51 clearly requires the implementation of 

5 presumptive NOx limits for coal-fired EGU’s greater than 200 MW located at greater 

6 than 750 MW power plants. Under Appendix Y, states are given the discretion to 

7 challenge presumptive limits through a five factor analysis, but presumptive limits were

8 developed by EPA as a reasonable, equivalent and mandated substitution for a five factor 

analysis.

14 9 

10 ]

11 Utah’s long-standing Prevention of Significant Deterioration (PSD) permitting program 

12 (SIP Section VII and R307-405), New Source Review permitting program (SIP Section II 

13 and R307-401) and Visibility program (SIP section XVII and R307-406) will continue to 

14 protect Class I area visibility by ensuring that the BART emission rates established in Part 

15 H.21 and H.22 of this plan are maintained, requiring best available control technology for 

16 new sources, and assuring that there is not a significant degradation in visibility at Class I 

17 areas due to new or modified major sources.

13 “Methodology for Developing BART NOx Presumptive Limits” EPA Clean Air Market Division June 

15, 2005 HQ-OAR-2002-0076-0445 and “Technical Support Document for BART NOx Limits for 

Electric Generating Units Excel Spreadsheet, Memorandum April 15, 2005 HQ-OAR-2002-0076-0369 

14 CFR Part 51 Appendix Y Guidelines for BART Determinations under the Regional Haze Rule (70 

Federal Register 39171)

Section XX - Regional Haze. Page 12

 

 
Page 1 of 5

SIP Section IX.H.21 and 22

1

Utah State Implementation Plan 

Emission Limits and 

Operating Practices 

Section IX, Part H

Adopted by the Air Quality Board

[December 3, 2014]January 7, 

2015 
Page 

2 of 5

SIP Section IX.H.21 and 22

1
Page 3 of 5

SIP Section IX.H.21 and 22

1

2 H.21. General Requirements: Control Measures for Area and Point Sources, 

3 Emission Limits and Operating Practices, Regional Haze Requirements

4

5 a.Except as otherwise outlined in individual conditions of this Subsection IX.H.21 listed below, the 

6 terms and conditions of this Subsection IX.H.21 shall apply to all sources subsequently 

7 addressed in Subsection IX.H.22. Should any inconsistencies exist between these two 

8 subsections, the source specific conditions listed in IX.H.22 shall take precedence.

9 b.The definitions contained in R307-101-2, Definitions, apply to Section IX, Part H.

10 c.Any information used to determine compliance shall be recorded for all periods when the source 

11 is in operation, and such records shall be kept for a minimum of five years. Any or all of these 

12 records shall be made available to the Director upon request.

13 d.All emission limitations listed in Subsections IX.H.22 apply during steady-state operation, unless 

14 otherwise specified in the source specific conditions listed in IX.H.22.

15 e.Stack Testing:

16 i. As applicable, stack testing to show compliance with the emission limitations for the sources 

17 in Subsection IX.H.22 shall be performed in accordance with the following:

18 A. Sample Location: The testing point shall be designed to conform to the requirements of 

19 40 CFR 60, Appendix A, Method 1, or other EPA-approved methods acceptable to the 

20 Director.

21 B. Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or other EPA-approved 

22 testing methods acceptable to the Director.

23 C. Particulate (PM): 40 CFR 51, Appendix M, Method 5B, or other EPA approved testing 

24 methods acceptable to the Director. The back half condensibles shall also be tested using 

25 Method 202. The back half condensibles shall not be used for compliance demonstration 

26 but shall be used for inventory purposes.

27 D. Calculations: To determine mass emission rates (lb/hr, etc.) the pollutant concentration as 

28 determined by the appropriate methods above shall be multiplied by the volumetric flow 

29 rate and any necessary conversion factors to give the results in the specified units of the 

30 emission limitation.

31 E. A stack test protocol shall be provided at least 30 days prior to the test. A pretest 

32 conference shall be held if directed by the Director. 

33 f. Continuous Emission and Opacity Monitoring.

34 i. For all continuous monitoring devices, the following shall apply:

35 A. Except for system breakdown, repairs, calibration checks, and zero and span adjustments 

36 required under paragraph (d) 40 CFR 60.13, the owner/operator of an affected source 

37 shall continuously operate all required continuous monitoring systems and shall meet 

38 minimum frequency of operation requirements as outlined in R307-170 and 40 CFR 

39 60.13.

40 B. The monitoring system shall comply with all applicable sections of R307-170; 40 CFR 

41 13; and 40 CFR 60, Appendix B – Performance Specifications.
Page 4 of 5

SIP Section IX.H.21 and 22

1 H.22. Source Specific Emission Limitations: Regional Haze Requirements, 

2 Best Available Retrofit Technology

3

4 a.PacifiCorp Hunter

5

6 i. Particulate Limitations on Units #1 and #2

7

8 A. Emissions of particulate (PM) shall not exceed 0.015 lb/MMBtu heat input from each 

9 boiler based on a 3-run test average. 

10

11 B. Stack testing for the emission limitation shall be performed each year on each boiler. 

12

13 ii. NOx Limitations on Units #1 and #2

14

15

16 A. Emissions of NOx from each boiler shall not exceed 0.26 lb/MMBtu heat input for a 30-

17 day rolling average.

18

19 B. Measuring of all NOx emissions shall be performed by CEM.

20
Page 5 of 5

SIP Section IX.H.21 and 22

1

2 b.PacifiCorp Huntington

3

4 i. Conditions on Boiler Unit #1

5

6 A. Emissions of PM10 shall not be greater than 74 lb/hr.

7

8 B. Stack testing to show compliance with the PM10 emission limitation shall be performed 

9 each year.

10

11 C. Emissions of NOx shall be no greater than 0.26 lb NOx/MMBtu heat input (1,290 lb/hr) 

12 on a 30-day rolling average.

13

14 D. Measuring of all NOx emissions shall be performed by CEM.

15

16 ii. Conditions on Boiler Unit #2

17

18 A. Emissions of particulate matter (PM) from Boiler Unit #2 shall not be greater than 70 

19 lb/hr.

20

21 B. Stack testing to show compliance with the PM emission limitation shall be performed 

22 each year.

23

24 C. Emissions of NOx shall be no greater than 0.26 lb/MMBtu heat input on a 30-day rolling 

25 average.

26

27 D. Measuring of all NOx emissions shall be performed by CEM.