## State of Utah

GARY R. HERBERT Governor

SPENCER J. COX Lieutenant G overnor 

### 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 1 6 , 2014

SUBJECT: PROPOSE FOR PUBLIC COMMENT: Amend Utah S IP . Section XX .D.6

. Regi onal Haze . L ong

- 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 O perating 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 R egional H aze SIP (RH SIP), but disapproved Utah’s b est a vailable r etrofit t echnology (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 o f 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 iss ues 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 Ci ty, U tah Mailing Address: P.O. Box 1448 2 0 • Salt Lake City, U tah 84114

- 48 2 0 Telephone (801) 53 6

- 4 0 00 • Fax (801 ) 536

- 4099 • T.D.D. (801) 536

- 4414 www.deq.utah.gov Printed on 100% recycled paperDAQ

- 086

- 14 Page 2

Sta ff 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 B est A vailable R etrofit

T echnology (BART) Determination

September 1 2 , 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 SO 2 , NO x , and PM Established as BART in 2008

................................ ................. 6
Energy and Non

- Air Quality Envi ronmental Impacts

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

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

................................ ................................ ................................ ................................ ... 6

Visib ility 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. S O 2 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. SO 2 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. Sulfat e 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, wa s based on the Recommendations of the Grand Canyon Visibility Transport Commission (GCVTC). The GCVTC e valuated haze at Class I Areas on the Colorado Plateau, and determined that stationary source reductions should
be focused on sulfur dioxide (SO 2 ) because it is the pollutant that has the most significant impact on
haze on the Colorado Plateau . Utah’s BAR T determination was developed within the context of the
overall SIP and reflected this focus on SO 2 . Figure 1 shows the contributions of various species to visibility impairment at Canyonlands National Park. As can be seen, sulfate (ammSO4) is the most

s ignificant contributor to haze . Fire ( OMC ) and dust (CM) are also a significant component s but the impact is variable from year to year

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

Utah’s 2003 RH SI P included SO 2 emission milestones with a backstop regulatory trading program to
ensure that SO 2 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 SO 2 emission s 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 Figu re 2).

1Figure 2 . SO 2 Milestones and Emission Trends

While Utah’s RH SIP is focused on achieving SO 2 reductions from stationary sources, substantial
reductions in nitrogen oxide ( NOx ) emissions will also occur . Figure 3 shows th e projected decrease in
NOx emissions between 2002 and 2018 as document ed 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 Bo ard adopted a revision to Utah’s RH SIP to include Best Available Retrofit Technology (BART) requirements for NO x 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 Hunti ngton Unit 2 fossil fuel fired electric generating units (EGU s ) were determined to be subject to BART. The 2008
RH SIP required PacifiCorp to install the following BART controls at these EGU s :

Hunter Units 1 and 2:

• Conversion of existing electrostatic pre cipitators to pulse jet fabric filter bag

- houses

• The replacement of existing, first generation low

- NO x burners with Alstom TSF 2000TM low

NO x firing system and installation of two elevations of separated overfire air.

• Upgrade of existing flue gas desulfuri zation 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 gener ation low

- NO x burners with Alstom TSF 2000TM low

- NO x 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.

T h e 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 SO 2 and NO x established in 40 CFR Part 51 Appendix Y, Guidelines for BART Determinations under the Regional Haze Rule as shown in Table 1

. ( Note, T able 1 corrects a typo graphical error in Table 5 of the RH SIP where the permitt ed 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. )

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

Units Utah Permitted Rates 1 Presumptive BART Limits 2

Rate: lb/MMBtu SO 2 NOx PM SO 2 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 NO x as the appropriate benchmark to determine whether the BART requirement had been met

. E PA had completed extensive technical
work for all EGUs in the country to develop presumptive limits for NO x , now codified in Appendix Y 3

, and
the Utah SIP referenced this technical work to meet the requirement to conduct a 5

- factor BART analysis
for NO x , a s 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 tech nical 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 b aghouse

, 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

. Th is rule was adopted in 2007 and was designed to work in conjunction with EPA’s 2005 Clean Air Mercury Rule (CAMR) to reduce mercury emission s both nationally and locally. Mercury was a concern in Utah due to e levated

1 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 amendme nt 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 BAR T Determinations under the Regional Haze Rule (70 Federal Register 39135)

3 40 CFR Part 51, Appx Y, Table 1, Presumptive NO x Emission Limits for BART

- Eligible Coal

- Fired Units, note 20,

says:
These [presumptive NO x ] limits reflect the design and technologi cal assumptions discussed in the technical support document for NO x limits for these guidelines. See Technical Support Document for
BART NO x Limits for Electric Generating Units and Technical Support Document for BART NO x Limits for Electric Generating Uni ts Excel Spreadsheet, Memorandum to Docket OAR 2002

– 0076, April 15, 2005.

4mercury 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 Enviro nmental 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 SO 2 , 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 r ule, 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
du e 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
Not e: 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 ana lysis 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 de termined 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

5prior to EPA’s proposed disapproval, and were installed on the 4 th 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 ha d 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 SO**  **2** 

## , NO **x**



## , and PM **Established as BART in 2008** 

**Energy and Non**

**- Air Quality Environmental Impacts**  PacifiCorp determined that installati on 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 analys is, DAQ staff consider s 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.

**Remaini ng 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 SO 2 , 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 $5 8 8
, 436
, 552 4 . When operating costs we re included, the total annualized cost of the new
controls was $7 0
, 8 47, 852 /year. Focusing specifically on NOx, 1 1
, 480 tons of NOx were reduced from the 4 subject

- to

- BART EGUs with an average cost of $ 3 07 /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.

**V isibility**  **benefit**

Early R eductions 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
SO 2 milestones established steady and co ntinuing 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 SO 2 and PM controls on 3 of the 4 EGUs and estimated costs for Hunter 1. Costs for NOx controls were updated August 5, 2014.

6and since that time

, SO 2 emissions have continued to decrease. The NOx and PM reductions re quired 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 visibilit y 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 PacifiC orp performed visibility modeling as outlined in the June 2012 modelin g 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.

T he model indicates significant visibility improvement due to the new controls for SO 2 , NOx, and PM as required by t he 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 Can yonlands 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 Hunte r 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)

.

7Figure 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 contr ols have been installed on 3 of the 4 units since 2011 , monitoring data can also be used to
validate the actual benefit achieved . C ontrols 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 SO 2 and NOx from the 4 subject

- to

- BART
EGUs.

8Figure 5 . SO 2 Emission Trends

Figure 6 . NOx Emission Trends

9DAQ staff evaluated the monitoring data using several different metrics. First, the overall trend in deciviews and the contribution of individual s pecies to light extinction during the 20% worst and 20% best days at Canyonlands w ere evaluated

. Canyonlands was chosen because the highest overall modeled impacts occurred at Canyonlands. Th e 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 imp rovement 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

10DAQ staff also evaluated changes in the individual species that contribute to visibility impairment. T he
98 th percentile (3 rd 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 SO 2

an d 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

11Figure 9 . Ni trate Trends

Ammonia
Sur prisingly, 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 unexpec ted result may occur because ammonium sulfate forms more readily than ammonium nitrate when both SO 2 and NOx are available to react with
ammonia

. A s SO 2 emissions decline and SO 2 is no longer available, the reaction shifts to form
ammonium nitrate from av ailable NOx . Figure 10 show s the nitrate and sulfate mass on the 98 th percentile (3 rd 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 SO 2 and NOx emissions may not lead to visibility improvements under
ammonia limited conditions.

12Figure 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 th ere were seasonal differences. Figure 11 shows that the decreas es 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 o f ammonium sulfate (NH4)2SO4 that was decreased

. D uring the

summer sulfate, nitrate, and ammonium are all decreas ing, indicating that ammonia is not limiting the
reaction

.

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

14DAQ 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. Pac ifiCorp 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 identifie d as a regional background site during a 2007 study of ammonia emissions in New Mexico and Oklahoma 5

. The shaded bands highlight the winter months of Dec ember

– February and as can be seen the ammonia values during the winter are typically much lower tha n 1 ppb

.
Figure 12 . Ammonia Trends

DAQ agree d that ammonia rates are likely lower in the winter, but the data set wa s so sparse that it wa s difficult to determine the appropriate levels that should be used. The Navajo Lake sit e is about 250 miles from the PacifiCorp EGUs and the only other monitoring sites in Utah we re affected by urban emissions or agriculture. Ammonia emission sources are primarily livestock, agriculture , and human populations in urban areas and there are fe w 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 Sat her et al., Baseline ambient gaseous ammonia concentrations in the Four Corners area and eastern Oklahoma, USA, J.Environ. Monit ., 2008, 10 , 1319

- 1325

15sta tes. 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 ppb 6 so the model may be overpredicting the formation o f 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 1 2 shows t hat t he initial few measurements at Canyonlands are similar to values at Navajo Lake

. T he 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 IMP ROVE 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 i n 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 Sou rce Attribution Visibility Impairment Modeling Analysis for Public Service Company of Colorado Hayden Station Units 1 and 2, November 1 2005, page 31.

16Other NOx Emission Sources DAQ staff also evaluated the possibility that NOx could be in creasing from other sources in the region. Figure 1 4 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 co ntinue to be reduce d through the implementation of Tier 3 emission standards

.
Figure 14 . NOx Emission Trends from EGUs

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

sca le 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

17Other Modeling Considerations DAQ staff cons idered several other reasons why the model might indicate a greater improvement in visibility tha n is measur ed by the monitoring data.

1. The modeling protocol uses conservative assumptions. The model assumes background
“natural conditions” while curre nt 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 a chieving 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 conditi ons 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 versi on 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). T herefore, 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 o f 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 5 th 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 moni toring
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 ma y use to determine visibility impacts for the BART
determination 7 ” 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

su pport 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

18determining 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 **Co ntrol Options** 
PacifiCorp’s 5

- Factor analysis identified three technologies that were available prior to the 2 008 BART determination: upgraded electrostatic precipitator (ESP) and flue gas conditioning (0.040 lb

PM 10 /MMBtu); polishing fabric filter (0.015 lb PM10/MMBtu); and replacement fabric filter (0.015 lb

PM 10 /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 PM 10 emission rate of 74 lb/hr a t 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 PM 10 /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 ha s 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 an alysis 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 stringen t 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 10 of 0.015 lb/MMBtu (30 day rolling average) no further analysis is required.

9 70 FR 39129

19

## Analysis of N **Ox Control Options** 
PacifiCorp evaluated 18 different NOx control options, and determined that the following were technically feasible 10 : low NOx burners and overfire air (LNB + OFA

– option required by 2008 BART determination), selective non

- catalytic redu ction ( 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 H untington 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 SC R 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.

20perceived v isibility 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 concer n 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, t he 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 sceni c 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) P olicy S tatement for the P rotection of V isibility

“ 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, bot h 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 Sheet s for S NCR (EPA

- 452/F

- 03

- 031) and SCR (EPA

- 452/F

- 03

- 032)
indicate s 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
i nstalled 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 co ntrol 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
Hunti ngton

. **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 Em ission 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 e stablishes 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 l ife beginning in 2020. The objectives of the [Clean Power Plan] rule must be reconciled with EPA’s required approach to BART

21determinations 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 assumpti ons case aside by the [Clean Power Plan] rule requirements. PacifiCorp requests that Utah c onsider 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 agree s that the current uncertainty regarding future requirements u nder 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 SO 2 NAAQS and the expected new 2015 ozone NAAQS
are ad ditional areas of uncertai nty.

**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.

2 2Table 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 Red uction (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 fact or, 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

- data

computation_1.xlsx ) demonstrates that a 70% redi spatch 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 Uta h could decrease by as much as one quarter under
Block 2. As a n 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 ) t o 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

uppe r end

.

23Table 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 Powe r 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 E PA 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 capac ity will be subject to the
installation of cont rols 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 u nits 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 the ir 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 t hat
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 lo ngest 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

24Carbon 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 SO 2 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 SO 2 and NOx due to the closure of t his plant will be equivalent to the NOx reductions that could be achieved by installing the most stringent NOx control, SCR, on the 4 subject

- to

BART EGUs and the emission reductions will occur close to the location of the Hunter and Huntington plants

. Th e SO 2 emission reductions from the closure of this plant will be in addition to what was required under the SO 2 milestones in Utah’s SIP because regional emissions in 2011 and 2012 were already below the 2018 milestone target

.
While PacifiCorp has announc ed 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.

**V isibility**  **Impact** PacifiCorp’s 2012 modeling showed a n improvement in visibility impact due to the installation of either
SNCR or SCR (Table 8)

. Figure 1 5 show s how the improved days are distributed through the year (results

ar e shown for Huntington 2 , s imilar results are seen for the other 3 units )

.

Tabl e 8 . Modeled Visibil i ty 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

25Figure 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 remodeli ng 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 un its 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 p ublic
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 visibilit y which may reasonably be anticipated to result from the use of different technologies

.

**Seasonal Differences**
S ulfate is a problem year round, while the nitrate impact is most significant during the winter months when visitation is low at Utah’s national p arks, as can be seen in Figure 1 6

. 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 SO 2 reductions because sulfates are a problem year round and sulfates are overall the most significant anthropogenic contributor to
haze on the Colorado Plateau.

26Figure 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 tha t 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 tightenin g the standard

.

• 2016, p lan required to reduce carbon emission from existing power plants under EPA’s proposed Clean Power Plan.

• 2017

- 2019, Source

- specific SO 2 monitoring is required under the proposed SO 2 data requirements rule to determine attainment sta tus 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 visibili ty conditions by 2064. W hile 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 achieve d from all significant emission sources in Utah. The first planning period was focused on SO 2 reductions. DAQ anticipates that NOx reductions will be important in the next planning period to address the dual requirements of reasonable progress
towards th e 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

Hun ter 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 alternativ e 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 subje ct 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 a ll 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 contro ls 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 SO 2 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.

28The 5

- factor analysis provides information ab out 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 applicati on 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 l evel 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 determi nation. The
State makes a BART determination based on the estimates available for each criteri on, and as the CAA does not spe cify how the State should take these factors into account, the States are free to determine the weight and significance to be assi gned 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 alrea dy 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 the refore the cost/benefit analysis must focus on the
increment al 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

. I t 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 l evel 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 $8,79 4/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

29When considering the second as pect 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 SO 2 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 BAR T

. ” Four aspects of visibility improvement were
considered equally :

1) T he results of the CALPUFF visibility modeling that estimated a significant visibility improvement , using conservative assumptions (natural conditions, highest emission rate, 98 th

per centile impact)

.
2) T he results of the regional modeling conducted by the WRAP and referenced in Section K of
Utah’s RH SIP that show s a more modest improvement despite significant regional emission
reductions.

3) T he monitoring data that do not show v isibility improvement at Canyonlands on high nitrate days during the months of December

– February

. The significant reductions in both SO 2 and
NOx that have already occurred due to the 2008 BART determination have resulted in a shift
from sulfate to nitra te during the winter at Canyonlands rather than a decrease in total aerosols

.
4) T he 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 f ocused on SO 2 , 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 rul e , as proposed, significantly affect s 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 ” w ould increase the annualized cost in the

num erator while lower utilization would decrease the emission reductions in the denominator leading

to a n 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 sign ificant 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 ha ze 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 emissio n 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 

# Utah State Implementation Plan 4

5 

# Section XX 6

7 

# Regional Haze 8

9 10 Addressing Regional Haze Visibility Protection for the Mandatory Federal Class I 11 Areas Required Under 40 CFR 51.309 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 Adopted by the Air Quality Board 36 [ April 6, 2011 ] Januar y 7, 2015 37

Page 1

### 1

Section XX

- Regional Haze. Page 2

### 1



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

## A ssessment for NO x 

## and PM

. 3



## a. R egional H aze Rule BART Requirements 4
Pursuant to 40 CFR 51.309(d ) (4 ) (vii), certain major stationary sources are required to 5 evaluate, install, operate and mainta in BART technology or an approved BART 6 alternative for NO x 

### and PM emissions. BART requirements can be addressed through a 7

case

- by

- case review under 40 CFR 51.308(e ) (1) or through an alternative program under 8 40 CFR 51.308(e ) (2). The State of Utah has chos en to evaluate BART for NO x 

### and PM 9 under the case

- by

- case provisions of 40 CFR 51.308(e)(1). BART for SO 2 

### is addressed 10 through an alternative program under 40 CFR 51.309 that is described in Part E of this 11 plan. 12 13 EPA issued guidelines for BART determinati ons on July 6, 2005 that are codified in 14 Appendix Y to 40 CFR Part 51. These guidelines establish a three step process

. 15

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

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

• For each source subject to BART State s identif y the appropriate control 18 technology. 19 20 The determination of NO x 

### limits for fossil

- fuel fired power plants having a total 21 generating capacity greater than 750 megawatts must be made pursuant to the guidelines 22 in 40 CFR 51 A ppendix Y

, Section E.5

. 1 

### 23



## b. BART

- Eligible Sources. 24

BART

- eligible sources are those sources that fall within one of 26 specific source 25 categories, were built during the 15

- year window of time from 1962 to 1977

, and have 26 potential emissions of at least 250 tons per year of any visibility impairi ng air pollutant 27 (40 CFR 51.301). Pursuant to 40 CFR 51.308 (e)(1) (i) a State is required to list all 28 BART

- eligible sources within the State. 29 30 Four BART

- eligible electric generating units have been ident ified in the State of Utah: 31 PacifiCorp’s Hunter Units 1 and 2 and Huntington Units 1 and 2 . The units are located at 32 fossil

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

, 33 one of the 26 specific BART source categories. The units have potential emissions greater 34 than 250 tons per year of a visibility impairing pollutant. The units had commenced 35 construction within the BART time frame of August 7, 1962 to August 7, 1977. 36 37

1 40 CFR Part 51 Appendix Y Guidelines for BART Determinations under the Regional Haze Rule (70 FR 39158)



### Page 3

### Table 1 . BART

- Eligible Sources in Utah. 1

SOURCE UNIT ID SERVICE DATE NET DEPENDABLE

CAPACITY (MW n ) 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 Fo ssil fuel fired Bituminous Tangential Huntington 2 1974 430 Fossil fuel fired Bituminous Tangential 

### Note: Hunter Unit 3 commenced construction after 1977 and is therefore not BART

2 eligible. 3



## c. Sources Subject to BART 4

5 Pursuant to 40 CFR 51.308(e)(1) (ii) t he State is required to determine which BART

6 eligible sources are also “subject to BART

. ” BART

- eligible sources are subject to BART 7 if they emit any air pollutant that may reasonabl y be anticipated to cause or contribute to 8 any impairment of visibility in any mandatory Class I Federal area. 9 10 PacifiCorp’s Hunter Units 1 and 2 and Huntington Units 1 and 2 were determined by the 11 State to be subject to BART. The State utilized the technical modeling services of the 12 WRAP Regional Modeling Center (RMC). Modeling was performed according to the 13 RMC modeling protocols 2 

### . For the WRAP BART exemption screening modeling, the 14 RMC followed the EPA BART Guidelines in 40 CFR 51, Appendix Y and the applicable 15 CALMET/CALPUFF modeling guidance (e.g., IWAQM, 1998; FLAG, 2000; E PA, 16 2003c) including EPA’s March 16, 2006 memorandum: “Dispersion Coefficients for 17 Regulatory Air Quality Modeling in CALPUFF”. 3 

### 18 19 The basic assumptions of the WRAP BART CALMET/CALPUFF modeling protocols 20 are as follows: 21

• T hree years of modeling ( 2001, 2002 a nd 2003 ) were used

. 22

• Visibility impacts due to emissions of SO 2 

### , NO x 

### and primary PM emissions were 23 calculated 24

• Visibility was calculated using the Original IMPROVE equation and Annual 25 Average Natural Conditions. 26

• The effective range of CALPUFF modeling wa s se t at 300km from the sources 27

• For pre

- control modeling

, maximum 24

- hour average actual emission s from the 28 Acid Rain database were used in CALPUFF model

. 29

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

### • For post

- control modeling

, expected New Source Review (NSR) permitted limits 1 were used in the CAL P UFF mod el. 2 3 According to 40 CFR Part 51, Appendix Y, a BART

- eligible source is considered to 4 “contribute” to visibility impairment in a Class I area if the modeled 98th percentile 5 change in deciviews is equal to or greater than the “contribution threshold.” T he State of 6 Utah evaluated BART exemption screening modeling results at the EPA

- suggested 7 contribution threshold of 0.5 dec i view s within a 300 Km radius of the BART

- eligible 8

sources. 4 

### BART

- eligible sources Hunter Unit 1, Hunter Unit 2, Huntington Unit 1, a nd 9 Huntington Unit 2 had a modeled impact greater than the threshold level of 0.5 change in 10 dec i views in at least one of the seven Class I areas within a 300 km radius of the sources. 11 12

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



### Page 5

### Figure 1 . Relationship between Utah potential BART

- eligible sources and Class I 1 areas. Hunter Units 1 and 2 and Huntington Units 1 and 2 modeled separately at 2 maximum 300 km. 3 4 5 Table 2 . Subject to BART Modeling 6 Subject to BART Modeling

- 98th Percent ile 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



## d. BART [ Determination ] Analysis 2 As required under 51.308 (e)(1) (A) the determinat ion of BART must be based on an 3 analysis of the best system of continuous emission contr ol technology available. In the 4 analysis the State must take in to account five factors: 5

• Available technology 6

• Costs of compliance 7

• Energy and non

- air quality environmental impacts 8

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

• The degree of improvement in visibility reasonably anticipated to result from 10 the use of such technology 11 12 40 CFR Part 51 Appendix Y (Appendix Y) requires coal

- fired electric generating plants 13 of greater than 750 MW to meet BART presumptive limits. The four s ubject

- to

- BART 14 EGUs meet the presumptive limit for SO 2 

### and NOx as required by Appendix Y 5 

### While 15 EPA considers presumptive limits to be appropriate for all coal

- fired power plants greater 16 than 750 MW, the State may establish different requirements if the S tate can demonstrate 17 that an alternative is justified based on a consideration of the five BART factors. 18 19 “For Coal

- fired EGU’s greater than 200 MW located at greater than 750 MW 20 power plants and operating without post

- combustion controls (i.e. SCR or 21 SN CR), we have provided presumptive NOx limits, differentiated by boiler design 22 and type of coal burned. You may determine that an alternative control level is 23 appropriate based on careful consideration of the statutory factors.” (Appendix Y 24 Part 51

– IV (E) (5)). 6 

### 25 26 In 2008 Utah determined that BART for NOx and PM was the emission rate established 27 in approval orders for the subject

- to

- BART EGUs that met the presumptive BART 28 emission rate established in Appendix Y. Utah relied on EPA’s extensive technical wor k 29 that was developed to support the presumptive limits to meet the requirement for a 5

- 30 factor analysis. PacifiCorp installed the control technology, as required, and significant 31 emission reductions of SO 2 

### , NOx, and PM were achieved. 32 33 34 35 36

5 Utah developed an alternative to BART program for SO 2 in Part E of this plan, however, the four subject

to

- BART EGU’s also meet the presumptive BART limits for SO 2 independently of the alternative
program.

6 70 Federal Register 39171



### Page 7

### Table 3

. [ Table 6. ] Change in Actual Emissions (tons/yr) for Retrofitted Subject

- to

1 BART EGUs. 2 Unit Pre

Control SO 2 Pre

Control NO x Post

Control SO 2 Post

Control NO x Delta SO 2 Delta NO x

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
Note: Pre

- control emissions 2001

- 2003 (2002 excluded for Huntington 2 due to partial operati on), Post



### 4 control emissions 2012

- 2013. The upgrades were completed on Hunter 1 in the Spring of 2014 therefore 

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

### 6 comparable due to significant changes in repo rting methodology. 

### 7 8 On December 12, 2012, the EPA disapproved Utah’s BART determination for NOx and 9 PM after concluding that EPA’s own technical analysis did not satisfy the 5

- factor 10 analysis requirement in the BART Rule. In June 2012 PacifiCorp provided a new 5

- 11 factor analysis for each of the four subject to BART EGUs. On August 4, 2014 12 PacifiCorp provided additional information to supplement that analysis. 13 14 The Division of Air Quality’s detailed review of the 5

- factor analysis is included in the 15 Technic al Support Document. 7 

### The currently installed baghouse technology is the most 16 stringent technology available for control of particulate matter. The currently installed 17 low

- NOx burners with overfire air meet the presumptive BART emission rate established 18 in Appendix Y and were cost

- effective with an average cost of $307/ton. After carefully 19 considering the 5 factors, post

- combustion controls for NOx are not justifiable. 20 21 Significant emission reductions (8,005 tons/yr SO 2 

### and 3.342 tons/yr NOx) beyond th ose 22 achieved through the installation of BART will occur due to the expected closure of 23 PacifiCorp’s Carbon Plant in 2015. The Carbon Plant is located 30 miles northeast of the 24 Huntington Plant and 40 miles northeast of the Hunter Plant and affects visibi lity in the 25 same general area as the Hunter and Huntington Plants. 26 27 28 29 30 31 32

7 Utah Division of Air Quality, Staff Review of 2008 Best Available Retrofit Technology (BART) Determination, September 1 2 , 2014.



### Section XX

- Regional Haze. Page 8

## e. BART Determination 1 The State of Utah reaffirms the 2008 determination that the following retrofit control 2 equipment at the Hunter Unit 1, Hunter Unit 2, Huntington Unit 1, and Hunting ton Unit 2 3 EGUs is BART. 4 5 [ PacifiCorp has installed or has received permits to install the following retrofit control 6 equipment at the Hunter Unit 1, Hunter Unit 2, Huntington Unit 1, and Huntington Unit 2 7 fossil fuel fired electric generating units (EGU): ] 8 9 Hunter Units 1 and 2: 10

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

11 houses 12

• The replacement of existing, first generation low

- NO x 

### burners with Alstom TSF 13 2000TM low

- NO x 

### firing system and installation of two elevations of separated 14 overfire air. 15

• Upgrade of existing flue gas desulfurization system to > 90% s ulfur dioxide 16 removal. 17 18 Huntington Units 1 and 2: 19

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

20 houses 21

• The replacement of existing, first gener ation low

- NO x 

### burners with Alstom TSF 22 2000TM low

- NO x 

### firing system and installation of two elevations of separated 23 overfire air. 24

• Installation of a new wet

- lime, flue gas de

- sulfurization system at Unit 2 (FGD). 25

• Upgrade of existing flue gas desu lfurization system to > 90% s ulfur dioxide 26 removal at Unit 1. 27 28 Carbon Units 1 and 2 29

• PacifiCorp shall retire Carbon Units 1 and 2 by April 15, 2015 30 31 The BART emission rates for NOx and PM are summarized in Table 6. While Utah has 32 chosen to meet the SO 2 

### BAR T requirement through an alternative to BART program 33 established in Part E of this plan, the SO 2 

### emission rate established in the approval orders 34 for the four EGUs meets the presumptive SO 2 

### emission rate established in Appendix Y 35 independently of the alter native program. The enforceable BART emission limits and 36 monitoring requirements are included in Section IX, Part H.2 1 and H.22 of the State 37 Implementation Plan. 38

Page 9

### 1 Table 4

. [ Table 5 .] Emissions Rates [ (lb/MMBtu) ] for the Retrofitted Hunter and 2 Huntington Units 3

4 5 Table 6 . Change in Emissions (tons/yr) for Retrofitted BART Units 6 Unit Pre

Control SO 2 Pre

Control NOx Pre

Control PM 10 Post

Control SO 2 Post

C ontrol NO x Post

Control PM 10 Delta SO 2 Delta NO x Delta PM 10

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 1 743 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 Pursuant to 51.308(e)(1)(C) (iv) each source subject to BART is required to install and 9 operate BART no later than 5 years after approval of the implementat ion plan. The 5

- year 10 deadline was met for all four units. [ The PacifiCorp schedule for the four EGUs at 11 Huntington and Hunter sources is as follows. ] 12 13 14 Source Notice of Intent Submitted Permit Issued Estimated In Service Date Hunter 1 June 2006 March 200 8 Spring 2014 Hunter 2 June 2006 March 2008 Spring 2011 Huntington 1 April 2008 August 2009 Fall 201 0 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

- AN 0102380019

- 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 3 9135) Units Utah [ Permitted Rates ]BART Emission Rate 8 Presumptive BART Limits 9

Rate: lb/MMBtu SO 2 lb/MMBtu NOx lb/MMBtu PM lb/MMBtu SO 2 lb/MMBtu NO x lb/MMBtu Hunter 1 0.12 0.26 0.0 1 5 0.15 0.28 Hunter 2 0.12 0.26 0.0 1 5 0.15 0.2 8 lb/hr

Huntington 1 0.12 0.26 [ 0.05 ] 74 (PM 10 ) 0.15 0.28 Huntington 2 0.12 0.26 [ 0.05 ] 70 0.15 0.28



### Section XX

- Regional Haze. Page 10

### [ EPA under the BART Rule requires coal

- fired electric generating plants of greater than 1 750 MW to meet BART presumptive limits. While EPA considers presumptive limits to 2 be appropriate for all coal

- fired power plants greater than 750 MW, the State may 3 establish different requirements if the State can demonstrate that an alternative is justified 4 based on a c onsideration of the five BART factors. 5 6 “States, as a general matter, must require owners and operators of greater than 750 7 MW power plants to meet these BART emission limits... a State may establish 8 different requirements if the State can demonstrate that an alternative 9 determination is justified based on a consideration of the five statutory factors.” 10 

### 10 11 “For Coal

- fired EGU’s greater than 200 MW located at greater than 750 MW 12 power plants and operating without post

- combustion controls (i.e. SCR or 13 SNCR), w e have provided presumptive NOx limits, differentiated by boiler design 14 and type of coal burned. You may determine that an alternative control level is 15 appropriate based on careful consideration of the statutory factors.” (Appendix Y 16 Part 51

– IV (E)(5). 11 

### 17 18 EPA determined presumptive limits for SO 2 

### and NO x 

### for EGUs based on a methodology 19 equivalent to that required in 50 CFR 51 Appendix Y for BART Rule. The EPA 20 determination of presumptive limits included: 21

• I dentification of all potential BART

- eligible EGUs (all BART

- eligible 22 EGU’s were assumed to be Subject to BART) 23

• T echnical analyses and industry research to determine applicable and 24 appropriate SO 2 

### and NO x 

### control options, 25

• E conomic analysis to determine cost effectiveness for each potentially 26 BART

- eligibl e EGU 27

• E valuation of historical emissions and forecast emission reductions for 28 each potentially BART

- eligible EGU 12



### . 29

• NOx and SO 2 

### CAL P UFF modeling of emissio n impacts at model Class I 30

area

. 31 32 The analysis included 4 91 potential BART EGUs including Hunter Un its 1 and 2 33 and Huntington Units 1 and 2 . The technical analysis conducted by EPA to 34 determine presumptive BART limits for SO 2 

### and NO x 

### is in effect a BART 35

10 Ibid. (70 Federal Register 39131).

11 70 Federal Register 39171

12 Ibid. (70 Federal Register 39134)



### Page 11

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

. 13 

### 2 3 S ection IV (E) (5) of Appendix Y Part 51 clearly requires the implementation of 4 presumptive NOx limits for coal

- fired EGU’s greater than 200 MW located at greater 5 than 750 MW power plants. Under Appendix Y

, s tates are given the discretion to 6 challenge presu mptive limits through a five factor analysis

, but presumptive limits were 7 developed by EPA as a reasonable, equivalent and mandated substitution for a five factor 8 analysis

. 14 

### 9 ] 10 Utah’s long

- standing Prevention of Significant Deterioration (PSD) permitting program 11 (SIP Section VII and R307

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

- 401) and Visibility program (SIP section XVII and R307

- 406) will continue to 13 protect Class I area visibility by ensuring that the BART emission rates est ablished in Part 14 H.21 and H.22 of this plan are maintained, requiring best available control technology for 15 new sources, and assuring that there is not a significant degradation in visibility at Class I 16 areas due to new or modified major sources. 17

13 “Methodology for Developing BART NOx Presumptive Limits” EPA Clean Air Market Division June 15, 2005 HQ

- OAR

- 2002

- 0076

- 0445 and “Technical Suppo rt 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 12Page 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, 201 4 ] January 7, 2015Page 2 of 5 SIP Section IX.H.21 and 22

1Page 3 of 5 SIP Section IX.H.21 and 22

1 

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

## Emission Limits and Opera ting Practices, Regional Haze Requirements 3 4

a. Except as otherwise outlined in individual conditions of this Subsection IX.H.21 listed below, the 5 terms and conditions of this Subsection IX.H.21 shall apply to all sources subsequently 6 addressed in Subsection I X.H.22. Should any inconsistencies exist between these two 7 subsections, the source specific conditions listed in IX.H.22 shall take precedence. 8 b. The definitions contained in R307

- 101

- 2, Definitions, apply to Section IX, Part H. 9

c. Any information used to deter mine compliance shall be recorded for all periods when the source 10 is in operation, and such records shall be kept for a minimum of five years. Any or all of these 11 records shall be made available to the Director upon request. 12 d. All emission limitations listed in Subsections IX.H.22 apply during steady

- state operation, unless 13 otherwise specified in the source specific conditions listed in IX.H.22. 14

e. Stack Testing: 15 i. As applicable, stack testing to show compliance with the emission limitations for the sources 16 in Sub section IX.H.22 shall be performed in accordance with the following: 17 A. Sample Location: The testing point shall be designed to conform to the requirements of 18 40 CFR 60, Appendix A, Method 1, or other EPA

- approved methods acceptable to the 19 Director. 20 B. Volumetri c Flow Rate: 40 CFR 60, Appendix A, Method 2 or other EPA

- approved 21 testing methods acceptable to the Director. 22 C. Particulate (PM): 40 CFR 51, Appendix M, Method 5B, or other EPA approved testing 23 methods acceptable to the Director. The back half condensibles shall also be tested using 24 Method 202. The back half condensibles shall not be used for compliance demonstration 25 but shall be used for inventory purposes. 26 D. Calculations: To determine mass emission rates (lb/hr, etc.) the pollutant concentration as 27 determine d by the appropriate methods above shall be multiplied by the volumetric flow 28 rate and any necessary conversion factors to give the results in the specified units of the 29 emission limitation. 30 E. A stack test protocol shall be provided at least 30 days prior to the test. A pretest 31 conference shall be held if directed by the Director. 32 f. Continuous Emission and Opacity Monitoring. 33 i. For all continuous monitoring devices, the following shall apply: 34 A. Except for system breakdown, repairs, calibration checks, and zero and span adjustments 35 required under paragraph (d) 40 CFR 60.13, the owner/operator of an affected source 36 shall continuously operate all required continuous monitoring systems and shall meet 37 minimum frequency of operation requirements as outlined in R307

- 170 a nd 40 CFR 38 60.13. 39 B. The monitoring system shall comply with all applicable sections of R307

- 170; 40 CFR 40 13; and 40 CFR 60, Appendix B

– Performance Specifications. 41Page 4 of 5 SIP Section IX.H.21 and 22



## H.22. Source Specific Emission Limitations : Regional Haze Requirements, 1 

## Best Available Retrofit Tech nology 2 3

a. PacifiCorp Hunter 4 5 i. Particulate Limitations on Units #1 and #2 6 7 A. Emissions of particulate (PM) shall not exceed 0.015 lb/MM Btu heat input from each 8 boiler based on a 3

- run test average. 9 10 B. Stack testing for the emission limitation shall be performed e ach year on each boiler. 11 12 ii. NOx Limitations on Units #1 and #2 13 14 15 A. Emissions of NOx from each boiler shall not exceed 0.26 lb/MMBtu heat input for a 30

- 16 day rolling average. 17 18 B. Measuring of all NOx emissions shall be performed by CEM

. 19 20Page 5 of 5 SIP Section IX.H.21 and 22

1 b. PacifiCorp Huntington 2 3 i. Co nditions on Boiler Unit #1 4 5 A. Emissions of PM10 shall not be greater than 74 lb/hr. 6 7 B. Stack testing to show compliance with the PM10 emission limitation shall be performed 8 each year. 9 10 C. Emissions of NOx shall be no greater than 0.26 lb NOx/MMBtu heat input (1,2 90 lb/hr) 11 on a 30

- day rolling average

. 12 13 D. Measuring of all NOx emissions shall be performed by CEM. 14 15 ii. Conditions on Boiler Unit #2 16 17 A. Emissions of particulate matter (PM) from Boiler Unit #2 shall not be greater than 70 18 lb/hr. 19 20 B. Stack testing to show compliance with the PM emission limitation shall be performed 21 each year. 22 23 C. Emissions of NOx shall be no greater than 0.26 lb/MMBtu heat input on a 30

- day rolling 24
average. 25 26 D. Measuring of all NOx emissions shall be performed by CEM. 27