20131114Exhibits.pdf

N P IGINIA L
e BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
rN THE MATTER OF IDAHO POWER )COMPANY'S APPLICATION FOR A
CERTIEICATE OE PUBLIC
CONVENIENCE AND NECESSITY FOR
THE INVESTMENT TN SELECTIVE
CATALYTIC REDUCTION CONTROLS ON
.JIM BRIDGER UNITS 3 AND 4.
CASE NO.
rPC-E-13-16
TECHNICAL HEARING
EXHIBITS
r*"D
PLACE: Commission Hearing Room
412 West lrlashington StreetBoise, Idaho
DATE: November 7, 20L3
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
COURT REPORTING
St*u;g, t{" &y/ wrrnw athoe /976
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HEDRICK COURT REPORTING
P. O. BOX 578, BOTSE, rD 83701
APPEAR.ANCES
Eor the Staff:KRISTINE A. SASSER, Esq.
Deputy Attorney General
472 West WashingtonBoise, fdaho 83702
LISA D. NORDSTROM, Esq.
-and-
JENNIFER REINHARDT-TESSMER, Esq.
Idaho Power Companyl22L West Idaho StreetBoise, Idaho 83702
RICHARDSON ADAMS, PILCby PETER .I. RfCHARDSON, Esq.
5l-5 North Twenty-seventh StreetBoise, Idaho 83616
BEN.TAMIN ,.I. OTTO, Esq.
Idaho Conservation League
7L0 North Sixth StreetBoise, Idaho 83702
McDEVITT & MTLLER, LLP
by DEAN .1. MILLER, Esq.
420 West Bannock StreetBoise, Idaho 83702
For Idaho Power Company:
Eor Industrial Customers
Idaho Power:
of
For Idaho Conservation
League:
For Snake River ALliance:
APPEARANCES
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EXHIBITS
NUMBER PAGE
For Idaho Power Company:
1. 12/07 BART Analysis for ,Jim Bridger PremarkedUnit 3, 97 pgs Admitted 168
2. L2/01 BART Analysls for Jim Bridger PremarkedUnit 4, 96 pgs Admj-tted 168
3. BART Appeal Settlement Agreement , Premarked
11 pgs Admitted 168
4. I/1 /11 Wyoming State Implementation Premarked
PIan, Regional Haze, 206 pgs Admitted 168
5. (Confidential) PremarkedAdmitted 168
5A. 2/8/13 Coal Environmental- Compliance Premarked
Upgrade Investment Evaluation, 52 pgs Admitted 168
6. 20LL IRP Update, 30 pgs Premarked
Admitted 168
7. (Confidential) PremarkedAdmitted 243
Eor Staff:
l-01 . (Conf idential- ) PremarkedAdmitted 322
702 . (Conf idential- ) PremarkedAdmitted 322
103. (Confidential) PremarkedAdmitted 322
Eor Industrial- Customers of Idaho Power:
20L. Don C. Reading Curriculum Vitae, 4 pgs PremarkedAdmitted 351
HEDRICK COURT REPORTING
P. O. BOX 578, BOTSE, rD 83701
EXHIBITS
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HEDRICK COURT REPORTING
P. O. BOX 578, BOTSE, rD
Pg. 60, 20L3 IRP, 1 pg (Iater
as Exhibit No. 301)
Eor Snake River A]liance:
Typical Resource Portfolio FueI Mix,lpg
(Omitted)
{gq ,Idalrg 9onpgrvalion Leasug:
301.
302.
(Renumbered from Exhibit No.
401.
402.
403.
404.
405.
406.
407 .
408.
409.
410 .
4]-7.
472.
302)
marked
Marked 359Admitted 359
Marked 72
Marked 5
Admitted 359
6/25/1,3 Presidential- Memorandum, 2 pgs Marked 5Admitted 359
LL/I/13 Clearing Up, 3 pgs Marked 5Admitted 359
Idaho Power Company's Response to Staff Marked 5
Request No. lL, 2 pgs Admitted 359
Idaho Power Company's Response to Staff Marked 5
Request No. 18, 1 pg Admitted 359
Idaho Power Company's Response to Staff Marked 5
Request No. L9, 5 pgs Admitted 359
(Confidential) Uarked 5Admitted 359
Lt/5/L3 IDACORP Announces Third Quarter Marked 5
201,3 Results, 1 pg Admitted 359
Commiss j-on Staf f ' s Response to the Marked 5Elrst Production Request of Snake Rj-ver Admitted 359Alliance, 3 pgs
Pgs. l0-L2, PrefJ-Ied Testimony of Marked 5
Ken Mi11er, Snake River A11iance, 3 pgs Admitted 359
1,2/37/12 IDACORP Eorm 10-K, 2 pgs Marked 5Admitted 359
83701
EXHIBITS
Final Rrport
BART Analysis for
Iim Bridger Unit 3
Prepared For:
PacifiCorp
1407 West No(h Temple
Salt Lake City, Utah 84116
December 2007
Prepared By:
GH2lulH!LL
215 South State Street, Suite 1000
Salt Lake City, Utah 84111
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 1 of97
F inal Rrp or t
BART Analysis for
Iim Bridger Unit 3
Submitted to
PacifiCorp
December 2007
GH2ll,lHILL
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 2 of 97
Executive Summary
Background
In response to the Regional Haze Rule and Best Available Retrofit Technology (BART)
regulations and guidelines, CH2M HILL was requested to perform a BART analysis for
PacifiCorp's Jim Bridger Unit 3 (hereafter referred to as Jim Bridger 3). Best Available
Retrofit Technology analysis has been conducted for the following criteria pollutants: nitrogen
oxide (NO*), sulfur dioxide (SOz), and particulate matter less than l0 micrometers in
aerodynamic diameter (PMro).The Jim Bridger Station consists of four 530 megawatt (MW)
units with a total generating capacity of 2,120 MW. Because the total generating capacity of
the Jim Bridger Station exceeds 750 MW, presumptive BART emission limits apply to
Jim Bridger 3, based on the United States Environmental Protection Agency's (EPA)
guidelines. BART emissions limits must be achieved within five years after the State
Implementation Plan (SIP) is approved by the EPA. A compliance date of 2014 was assumed
for this analysis.
In completing the BART analysis, technology alternatives were investigated and potential
reductions in NO*, SOz, and PMro emissions rates were identified. The following technology
alternatives were investigated, listed below by pollutant:
NO, emission controls:
Low-NO* bumers (LNB) with over-fire air (OFA)
Rotating opposed fire air (ROFA)
LNB with selective non-catalytic reduction (SNCR) system
LNB with selective catalytic reduction (SCR) system
SOz emission controls:
Optimize current operation of existing wet sodium flue gas desulfurization (FGD)
system
Upgrade wet sodium FGD system to achieve an SOz emission rate of 0.10 lb per
MMBtu
New dry FGD system
PMro emission controls:
Sulfur trioxide (SO3) injection flue gas conditioning system on existing electrostatic
precipitator (ESP)
Polishing fabric filter
Exhibit No l
Case No. lPc-E-13-16 ES-l
T. Harvey, IPC
Page 3 of 97
JMS EY1 O2OO7OO1 SLC\BART_JB3-OCT20O7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
BART Engineering Analysis
The specific steps in a BART engineering analysis are identified in the Code of Federal
Regulations (CFR) at 40 CFR 5l Appendix Y, Section IV. The evaluation must include:
o The identification of available, technically feasible, retrofit control options
. Consideration of any pollution control equipment in use at the source (which affects the
availability of options and their impacts)
o The costs of compliance with the control options
. The remaining useful life of the facility
o The energy and non-air quality environmental impacts of compliance
o The degree of visibility improvement that may reasonably be anticipated from the use of
BART
The following steps are incorporated into the BART analysis:
. Step I - Identifi All Available Retrofit Control Technologies
. Step 2 - Eliminate Technically Infeasible Options
The identification of available, technically feasible, retrofit control options
Consideration of any pollution control equipment in use at the source (which affects
the applicability of options and their impacts)
o Step 3 - Evaluate Control Effectiveness of Remaining Control Technologies
. Step 4 - Evaluate Impacts and Document the Results
The costs of compliance with the control options
The remaining useful life of the facility
The energy and non-air quality environmental impacts of compliance
. Step 5 - Evaluate Visibility Impacts
The degree of visibility improvement that may reasonably be anticipated from the use
ofBART
Separate analyses have been conducted for NO*, SOz, and PMro emissions. All costs included
in the BART analyses are in 2006 dollars, and costs have not been escalated to the assumed
2014 BART implementation date.
Coal Characteristics
The main source of coal burned at Jim Bridger 3 will be the Bridger Underground Mine.
Secondary sources are the Bridger Surface Mine, the Bridger Highwall Mine, the Black Butte
Mine, and the Leucite Hills Mine. These coals are ranked as sub-bituminous, but are closer in
characteristics to bituminous coal in many of the parameters influencing NO* formation.
These coals have higher nitrogen content than coals from the Powder River Basin (PRB),
Exhibit No. 1 -^c""" No
-ipc-E-1
3-1 6 ES-2
T. Harvey, IPC
Page 4 of 97
JMS EY1 O2OO7OO1 SLC\BART_JB3_OCI2OO7_FINAL,DOC
MRT ANALYSIS FOR JIM BRIDGER UNIT 3
which represent the bulk of sub-bituminous coal use in the U.S. This BART analysis has
considered the higher nitrogen content and different combustion characteristics of PRB coals,
as compared to those coals used at Jim Bridger 3, and has evaluated the effect of these
qualities on NO* formation and achievable emission rates.
Recommendations
CH2M HILL recommends these BART selections, which include installing low NO* bumers
with over-fire air, upgrading the existing FGD system, and operating the existing electrostatic
precipitator with an SOr flue gas conditioning system. This combination of control devices is
identified as Scenario 1 throughout this report.
NO' Emission Control
The BART presumptive NO* limit assigned by EPA for tangentially-fired boilers burning
sub-bituminous coal is 0.15 lb per MMBtu. However, as documented in this analysis, the
characteristics of the Jim Bridger coals are more closely aligned with bituminous coals, with
a presumptive BART NO* limit of 0.28 lb per MMBtu.
CH2M HILL recommends low-NO* burners with over-fire air (LNB with OFA) as BART for
Jim Bridger 3, based on the projected significant reduction in NO* emissions, reasonable
control costs, and the advantages of no additional power requirements or non-air quality
environmental impacts. NO* reductions are expected to be similar to those realized at
Jim Bridger 2. CHZM HILL recommends that the unit be permitted at a rate of 0.26 lb per
MMBtu.
SOz Emission Gontrol
CH2M HILL recommends upgrading the existing wet sodium FGD system as BART for
Jim Bridger 3, based on the significant reduction in SOz emissions, reasonable control costs,
and the advantages of minimal additional power requirements and minimal non-air quality
environmental impacts. This upgrade approach will meet the BART presumptive SOz limit of
0.15 lb per MMBtu.
PMro Emission Control
CH2M HILL recommends finalizing the permitting of the flue gas conditioning system to
enhance the performance of the existing ESP as BART for Jim Bridger 3, based on the
significant reduction in PMro emissions, reasonable control costs, and the advantages of
minimal additional power requirements and no non-air quality environmental impacts.
BART Modeling Analysis
CH2M HILL used the CALPUFF modeling system to assess the visibility impacts of
emissions from Jim Bridger 3 at Class I areas. The Class I areas potentially affected are
located more than 50 kilometers, but less than 300 kilometers, from the Jim Bridger Plant.
Exhibit No- 1 _ .^ .^ ES_3Case No. IPC-E-13-16 --'
T. Harvey, IPC
Page 5 of 97
JMS EY1 02007001 SrC\BART_JB3_0CT2007_FTNAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
The Class I areas include the following wilderness areas (WAs):
. Bridger WA. Fitzpatrick WA. Mt. Zirkel WA
Because Jim Bridger 3 will simultaneously control NO*, SO2, and PMro emissions, four
post-control atmospheric dispersion modeling scenarios were developed to cover the range of
effectiveness for combining the individual NO,, SO2, and PMls control technologies under
evaluation. These modeling scenarios, and the controls assumed, are as follows:
. Scenario 1: New LNB with OFA modifications, upgraded wet FGD system, and flue gas
conditioning for enhanced ESP performance. As indicated previously, this scenario
represents CH2M HILL HILL's preliminary BART recommendation.
. Scenario 2: New LNB with OFA modifications, upgraded wet FGD system, and new
polishing fabric filter.
. Scenario 3: New LNB with OFA modifications and SCR, upgraded wet FGD system,
and flue gas conditioning for enhanced ESP performance.
. Scenario 4: New LNB with OFA modifications and SCR, upgraded wet FGD system,
and new polishing fabric filter.
Visibility improvements for all emission control scenarios were analyzed, and the results
were compared utilizing a least-cost envelope, as outlined in the New Source Review
Worleshop Manual.l
Least-cost Envelope Analysis
EPA has adopted the least-cost envelope analysis methodology as an accepted methodology
for selecting the most reasonable, cost-effective controls. Incremental cost-effectiveness
comparisons focus on annualized cost and emission reduction differences between dominant
alternatives. The dominant set of control alternatives is determined by generating what is
called the envelope of least-cost alternatives. This is a graphical plot of total annualized costs
for total emissions reductions for all control altematives identified in the BART analysis.
To evaluate the impacts of the modeled control scenarios on the three Class I areas, the total
annualized cost, cost per deciview (dV) reduction, and cost per reduction in number of days
above 0.5 dV were analyzed. This report provides a comparison of the average incremental
costs between relevant scenarios for the three Class I areas; the total annualized cost versus
number of days above 0.5 dV, and the total annualized cost versus 98th percentile delta-
deciview (AdV) reduction.
Results of the least-cost envelope analysis validate the selection of Scenario l, based on
incrementalcost and visibility improvements. Scenario 2 (LNB with OFA, upgraded wet
FGD, and polishing fabric filter) is eliminated, because it is to the left of the curve formed by
the dominant control alternative scenario, which indicates a scenario with lower
1 f pR, t 990. New Source Review Workshop Manual. Draft. Environmental Protection Agency. October, 1990
Exhibit No. 1 -^ ,c""" fl" IPC-E-13-16 ES-4
T. Harvey, IPC
Page 6 of 97
JMS EY,IO2OOTOO1SLC\BARI J83 OCT2OOT FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
improvement and/or higher costs. Scenario 3 (LNB with OFA and SCR, upgraded wet FGD,
and flue gas conditioning for enhanced ESP performance) is not selected due to very high
incremental costs, on the basis of both a cost per day of improvement and cost per dV
reduction. While Scenario 4 (LNB with OFA and SCR, upgraded wet FGD, and polishing
fabric filter) provides some potential visibility advantage over Scenario 1, the projected
improvement is less than half a dV, and the projected costs are excessive. Therefore,
Scenario I represents BART for Jim Bridger 3.
Just-Noticeable Differences in Atmospheric Haze
Studies have been conducted that demonstrate only dV differences of approximately 1.5 to
2.0 dV or more are perceptible by the human eye. Deciview changes of less than 1.5 cannot
be distinguished by the average person. Therefore, the modeling analysis results indicate that
only minimal, if any, observable visibility improvements at the Class I areas studied would
be expected under any of the control scenarios. Thus, the results indicate that only minimal
discernable visibility improvements may result, even though PacifiCorp will be spending
many millions of dollars at this single unit, and over a billion dollars when considering its
entire fleet of coal-fired power plants.
ExhibitNo-l _.-.-ES.5Case No.|PC-E-13-16-"
T. Harvey, IPC
Page 7 of 97
JMS EY1 O2OO7OO1 SLC\BART-JB3-OCI2OO7_FINAL.DOC
Contents
1.0
2.0
3.0
1-1
BART Engineering Analysis.3-13.1 Applicability ...............3-l3.2 BART Process ............3-l3.2.1 BART NO* Analysis............... ..........3-23.2.2 BART SO2 Ana1ysis................ ........3-143.2.3 BART PM16 Ana1ysis.............. ........3-17
BART Modeling Analysis.... .....................4-14.1 Model Selection.... ......4-14.2 CALMET Methodology................ ...................4-l4.2.1 Dimensions of the Modeling Domain ..................4-l4.2.2 CALMET Input Data.. ....4-44.2.3 Validation of CALMET Wind Field.......... ..........4-64.3 CALPUFF Modeling Approach ....4-64.3.1 Background Ozone and Ammonia............... ........4-64.3.2 Stack Parameters.......... .....................4-64.3.3 Emission Rates......... ......4-7
4.3.4 Post-control Scenarios. ......................4-74.3.5 Modeling Process ...........4-8
4.3.6 Receptor Grids.......... ......4-84.4 CALPOST ................4-104.5 Presentation of Modeling Results....... ............4-l I4.5.1 Visibility Changes for Baseline vs. Preferred Scenario ........ 4-l 1
Preliminary Assessment and Recommendations .............. ...........5-1
5.1 Least-cost Envelope Analysis .......5-l5.1.1 Analysis Methodology ................ ......5-l5.1.2 Analysis Results .............5-95.2 Recommendations ......5-95.2.1 NO* Emission Control. ......................5-95.2.2 SOz Emission Control ....5-95.2.3 PMro Emission Control .....................5-95.3 Just-Noticeable Differences in Atmospheric Haze ........... 5-10
6.0 References.........6-1
Exhibit No. 1
Case No. tPC-e-tS-'l'b
T. Harvey, IPC
Page 8 of 97
5.0
P:\PACIFICORP\348295BARnDAVEJ0HNST0N3_FINALSUBMITTAL\BART-JB3_OCT2007_FINAL.DOC
CONTENTS (CONTINUED}
Tables2-l Unit Operation and Study Assumptions2-2 Coal Sources and Characteristics3-l CoalCharacteristicsComparison3-2 NO* Control Technology Projected Emission Rates3-3 NO* Control Cost Comparison3-4 SOz ControlTechnology Emission Rates3-5 SOz Control Cost Comparison (lncrementalto Existing FGD System)3-6 PMro ControlTechnology Emission Rates3-7 PMro Control Cost Comparison (lncremental to Existing ESP)4-l User-specified CALMET Options4-2 BART Model Input Data4-3 Average Natural Levels of Aerosol Components4-4 Costs and Visibility Modeling Results for Baseline vs. Post-Control Scenarios at Class I
Areas5-l Control Scenario Results for the Bridger Class I Wildemess Area
5-2 Control Scenario Results for the Fitzpatrick Class I Wilderness Area5-3 Control Scenario Results for the Mt. Zirkel Class I Wilderness Area5-4 Bridger Class I Wildemess Area Incremental Analysis Data5-5 Fitzpatrick Class I Wilderness Area Incremental Analysis Data5-6 Mt. Zirkel Class I Wilderness Area Incremental Analysis Data
Figures3-l lllustration of the Effect of Agglomeration on the Speed of Coal Combustion3-2 Plot of Typical Nitrogen Content of Various Coals and Applicable Presumptive
BART NO* Limits
3-3 Plot of Typical Oxygen Content of Various Coals and Applicable Presumptive
3-4
3-5
4-l
4-2
5-l
5-2
5-3
5-4
5-5
5-6
Appendices
BART NO* Limits
First Year Control Cost for NO* Air Pollution Control Options
First Year Control Cost for PM Air Pollution Control Options
Jim Bridger Source-Specific Class I Areas to be Addressed
Surface and Upper Air Stations Used in the Jim Bridger BART Analysis
Least-cost Envelope Bridger Class I WA Days Reduction
Least-cost Envelope Bridger Class I WA 98th Percentile Reduction
Least-cost Envelope Fitzpatrick Class I WA Days Reduction
Least-cost Envelope Fitzpatrick Class I WA 98th Percentile Reduction
Least-cost Envelope Mt. ZirkelClass I WA Days Reduction
Least-cost Envelope Mt. Zirkel Class I WA 98th Percentile Reduction
A
B
Economic Analysis
2006 Wyoming BART Protocol
Exhibit No. 1
Case No. IPC-E-13-ib
T. Harvey, IPC
Page 9 of 97
JMS EY1 O2OO7OO1 SLC\BARI_JB3_OCT2OO7_FINAL.DOC
Acronyms and Abbreviations
oF Degree Fahrenheit
BACT Best Available Control Technology
BART Best Available Retrofit Technology
CALDESK Program to Display Data and Results
CALMET Meteorological Data Preprocessing Program for CALPUFF
CALPOST Post-processing Program for Calculating Visibility Impacts
CALPUFF GaussianPuffDispersionModel
COHPAC Compact Hybrid Particulate Collector
dV Deciview
AdV Delta Deciview, Change in Deciview
DEQ Department of Environmental Quality
ESP Electrostatic Precipitator
EPA United States Environmental Protection Agency
FGC Flue Gas Conditioning
FGD Flue Gas Desulfurization
kW Kilowatt
kW-Hr Kilowatt-hour
LNB Low-NO* Burner
lb Pound
MMBtu Million British Thermal Units
MM5 Mesoscale Meteorological Model, Version 5
MW Megawatts
NO* Nitrogen Oxides
OFA Over Fire Air
PM Particulate Matter
PMz.s Particulate Matter less than 2.5 Micrometers in Aerodynamic Diameter
PMro Particulate Matter less than l0 Micrometers in Aerodynamic Diameter
PRB Powder River Basin
ROFA Rotating Opposed Fire Air
S&L Sargent & Lundy
SCR Selective Catalytic Reduction
SIP State Implementation Plan
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 10 of97
JMS EYIO2OOTOOlSIC\BART_JB3_OCT2OOT.FINAL,DOC
ACRONYMS ANDABBREVIATIONS (CONTINUED)
O SNCR Selective Non-catalytic Reduction
SOz Sulfur Dioxide
SOr Sulfur Trioxide
USGS U.S. Geological Survey
WA Wilderness Area
WDEQ-AQD Wyoming Department of Environmental Quality - Air Quality Division
Exhibit No. 1
Case No. IPC-E-13-16 vi
T. Harvey, IPC
Page 11 of97
JMS EY1 02OO7OO1 SLC\BART_JB3-OCT2OO7-FINAL.DOC
1.0 !ntroduction
Best Available Retrofit Technology (BART) guidelines were established as a result of United
States Environmental Protection Agency (EPA) regulations intended to reduce the
occurrence of regional haze in national parks and other Class I protected air quality areas in
the United States (40 CFR Part 5l). These guidelines provide guidance for states when
determining which facilities must install additional controls, and the type of controls that
must be used. Facilities eligible for BART installation were built between 1962 and 1977,
and have the potentialto emit more than 250 tons per year of visibility-impairing pollutants.
The Wyoming Department of Environmental Quality (DEQ) BART regulations state that
each source subject to BART must submit a BART application for a construction permit by
December 15, 2006. PacifiCorp received an extension from the Wyoming DEQ to submit the
BART report for Jim Bridger Unit 3 (hereafter referred to as Jim Bridger 3) by January 12,
2007.The BART Report that was submitted to WDEQ in January 2007 included a BART
analysis, and a proposal and justification for BART at the source. This revised report-
submitted in October 2OO7-incorporates editorial revisions and new model runs since the
January 2007 version.
The State of Wyoming has identified those eligible, in-state facilities that are required to
reduce emissions under BART, and will set BART emissions limits for those facilities. This
information will be included in the State of Wyoming State Implementation Plan (SIP),
which the State has estimated will be formally submitted to the EPA by early 2008. The EPA
BART guidelines also state that the BART emission limits must be fully implemented within
5 years of EPA's approval of the SIP.
Five elements related to BART address the issue of emissions for the identified facilities:
. Any existing pollution control technology in use at the sourceo The cost of the controls. The remaining useful life of the sourceo The energy and non-air quality environmental impacts of complianceo The degree of improvement in visibility that may reasonably be anticipated from the use
of such technology
This report documents the BART analysis that was performed on Jim Bridger 3 by
CH2M HILL for PacifiCorp. The analysis was performed for the pollutants nitrogen oxide
(NO*), sulfur dioxide (SOz), and particulate matter less than l0 micrometers in aerodynamic
diameter (PMro), because they are the primary criteria pollutants that affect visibility.
Section 2 of this report provides a description of the present unit operation, including a
discussion of coal sources and characteristics. The BART Engineering Analysis is provided
in Section 3, by pollutant type. Section 4 provides the methodology and results of the BART
Modeling Analysis, followed by recommendations in Section 5. References are provided in
Section 6. Appendices provide more detail on the economic analysis and the 2006 Wyoming
BART Protocol.
ExhibitNo. I nnCase No. IPC-E-13-16 ' '
T. Harvey, IPC
Page 12 of 97
JMS EY1O2OO7OO1 SLC\BART-JB3-OCT2OO7_FINAL,DOC
2.0 Present Unit Operation
The Jim Bridger Station consists of four units with a total generating capacity of
2,120 megawatts (MW). Jim Bridger 3 is a nominal 530 net MW unit located approximately
35 miles northeast of Rock Springs, Wyoming. It is equipped with a tangentially fired
pulverized coal boiler with low NO* bumers manufactured by Combustion Engineering. The
unit was constructed with a Flakt wire frame electrostatic precipitator (ESP). The unit
contains a Babcock & Wilcox wet sodium flue gas desulfurization (FGD) system with three
absorber towers installed in 1988. An Emerson Ovation distributed control system (DCS)
was installed in 2003.
Jim Bridger 3 was placed in service in 1976.Its current economic depreciation life is through
2040; however, this analysis is based on a2O-year life for BART control technologies.
Assuming a BART implementation date of 2014, this willresult in an approximate remaining
useful life for Jim Bridger 3 of 20 years from the installation date of any new or modified
BART-related equipment. This report does not attempt to quantifr any additional life
extension costs needed to allow the unit and these control devices at Jim Bridger 3 to operate
until2040.
Table 2-l lists additional unit information and study assumptions for this analysis.
The BART presumptive NO* limit for tangential-fired boilers buming sub-bituminous coal is
0.15 lb per MMBtu and the BART presumptive NO* limit for burning bituminous coal is
0.28 lb per MMBtu. The main sources of coal burned at Jim Bridger 3 are the Bridger Mine
and secondarily the Black Butte Mine and Leucite Hills Mine. These coals are ranked as
sub-bituminous, but are closer in characteristics to bituminous coal in many of the parameters
influencing NO* formation. These coals have higher nitrogen content than coals from the
Powder River Basin (PRB), which represent the bulk of sub-bituminous coal use in the U.S.
This BART analysis has considered the higher nitrogen content and the different combustion
characteristics of PRB coals, as compared to those coals used at Jim Bridger 3, and has
evaluated the effect of these qualities on NO* formation and achievable emission rates. Coal
sources and characteristics are summarized in Table 2-2.The primary source of coal will be
the Bridger Underground Mine, and data on coal from this source were used in the modeling
analysis. For the coal analysis that is presented in Section 3.2.l,the data from allthe coal
sources were used.
Exhibit No. 1 ^Case No. IPC-E-13-16 2'1
T. Harvey, IPC
Page 13 of 97
JMS EY1 O2OO7OO1 SIC\BARI_JB3-OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
TABLE 2.1
Unit Operation and Study Assumptions
Jim Bridger 3
General Plant Data
Site Elevation feet above MSL
Stack Height (feet)
Stack Exit lnternal Diameter (feet) /Exit Area (square feet)
Stack Exit Temperature (degrees Fahrenheit)
Stack Exit Velocity (feet per second)
Stack Flow (actual cubic feet per minute)
Latitude (degree: minute: second)
Longitude (degree: minute: second)
Annual Unit Capacity Factor (percentage)
Net Unit Output (megawatts)
Net Unit Heat Rate (British thermal unit [Btu]/kilowatt-
hour)(100% load)
Boiler Heat lnput (million British thermal units [MMBtu] per
hour)(100% load)
Type of Boiler
Boiler Fuel
Coal Sources
Coal Heating Value (Btu/ per pound [b])(")
Coal Sulfur Content (percentage by weight twt. %l) 6)
Coal Ash Content (wt. %I")
Coal Moisture Content (wt. %I4
Coal Nitrogen Content (wt. %)(")
Current Nitrogen Oxide (NOf Controls
NO* Emission Rate (lb per MMBtu)
Current Sulfur Dioxide (SO2) Controls
SOz Emission Rate (lb per MMBtu)
Current PMro Controls
PMro(') Emission Rate (lb per MMBtu)(b)
6669
s00
24 t452.4
140
84.04
2,281,182
41 :44:1 8.54 north
108:47:12.82 west
90
530
10,400 (as measured by fuel throughput)
6,000 (as measured by continuous
emission monitoring)
Tangentially fired
Coal
Bridger Mine, Black Butte Mine, Leucite
Hills Mine
9,660
0.58
10.3
19.3
0.98
Low NO, burners
0.45
Sodium based wet scrubber
0.267
Electrostatic Preci pitator
0.057
NOTES:(")Coal characteristics based on Bridger Underground Mine (primary coal source)
(b) Based on maximum historic emission rate from 1999-2001 , prior to installation of the SOr injection
system.(")PMro refers to particulate matter less than 10 micrometers in aerodynamic diameter
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 14 of97
JMS EY1 O2OO7OO1 SLC\BARI_JB3_OCT2OO7_FINAt.DOC
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Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 15 of97
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3.0 BART Engineering Analysis
This section presents the required BART engineering analysis.
3.1 Applicability
In compliance with regional haze requirements, the State of Wyoming must prepare and submit
visibility SIPs to the EPA for Class I areas. The State has estimated that the formal submittal of
the SIPs will occur by early 2008. The first phase of the regional haze program is the
implementation of BART emission controls on all BART eligible units, within 5 years after
EPA approval ofthe SIP.
3.2 BART Process
The specific steps in a BART engineering analysis are identified in the Code of Federal
Regulations (CFR) at 40 CFR 5l Appendix Y, Section IV. The evaluation must include:
o The identification of available, technically feasible, retrofit control options
o Consideration of any pollution control equipment in use at the source (which affects the
availability of options and their impacts)
o The costs of compliance with the control options
o The remaining useful life of the facility
o The energy and non-air quality environmental impacts of compliance, and
o The degree of visibility improvement that may reasonably be anticipated from the use of
BART
The following steps are incorporated into the BART analysis:
. Step I - Identiff All Available Retrofit ControlTechnologies
. Step 2 - Eliminate Technically Infeasible Options
The identification of available, technically feasible, retrofit controloptions
Consideration of any pollution control equipment in use at the source (which affects the
applicability of options and their impacts)
o Step 3 - Evaluate Control Effectiveness of Remaining Control Technologies
. Step 4 - Evaluate Impacts and Document the Results
The costs of compliance with the control options
The remaining useful life of the facility
The energy and non-air quality environmental impacts of compliance
Exhibit No. 1 31
Case No. IPC-E-13-16
T. Harvey, IPC
Page 16 of97
JMS EY1 O2OO7OO1 SLC\BART-JB3_OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
. Step 5 - Evaluate Visibility Impacts
The degree of visibility improvement that may reasonably be anticipated from the use
ofBART
In order to minimize costs in the BART analysis, consideration was made of any pollution
control equipment in use at the source, the costs of compliance associated with the control
options, and the energy and non-air quality environmental impacts of compliance using these
existing control devices. In some cases, enhancing the performance of the existing control
equipment was considered. Other scenarios with new control equipment were also developed.
All costs included in the BART analysis are in 2006 dollars (not escalatedto 2014 BART
implementation date).
3.2.1 BART NO, Analysis
Nitrogen oxide formation in coal-fired boilers is a complex process that is dependent on a
number of variables, including operating conditions, equipment design, and coal characteristics.
Formation of NO,
During coal combustion, NO* is formed in three different ways. The dominant source of NO*
formation is the oxidation of fuel-bound nitrogen. During combustion, pan of the fuel-bound
nitrogen is released from the coalwith the volatile matter, and part is retained in the solid
portion (char). The nitrogen chemically bound in the coal is partially oxidized to nitrogen
oxides (nitric oxide and nitrogen dioxide) and partially reduced to molecular nitrogen. A
smaller part of NO* formation is due to high temperature fixation of atmospheric nitrogen in
the combustion air. A very small amount of NO* is called "prompt" NO*. Prompt NO* results
from an interaction ofhydrocarbon radicals, nitrogen, and oxygen.
In a conventional pulverized coal burner, air is introduced with turbulence to promote good
mixing of fuel and air, which provides stable combustion. However, not all of the oxygen in the
air is used for combustion. Some of the oxygen combines with the fuel nitrogen to form NO*.
Coal characteristics directly and significantly affect NO* emissions from coal combustion. Coal
ranking is a means of classi$ing coals according to their degree of metamorphism in the
natural series, from lignite to sub-bituminous to bituminous and on to anthracite. Lower rank
coals, such as the sub-bituminous coals from the PRB, produce lower NO* emissions than
higher rank bituminous coals, due to their higher reactivity and lower nitrogen content. The
fixed carbon to volatile matter ratio (fuel ratio), coal oxygen content, and rank are good relative
indices of the reactivity of a coal. Lower rank coals release more organically bound nitrogen
earlier in the combustion process than do higher rank bituminous coals. When used with low-
NO,, burners (LNBs), sub-bituminous coals create a longer time for the kinetics to promote
more stable molecular nitrogen, and hence result in lower NO* emissions.
Coals from the PRB are classified as sub-bituminous C and demonstrate the high reactivity and
low NO* production characteristics described above. Based on data from the Energy
Information Administration, PRB coals currently represent 88 percent of total U.S.
sub-bituminous production and 73 percent of western coal production (Energy lnformation
Administration, 2006). Most references to "westem" coal and sub-bituminous coal infer PRB
origin and characteristics. Emissions standards differentiating between bituminous and sub-
Exhibit No. 1
Case No. IPC-E-13-16 3'2
T. Harvey, IPC
Page 17 of97
JMS EYlO2OOTOOlSLC\BART-JB3_OCI2OO7-FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
bituminous coals are presumed to use PRB coal as the basis for the sub-bituminous standards,
due to its dominant market presence and unique characteristics.
There are a number of western coals that are classified as sub-bituminous, however, they border
on being ranked as bituminous and do not display many of the qualities of PRB coals, including
most of the low NO* forming characteristics. Coals from the Bridger, Black Butte, and Leucite
Hills mines fall into this category.
As defined by the American Society for Testing and Materials, the only distinguishing
characteristic that classifies the coals used at Jim Bridger 3 as sub-bituminous rather than
bituminous - that is, they are "agglomerating" as compared to "non-agglomerating".
Agglomerating as applied to coal is "the property of softening when it is heated to above about
400'C in a non-oxidizing atmosphere, and then appearing as a coherent mass after cooling to
room temperature." Because the agglomerating property of coals is the result of particles
transforming into a plastic or semi-liquid state when heated, it reflects a change in surface area
of the particle. Thus, with the application of heat, agglomerating coals would tend to develop a
non-porous surface while the surface of non-agglomerating coals would become even more
porous with combustion. As shown by Figure 3-1, the increased porosity provides more particle
surface area resulting in more favorable combustion conditions. This non-agglomerating
property assists in making sub-bituminous coals more amenable to controlling NO,, by allowing
less air to be introduced during the initial ignition portion of the combustion process. The coals
from the Bridger, Black Butte and Leucite Hills mines just barely fall into the category of
non-agglomerating coals. While each of these coals is considered non-agglomerating, they
either do not exhibit those properties of non-agglomerating coals or exhibit them to only a
minor degree. The conditions during combustion of typical non-agglomerating coals that make
it easier to control NO* emissions do not exist for the Bridger blends of coals.
FIGURE 3.1
lllustration of the Effect of Agglomeration on the Speed of Coal Combustion
Jim Bidger 3
THE EFFECT OF AGGTOMERATING IB.IDCNCY UPON COi BUSTION
NONAGGTO'{EIAIING IGNIIION CHAI
O IAl
-l
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r otc
SUtfACCAtEA/ftAS5
IEUff'tsfasttl
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DEVOTAIITIZAIION
AND COMBUSTION
Exhibit No. 'l
Case No.lPC-E-13-16
T. Harvey, IPC
Page 18 of97
JMS EY1 O2OO7OO1 SLC\BART-JB3_OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
Table 3-l shows key characteristics of a typical PRB coal compared to coals from the Bridger
Mine, Black Butte, and Leucite Hills, as well as Twentymile, which is a representative western
bituminous coal.
TABLE 3.1
Coal Characteristics Comparison
Jim Bridger 3
Parameter
TypicalPowder BridgerRiver Mine
Basin
Black
Butte
Leucite
Hi!ls Twentymile
Nitrogen (percentage dry)
Oxygen (percentage dry)
Coal rank
1.10 1.26
16.2 13.2
Sub C Sub B
1.47
13.4
Sub B
1.48
13.2
Sub B
1.85
7.19
Bituminous high
volatility B
As shown in Table 3-1, although Bridger, Black Bufte, and Leucite Hills are classified as
sub-bituminous, they all exhibit higher nitrogen content and lower oxygen content than the
PRB coal. The higher nitrogen content is an indication that more nitrogen is available to the
combustion process and higher NO* emissions are likely. Oxygen content can be correlated to
the reactivity of the coal, with more reactive coals generally containing higher levels of oxygen.
More reactive coals tend to produce lower NO* emissions, and they are also more conducive to
reduction of NO* emissions through the use of combustion control measures, such as low NO,*
burners and over-fire air (OFA). These characteristics indicate that higher NO* formation is
likely with coal from the Bridger, Black Butte, and Leucite Hills mines, rather than with PRB
coal. The Bridger, Black Butte, and Leucite Hills coals all contain quality characteristics that
fall between a typical PRB coal and Twentymile. Twentymile is a clearly bituminous coal that
produces higher NO*, as has been demonstrated at power plants burning this fuel.
Figures 3-2 and 3-3 graphically illustrate the relationship of nitrogen and oxygen content to the
BART presumptive NO* limits for the coals listed in Table 3-1. Each chart identifies the
presumptive BART limit associated with a typical bituminous and sub-bituminous coal, and
demonstrates how the Jim Bridger coal falls between these two general coal classifications.
The Bridger blend data point represents a combination of coals from the Bridger Mine, Black
Butte, and Leucite Hills that has been used at Jim Bridger 3, and indicates the average NO*
emission rate achieved during the years 2003-2005. The Jim Bridger 2 data point consists of the
same blend of coals as Jim Bridger 3, and represents the NO* emission rate achieved after
installation of Alstom's current state-of-the-art TFS2000 LNB and OFA system. The long-term
sustainable emission rate for this system is expected tobe 0.24Ib per MMBtu. All four units at
Jim Bridger consist of identical boilers; while there may be some differences in performance
among them, installation of the TFS2000 firing system at Jim Bridger 3 would likely result in
performance and NO* emission rates comparable to those at Jim Bridger 2.
Figures 3-2 and 3-3 both demonstrate that for the Jim Bridger units-with the TFS2000 low
NO* emission system installed, and burning a combination of the Bridger, Black Butte, and
Exhibit No. 1
Case No. IPC-E-'l3-16 &4
T. Harvey, IPC
Page 19 of97
JMS EY1 O2OOTOOlSLC\BART-JB3_OCT2OO7-FINAL,DOC
tor 0.3
=-g
.EJ 0.25xo2
BART ANALYSIS FOR JIM BRIDGER UNIT 3
Leucite Hill coals-the likely NO* emission rate will be closer to the bituminous end (0.28) of
the BART presumptive NO* limit range, rather than the BART presumptive NO* limit of
0.15 lb per MMBtu for sub-bituminous coal. All of these factors are consistent with the
observed sustainable rate of 0.24Ib per MMBtu.
FIGURE 3.2
Plot ol Typical Nitrogen Content of Various Coals and Applicable Presumptive BART N0, Limits
Jin Bridger 3
A
Bridger Blend
--;;r-*,"-rr.il"-.*;;;; ---r-Twentymile Bituminous
i-\im Brioger 2
PRB subbituminous Subbituminous Presumptive Limit - 0.15|b/MMBtu
1.40 1.50 I .60
Typical Nitrogon Cont6nt (%-Dry Basis)
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 20 of 97
0.2
JMS EY1 O2OO7OO1 SLC\AART-JB3-OCT2OO7_FINAL,DOC $5
BART ANALYSIS FOR JIM BRIDGER UNIT 3
FIGURE 3.3
Plot of Typical Orygen Content of Various Coals and Applicable Presumptive BART NO, Limits
Jin Bridger 3
Bridger Blend
Twentymile Bituminous
-{-Bituminous Presumptive Limit - 0.28 lb/MMBtu
\.J,rBridger2
-_- -:_-_:,------_-_-----_ --- _--_ _-- -------_--SuOUituminouipresumplivef-imit-O.15lb/MMBtu -- t - - - - -
PRB Subbituminous
0.1
o- 0.3-o
tEf o.zsxoz
0.45
0.35
0.2
6.00 8.00 10.00 12.00 14.00
Typical Oxygen Content (%-Dry BasE)
Coal quality characteristics also impact the design and operation of the boiler and associated
auxiliary equipment. Minor changes in quality can sometimes be accommodated through
operational adjustments or equipment changes. It is important to note, however, that consistent
variations in quality or assumptions of "average" quality for performance projections can be
problematic. This is particularly troublesome when dealing with performance issues that are
very sensitive to both coal quality and combustion conditions, such as NO* formation. There is
significant variability in the quality of coals burned at Jim Bridger 3. In addition to buming
coal from Black Butte and Leucite Hills, Jim Bridger 3 burns coal supplied from the Bridger
Mine consisting of three sources: underground, surface, and highwall operations. Each of these
coal sources has different quality characteristics, as well as inherent variability in composition
of the coal within the mine.
Several of the coal quality characteristics and their effect on NO* formation have been
previously discussed. There are some additional considerations that illustrate the complexity of
achieving and maintaining consistent low NO* emissions with pulverized coal on a shorter
term, such as a 30-day rolling average basis.
Good combustion is based on the "three Ts": time, temperature, and turbulence. These
parameters along with a "design" coal are taken into consideration when designing a boiler and
associated firing equipment such as fans, bumers, and pulverizers. If a performance
requirement such as NO* emission limits is subsequently changed, conflicts with and between
other performance issues can result.
r6.00
Exhibit No. 1
Case No. IPC-E-13-16 3-6
T. Harvey, IPC
Page 21 ol 97
JMS EY1 O2OO7OO1 SLC\BART_JB3_OCT2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
Jim Bridger 3 is located at an altitude of 6,669 feet above sea level. Atmospheric pressure is
lower at this elevation, I 1.5 pounds per square inch, as compared with sea level pressure of
14.7 pounds per square inch. This lower pressure means that less oxygen is available for
combustion for each volume of air. In order to provide adequate oxygen to meet the
requirements for efficient combustion, larger volumes of air are required. When adjusting air
flows and distribution to reduce NO* emissions using LNB and OFA, original boiler design
restrictions again limit the modifications that can be made while still achieving satisfactory
combustion performance.
Another significant factor in controlling NO* emissions is the fineness of the coal entering the
burners. Fineness is influenced by the Hardgrove Grindability Index of the coal. Finer coal
particles promote release of volatiles and assist char burnout due to more surface area being
exposed to air. NO* reduction with high volatile coals is improved with greater fineness and
with proper air staging. The lower rank sub-bituminous coals such as PRB coals are quite
friable and easy to grind. Coals with lower Hardgrove Grindability Index values, such as those
used at Jim Bridger 3, are more diflicult to grind and can contribute to higher NO* levels. In
addition, coal fineness can deteriorate over time periods between pulverizer maintenance and
service as pulverizer grinding surfaces wear.
In summary, when all the factors of agglomeration versus non-agglomeration, nitrogen and
oxygen content of the coals, and the grindability index are taken into account, this analysis
demonstrates that, for the coal used at Jim Bridger 3, the more applicable presumptive BART
limit for NO* emissions is 0.28 lb per MMBtu. The BART analysis for NO* emissions from
Jim Bridger 3 is further described below.
Step 1: ldentify All Available Retrofit Control Technologies
The first step of the BART process is to evaluate NO" controltechnologies with practical
potential for application to Jim Bridger 3, including those control technologies identified as
Best Available Control Technology (BACT) or lowest achievable emission rate (LAER) by
permitting agencies across the United States. A broad range of information sources have been
reviewed in an effort to identifr potentially applicable emission controltechnologies. NO*
emissions at Jim Bridger 3 are currently controlled through the use of good combustion
practices and OFA.
The following potentialNO* control technology options were considered:
o New/modified LNBs with advanced OFAo Rotating Opposed Fire Air (ROFA)o Conventional selective non-catalytic reduction (SNCR) systemo Selective catalytic reduction (SCR) system
Step 2: Eliminate Technically lnfeasible Options
For Jim Bridger 3, a tangential-fired configuration burning sub-bituminous coal, technical
feasibility will primarily be determined by physical constraints, boiler configuration, and on the
ability to achieve the regulatory presumptive limit (used as a guide) of 0.28 lb NO* per MMBtu.
Jim Bridger 3 has an uncontrolled NO* emission rate of 0.45 lb per MMBtu.
Exhibit No. 1
Case No. IPC-E-13-16 3-7
T. Harvey, IPC
Page 22 of 97
JMS EYlO2OOTOO1SLC\BART JB3 OCT2OOT FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
For this BART analysis, information pertaining to LNBs, OFA, SNCR, and SCR were based on
the Multi-Pollutant Control Report (Sargent and Lundy, 2002,hereafter referred to as the S&L
Study). Updated cost estimates for SCR and SNCR were used (Sargent & Lundy, 2006).
PacifiCorp provided additional emissions data and costs developed by boiler vendors for LNBs
and OFA. Also, CH2M HILL solicited a proposal from Mobotec for their ROFA technology.
With SNCR, an amine-based reagent such as ammonia, or more commonly urea, is injected
into the furnace within a temperature range of 1,600 degrees Fahrenheit ('F) to 2,100oF, where
it reduces NO* to nitrogen and water. NO* reductions of up to 40 to 60 percent have been
achieved, although l5 to 30 percent is more realistic for most applications. SNCR is typically
applied on smaller units. Adequate reagent distribution in the furnaces of large units can be
problematic.
Table 3-2 summarizes the control technology options evaluated in this BART analysis, along
with projected NO* emission rates. All technologies can meet the applicable presumptive
BART limit of 0.28 lb per MMBtu.
TABLE 3.2
N0, Control Technology Projected Emission Rates
Jin Bridger 3
Technology Projected Emission Rate (pounds per
million British thermal units)
Presumptive Best Available
Retrofit Technology (BART) Limit
Low-NO" burners (LNBs) with
over-fire air (OFA)
Rotating Opposed Fire Air
LNB with OFA and Selective
Non-catalytic Reduction (SNCR)
LNB with OFA and Selective
Catalytic Reduction (SCR)
0.28
0.24
0.22
0.20
0.07
Step 3: Evaluate Control Effectiveness of Remaining ControlTechnologies
Preliminary vendor proposals, such as those used to support portions of this BART analysis,
may be technically feasible and provide expected or guaranteed emission rates; however, the
proposals include inherent uncertainties. These proposals are usually prepared in a limited time
frame, may be based on incomplete information, may contain over-optimistic conclusions, and
are non-binding. Therefore, emission rate values obtained in such preliminary proposals must
be qualified, and it must be recognized that contractual guarantees are established only after
more detailed analysis has been completed. The following subsections describe the control
technologies and the controleffectiveness evaluated in this BART analysis.
New LNBs with OFA System. The mechanism used to lower NO* with LNBs is to stage the
combustion process and provide a fuel rich condition initially;this is so oxygen needed for
combustion is not diverted to combine with nitrogen and form NO*. Fuel-rich conditions favor
Exhibit No. 1
Case No. lPc-E-13-16 3-8
T. Harvey, IPC
Page 23 of 97
JMS EY1O2OO7OO1 SLC\BART.JB3-OCT2OO7_FINAL,DOC
BART ANALYSIS FOR JII\I BRIDGER UNIT 3
the conversion of fuel nitrogen to nitrogen instead of NO*. Additional air (or OFA) is then
introduced downstream in a lower temperature zone to burn out the char.
Both LNBs and OFA are considered to be a capital cost, combustion technology retrofit. For
LNB retrofits to units configured with tangential-firing such as Jim Bridger 3, it is generally
necessary to increase the bumer spacing; this prevents interaction of the flames from adjacent
burners and reduces burner zone heat flux. These modifications usually require boiler
waterwall tube replacement.
Information provided to CH2M HILL by PacifiCorp-based on the S&L Study and data from
boiler vendors-indicates that a new LNB and OFA retrofit at Jim Bridger 3 would result in an
expected NO* emission rate of 0.24Ib per MMBtu. PacifiCorp has indicated that this rate
corresponds to a vendor guarantee, not a vendor prediction, and they believe that this emission
rate can be sustained as an average between overhauls. This emission rate represents a
significant reduction from the current NO* emission rate, and is below the more applicable
presumptive NO* emission rate of 0.28 lb per MMBtu.
Rotating Opposed Fire Air. Mobotec markets ROFA as an improved second generation OFA
system. Mobotec states that "the flue gas volume of the furnace is set in rotation by
asymmetrically placed air nozzles. Rotation is reported to prevent laminar flow, so that the
entire volume of the furnace can be used more effectively for the combustion process. In
addition, the swirling action reduces the maximum temperature of the flames and increases heat
absorption. The combustion air is also mixed more effectively." A typical ROFA installation
would have a booster fan(s) to supply the high velocity air to the ROFA boxes, and Mobotec
would propose two 4,000 to 4,300 horsepower fans for Jim Bridger 3.
Mobotec proposes to achieve a NO* emission rate of 0.1 8 lb per MMBtu using ROFA
technology. An operating margin of 0.04 lb per MMBtu was added to the expected rate due to
Mobotec's limited ROFA experience with western sub-bituminous coals. Under the Mobotec
proposal, which is primarily based on ROFA equipment, the operation of existing LNB and
OFA ports would be analyzed. While a typical installation does not require modification to the
existing LNB system and the existing OFA ports are not used, results of computational fluid
dynamics modeling would determine the quantity and location of new ROFA ports. The
Mobotec proposal includes bent tube assemblies for OFA port installation.
Mobotec would not provide installation services, because they believe that the Owner can more
cost effectively contract for these services. However, they would provide one onsite
construction supervisor during installation and startup.
Selective Non-catalytic Reduction. With SNCR-a process generally utilized to achieve modest
NO* reductions on smaller units-an amine-based reagent such as ammonia, or more
commonly urea, is injected into the furnace within a temperature range of l,600oF to 2,100oF,
where it reduces NO* to nitrogen and water. NO* reductions of up to 60 percent have been
achieved, although 20 to 40 percent is more realistic for most applications.
Reagent utilization, which is a measure of the efficiency with which the reagent reduces NO*
can range from 20 to 60 percent, depending on the amount of reduction, unit size, operating
conditions, and allowable ammonia slip. With low reagent utilization, low temperatures, or
inadequate mixing, ammonia slip occurs, allowing unreacted ammonia to create problems
Exhibit No. 1
Case No. IPC-E-13-16 3-e
T. Harvey, IPC
Page 24 ot 97
JMS EY1 O2OO7OO1 SLC\BART_JB3_OCT2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
downstream. The ammonia may render fly ash unsaleable, react with sulfur to foul heat
exchange surfaces, and/or create a visible stack plume. Reagent utilization can have a
significant impact on economics, with higher levels of NO* reduction generally resulting in
lower reagent utilization and higher operating cost.
Reductions from higher baseline concentrations (inlet NO*) are lower in cost per ton, but result
in higher operating costs, due to greater reagent consumption. To reduce reagent costs, S&L
has assumed that combustion modifications including LNBs and advanced OFA, capable of
achieving a projected NO* emission rate of 0.24Ib per MMBtu. At a further reduction of
15 percent in NO* emission rates for SNCR would result in a projected emission rate of 0.20 lb
per MMBtu.
Selective Catalytic Reduction. While working on the same chemical principle as SNCR, SCR
uses a catalyst to promote the chemical reaction. Ammonia is injected into the flue-gas stream,
where it reduces NO* to nitrogen and water. Unlike the high temperatures required for SNCR,
in SCR the reaction takes place on the surface of a vanadium/titanium-based catalyst at a
temperature range between 580oF to 750oF. Due to the catalyst, the SCR process is more
efficient than SNCR and results in lower NO* emissions. The most common type of SCR is the
high-dust configuration, where the catalyst is located downstream from the boiler economizer
and upstream of the air heater and any particulate control equipment. . In this location, the SCR
is exposed to the full concentration of fly ash in the flue gas that is leaving the boiler. The
high-dust configuration is assumed for Jim Bridger 3. In a full-scale SCR, the flue ducts are
routed to a separate large reactor containing the catalyst. With in-duct SCR, the catalyst is
located in the existing gas duct, which may be expanded in the area of the catalyst to reduce
flue gas flow velocity and increase flue gas residence time. Due to the higher removal rate, a
full-scale SCR was used as the basis for analysis at Jim Bridger 3.
S&L prepared the design conditions and cost estimates for SCR at Jim Bridger 3. As with
SNCR, it is generally more cost effective to reduce NO* emission levels as much as possible
through combustion modifications, in order to minimize the catalyst surface area and ammonia
requirements of the SCR. The S&L design basis for LNB with OFA and SCR results in a
projected NO* emission rate of 0.07 lb per MMBtu. Additional catalyst surface was included in
the SCR design to accommodate the characteristics of the coal used at Jim Bridger 3.
Level of Confidence for Vendor Post-control Emissions Estimates. In order to determine the level
of NO* emissions needed to consistently achieve compliance with an established goal, a review
of typical NO* emissions from coal-fired generating units was completed. As a result of this
review, it was noted that NO* emissions can vary significantly around an average emissions
level. Variations may result for many reasons, including coal characteristics, unit load, boiler
operation including excess air, boiler slagging, burner equipment condition, coal mill fineness,
and so forth.
The steps utilized for determining a level of confidence for the vendor expected value are as
follows:
o Establish expected NO* emissions value from vendor.
o Evaluate vendor experience and historical basis for meeting expected values.
Exhibit No. 1
Case No. IPC-E-13-16 'I1o
T. Harvey, IPC
Page 25 of 97
JMS EY1 O2OO7OOl SLC\BART_JB3,OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
o Review and evaluate unit physical and operational characteristics and restrictions. The
fewer variations there are in operations, coal supply, etc., the more predictable and less
variant the NO* emissions are.
o For each technology expected value, there is a corresponding potential for actual NO*
emissions to vary from this expected value. From the vendor information presented, along
with anticipated unit operational data, an adjustment to the expected value can be made.
Step 4: Evaluate lmpacts and Document the Results
This step involves the consideration of energy, environmental, and economic impacts
associated with each controltechnology. The remaining useful life of the plant is also
considered during the evaluation.
Energy lmpacts. Installation of LNBs and modification to the existing OFA systems are not
expected to significantly impact the boiler efliciency or forced draft fan power usage.
Therefore, these technologies will not have energy impacts.
The Mobotec ROFA system would require installation and operation of two 4,000 to
4,300 horsepower ROFA fans (6,410 kW total). The SNCR system would require
approximately 520 kW of additionalpower.
Selective catalytic reduction retrofit impacts the existing flue gas fan systems, due to the
additional pressure drop associated with the catalyst, which is typically a 6- to 8-inch water
gage increase. Total additional power requirements for SCR installation at Jim Bridger 3 are
estimated at approximately 3,220 kW, based on the S&L Study.
Environmental lmpacts. Mobotec has predicted that carbon monoxide emissions, and unburned
carbon in the ash, commonly referred to as loss on ignition, would be the same or lower than
prior levels for the ROFA system.
The installation of SNCR or SCR systems could impact the saleability and disposal of fly ash
due to ammonia levels, and could potentially create a visible stack plume, which may negate
other visibility improvements. Other environmental impacts involve the storage of ammonia
(especially if anhydrous ammonia is used), and the transportation of the ammonia to the power
plant site.
Economic lmpacts. Costs and schedules for the LNBs and OFA, SNCR, and SCR were
furnished to CH2M HILL by PacifiCorp, developed using S&L's internal proprietary database,
and supplemented (as needed) by vendor-obtained price quotes. The relative accuracy of these
cost estimates is stated by S&L to be in the range of plus or minus 20 percent. Cost for the
ROFA system was obtained from Mobotec.
A comparison of the technologies on the basis of costs, design control efficiencies, and tons of
NO* removed is summarized in Table 3-3, and the first year control costs are presented in
Figure 3-4. The complete economic analysis is contained in Appendix A.
Exhibit No. 1
Case No.|PC-E-13-16
T. Harvey, IPC
Page 26 of 97
JMS EY1 O2OO70O1 SLC\BARI_JB3_OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
TABLE 3.3
NO, Control Cost Comparison
Jim Bridger 3
Factor
Low-NOr
Bumers
(LNBs) with
Over-firc Air
(oFA)
Mobotec
Rotating
Opposed Fire
Air(ROFA)
LNB with
OFA and
Selective
Non-
Catalytic
Reduction
(sNcR)
LNB with OFA
and Selective
Catalytic
Reduction
(scR)
Total lnstalled Capital Costs
Total First Year Fixed and Variable
Operation and Maintenance Costs
Total First Year Annualized Cost
Power Consumption (megawatts [MWl)
Annual Power Usage
(million MW-hours per year)
NO, Design Control Efficiency
NO, Removed per Year (Tons)
Nitrogen Oxide (NO^) Design Control
Efficiency
lncremental Control Cost
(dollars per ton [$/ton] of NO, Removed)
$8.7 million
$0.1 million
$0.9 million
0
0
46.7o/o
4,967
$181/ton
$181/ton
$20.5 million
$2.6 million
$4.6 million
6.4
s0.6
51.1%o
5,440
$843/ton
$7,797lton
22.0 million
$1.5 million
$3.6 million
0.5
4.1
5s.6%
5,913
$61O/ton
$2,863/ton
$129.6 million
$3.3 million
$15.6 million
3.3
2s.4
84.4Yo
8,987
$1,7%lton
$3,896/ton
Preliminary BART Selection. CH2M HILL recommends selection of LNBs with OFA as BART
for Jim Bridger 3 based on its significant reduction in NO* emissions, reasonable control cost,
and no additional power requirements or environmental impacts. Low-NO* burners with OFA
does not meet the EPA presumptive limit of 0.15 lb per MMBtu for sub-bituminous coal, but it
does meet an emission rate that falls between the presumptive limit of 0.28 lb per MMBtu for
bituminous coal and the limit of 0.15 lb per MMBtu for sub-bituminous coal. As discussed in
the section on coal quality, the recommended technology and the achieved emission rate are
deemed appropriate as BART for NO* emissions from the coals combusted at Jim Bridger 3.
Step 5: Evaluate Visibility lmpacts
Please see Section 4, BART Modeling Analysis.
Exhibit No. 1
Case No. lPc-E-13-16 3'12
T. Harvey, IPC
Page27 ot97
JMS EY1 O2OOTO()lSLC\BART-JB3-OCT2OO7-FINAL.DOC
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Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 28 of 97
BART ANALYSIS FOR JIM BRIDGER UNIT 3
3.2.2 BART SOz Analysis
Sulfur dioxide forms in the boiler during the combustion process, and is primarily dependent on
coal sulfur content. The BART analysis for SOz emissions on Jim Bridger 3 is described below.
Step 1: Identify AII Available Retrofit Control Technologies
A broad range of information sources were reviewed, in an effort to identify potentially
applicable emission control technologies for SOz at Jim Bridger 3. This included control
technologies identified as BACT or LAER by permitting agencies across the United States.
The following potential SOz control technology options were considered:
. Optimize current operation of existing wet sodium FGD system. Upgrade wet sodium FGD system to meet SOz emission rate of 0.10 lb per MMBtuo New dry FGD system
Step 2: Eliminate Technically lnfeasible Options
Technical feasibility will primarily be based on the regulatory presumptive limit (used as a
guideline) of 95 percent reduction in SOz emissions, or 0.15 lb per MMBtu. Based on the coal
that Jim Bridger 3 currently burns, the unit would be required to achieve an 87.5 percent SO2
removal efficiency to meet the presumptive limit of 0. l5 lb per MMBtu.
Table 3-4 summarizes the controltechnology options evaluated in this BART analysis, along
with projected SOz emission rates. Only one technology option can meet the applicable
presumptive BART limit of 0.15 lb per MMBtu.
TABLE 3.4
S0z Control Technology Emission Rates
Jim Bridger 3
Projected Sulfur Dioxide (SOz)Technology Emission Rate (pound per million
British thermal units)
Presumptive Best Available Retrofit 0.1 5
Technology Limit
Upgrade Existing Wet Sodium System 0.10
Optimize Existing Wet Sodium System 0.20
New Dry Flue Gas Desulfurization 0.21
System
Wet Sodium FGD System. Wet sodium FGD systems operate by treating the flue gas in large
scrubber vessels with a soda ash solution. The scrubber mixes the flue gas and alkaline reagent
using a series of spray nozzles to distribute the reagent across the scrubber vessel. The sodium
in the reagent reacts with the SOz in the flue gas to form sodium sulfite and sodium bisulfite,
which are removed from the scrubber and disposed.
Exhibit No-_1_ 3-14Case No. IPC-E-13-16
T. Harvey, IPC
Page 29 of 97
JMS EYlO2OOTOOlSLC\BART J83 OCT2OOT_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
The wet sodium FGD system at Jim Bridger 3 currently achieves approximately 78 percent SO2
removal to achieve an SOz outlet emission rate of 0.27 lb per MMBtu. Optimizing the existing
wet FGD system would achieve an SOz outlet emission rate of 0.20 lb per MMBtu
(83.3 percent SOz removal) by partially closing the bypass damper to reduce routine bypass
flue gas flow used to reheat the treated flue gas from the scrubber, relocating the opacity
monitor, and modifying the system to minimize scaling problems.
Upgrading the wet FGD system would achieve an SOz outlet emission rate of 0.10 lb per
MMBtu (91.7 percent SOz removal) by closing the bypass damper to eliminate routine bypass
flue gas flow used to reheat the treated flue gas from the scrubber, relocating the opacity
monitor, adding new fans, adding a stack liner and drains for wet operation, and using a refined
soda ash reagent. It is considered technically infeasible for the present wet FGD system to
achieve 95 percent SO2 removal (0.06 lb per MMBtu) on a continuous basis, since this high
level of removal must be incorporated into the original design of the scrubber.
Optimizing the existing wet sodium scrubbing FGD system is projected to achieve an outlet
emission rate of 0.20 Ib per MMBtu which would not meet the presumptive limit of 0.15 Ib SO2
per MMBtu. Therefore, this option is eliminated as technically infeasible for this analysis. An
upgraded wet sodium scrubbing FGD system is projected to achieve an outlet emission rate of
0.10 lb per MMBtu (91 .7 percent SOz removal) which would meet the presumptive limit of
0.15 lb SO2 per MMBtu for Jim Bridger 3.
New Dry FGD System. The lime spray dryer typically injects lime slurry in the top of the
absorber vessel with a rapidly rotating atomizer wheel. The rapid speed of the atomizer wheel
causes the lime slurry to separate into very fine droplets that intermix with the flue gas. The
SOz in the flue gas reacts with the calcium in the lime slurry to form dry calcium sulfate
particles. At Jim Bridger 3, this dry particulate matter would be captured downstream in the
existing ESP, along with the fly ash. A lime spray dryer system typically produces a dry waste
product suitable for landfill disposal.
The dry FGD system with the existing ESP is projected to achieve 82.5 percent SOz removal at
Jim Bridger 3. This would result in a controlled SOz emission rate of 0.21 lb per MMBtu, based
on an uncontrolled SOz emission rate of 1.20 lb per MMBtu. Therefore, this option cannot meet
the presumptive limit of 0.15 lb SOz per MMBtu, and is eliminated from further analysis as
technically infeasible.
Step 3: Evaluate Control Effectiveness of Remaining Control Technologies
When evaluating the controleffectiveness of SOz reduction technologies, each option can be
compared against benchmarks of performance. One such benchmark is the presumptive BART
emission limit because Jim Bridger 3 is required to meet this limit. As indicated previously, the
presumptive limit for SOz on a BART-eligible coal burning unit is 95 percent removal, or
0.15 lb per MMBtu.
The projected emission rate for an upgraded wet sodium FGD system for Jim Bridger 3 would
be 0.10 lb per MMBtu. This option would meet the presumptive SOz limit of 0.15 lb per
MMBtu.
Exhibit No..l
3_15Case No. IPC-E-13-16
T. Harvey, IPC
Page 30 of97
JMS EY1 O2OO7OO1 SLC\BART_JB3_OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
Step 4: Evaluate lmpacts and Document the Results
This step involves the consideration of energy, environmental, and economic impacts
associated with each controltechnology. The remaining useful life of the plant is also
considered during the evaluation.
Energy lmpacts. Upgrading the existing wet sodium FGD system would require an additional
520 kW of power.
Environmental lmpacts. There will be incremental additions to scrubber waste disposal and
makeup water requirements. Another environmental impact is a reduction of the stack gas
temperature from 140"F to l20oF due to elimination of the bypassed flue gas which had
provided approximately 20"F of reheat.
Economic lmpacts. A summary of the costs and amount of SOz removed for the upgraded wet
sodium FGD system is provided in Table 3-5. The complete economic analysis is contained in
Appendix A.
TABLE 3.5
SOz Control Cost Comparison (lncrementalto Existing FGD System)
Jin Bridger Unit 3
Factor Upgraded Wet Flue Gas Desulfurization (FGD)
Total lnstalled Capital Costs
Total First Year Fixed and Variable Operation and
Maintenance Costs
Total First Year Annualized Cost
Additional Power Consumption (megawatts [MWl )
Additional Annual Power Usage (1000 MW-hours
per year)
lncremental Sulfur Dioxide (SO2) Design Control
Efficiency
lncremental Tons SOz Removed per Year
First Year Average Control Cost (dollars per ton
[$/Ton1 of SOz Removed)
lncremental Control Cost
($/Ton of SOz Removed)
$13.0 million
$1.3 million
$2.5 million
0.5
4.1
62.5yo (91.7o/o based on Uncontrolled SO2)
3,950
632
632
Preliminary BART Selection. CH2M HILL recommends upgrading the existing wet sodium FGD
system as BART for Jim Bridger 3 based on its significant reduction in SOz emissions (meeting
presumptive limit of 0.15 lb per MMBtu), reasonable control costs, and the advantages of
minimal additional power requirements and environmental impacts.
Step 5: Evaluate Visibility lmpacts
Please see Section 4, BART Modeling Analysis.
Exhibit No,f_
3.16Case No. IPC-E-13-16
T. Harvey, IPC
Page 3'l of 97
JMS EYl 02OO7OO1 SLC\BART_JB3_OCT2OO7-FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
3.2.3 BART PMro Analysis
Jim Bridger 3 is currently equipped with an ESP. Electrostatic precipitators remove particulate
matter (PM) from the flue gas stream by charging fly ash particles with a very high direct
current voltage, and attracting these charged particles to grounded collection plates. A layer of
collected PM forms on the collecting plates and is removed by periodically rapping the plates.
The collected ash particles drop into hoppers below the precipitator and are removed
periodically by the fly ash-handling system. Historically, the ESP at Jim Bridger 3 has
controlled PMle emissions to levels below 0.057 lb per MMBtu.
The BART analysis for PMro emissions at Jim Bridger 3 is described in this section. For the
modeling analysis in Section 4, PMro was used as an indicator for PM, and PMro includes
particulate matter less than 2.5 micrometers in aerodynamic diameter (PMz s) as a subset.
Step 1: Identify All Available Retrofit Control Technologies
Two retrofit control technologies have been identified for additional PM control:
o Flue gas conditioningo Polishing fabric filter (baghouse) downstream of existing ESP
Another available control technology is replacing the existing ESP with a new fabric filter.
Because the environmental benefits of replacing the fabric filter are also achieved by the
lower-cost option of installing a polishing fabric filter downstream of the existing ESP,
installation of a full fabric filter was not considered in the analysis.
Step 2: Eliminate Technically lnfeasible Options
Flue Gas Conditioning. If the fly ash from coal has high resistivity, such as fly ash from
sub-bituminous coal, the ash is not collected effectively in an ESP. This is because the high
resistivity makes the particles less willing to accept an electrical charge. Adding flue gas
conditioning (FGC), which is typically accomplished by injection of sulfur trioxide (SOr), will
lower the resistivity of the particles so that they will accept more charge and allow the ESP to
collect the ash more effectively. Flue gas conditioning systems can account for large
improvements in collection efficiency for small ESPs.
Polishing Fabric Filter. A polishing fabric filter could be added downstream of the existing ESP
at Jim Bridger 3. One such technology is licensed by the Electric Power Research Institute, and
referred to as a COHPAC (Compact Hybrid Particulate Collector). The COHPAC collects the
ash that is not collected by the ESP, thus acting as a polishing device. The ESP needs to be kept
in service for the COHPAC fabric filter to operate effectively.
The COHPAC fabric filter is about one-half to two-thirds the size of a full-size fabric filter,
because the COHPAC has a higher air-to-cloth ratio (7 to 9: I ), compared to a full-size pulse jet
fabric filter (3.5 to 4:l).
Step 3: Evaluate Control Effectiveness of Remaining Control Technologies
The existing ESP at Jim Bridger 3 is achieving a controlled PM emission rate of 0.057 lb per
MMBtu. Utilizing flue conditioning upstream of the existing ESP is projected to reduce PM
emissions to approximately 0.030 lb per MMBtu. Adding a COHPAC fabric filter downstream
of the existing ESP is projected to reduce PM emissions to approximately 0.015 lb per MMBtu.
Exhibit No. 1 "Cr"" rlo IPC-E-13-16 3-17
T. Harvey, IPC
Page 32 of 97
JMS EY1 O2OO7OO1 SLC\BART-JB3-OCT2OO7-FINAL,DOC
BART ANALYSIS FOR JIM BRIOGER UNIT 3
O The PMrocontroltechnology emission rates are summarized in Table 3-6.
TABLE }6
PMro Control Technology Emission Rates
Jin Bridger 3
Short-term Projected PMro("
control rechnology EmissionRate (pound per
British thermal units)
Flue Gas Conditioning
Polishing Fabric Filter
0.030
0.015
NOTES:(")PMro refers to particulate matter less than '10 micrometers in
aerodynamic diameter
Step 4: Evaluate lmpacts and Document the Results
This step involves the consideration of energy, environmental, and economic impacts
associated with each control technology. The remaining useful life ofthe plant is also
considered during the evaluation.
Energy lmpacts. Energy is required to overcome the additional pressure drop from the
COHPAC fabric filter and associated ductwork. Therefore, a COHPAC retrofit will require an
internal diameter fan upgrade and upgrade of the auxiliary power supply system.
The COHPAC fabric filter at Jim Bridger 3 would require approximately 3.3 MW of power,
equating to an annual power usage of approximately 26.3 million kW-Hr.
There is only a small power requirement of approximately 50 kW associated with flue gas
conditioning.
Environmental lmpacts. There are no negative environmental impacts from the addition of a
COHPAC polishing fabric filter or flue gas conditioning system.
Economic Impacts. A summary of the costs and PM removed for COHPAC and flue gas
conditionings are recorded in Table 3-7, and the first-year control costs for flue gas
conditioning and fabric filters are shown in Figure 3-5. The complete economic analysis is
contained in Appendix A.
Exhibit No.l^ $18Case No. IPC-E-13-16
T. Harvey, IPC
Page 33 of 97
JMS EY1 O20O7OOl SLC\BART_JB3_OCT2OOT.FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
TABLE 3.7
PMro Control Cost Comparison (lncrementalto Existing ESP)
Jim Bridger 3
Factor
Flue Gas
Conditioning Polishing Fabric Filter
Total lnstalled Capital Costs
Total First Year Fixed and Variable Operations and
Maintenance Costs
Total First Year Annualized Cost
Additional Power Consumption (MW)
Annual Power Usage (million kilowatt-hours per
year)
lncremental Particulate Matter (PM) Design Control
Efficiency
lncremental Tons PM Removed per Year
First Year Average Control Cost
(dollars per ton [$/Ton1 of PM Removed)
lncremental Control Cost
($/Ton of PM Removed)
$o
$0.2 million
$0.2 million
0.05
0.4
47.4%
275
$48.4 million
$1.7 million
$ 6.3 million
3.43
26.3
73.7Yo
993
6,381
17,371
639
275
Preliminary BART Selection. CH2M HILL recommends selection of flue gas conditioning
upstream of the existing ESP as BART for Jim Bridger 3 based on the significant reduction in
PM emissions, reasonable control costs, and advantages of minimal additional power
requirements and no environmental impacts.
Step 5: Evaluate Visibility lmpacts
Please see Section 4, BART Modeling Analysis.
Exhibit No. 'l
Case No. IPC-E-13-16
T. Harvey, IPC
Page 34 of 97
JMS EYIO2OOTOOISLC\BART JB3 OCT2OOT FINAL.DOC
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Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 35 of 97
4.0 BART Modeling Analysis
4.1 Mode! Selection
CH2M HILL used the CALPUFF modeling system to assess the visibility impacts of emissions
from Jim Bridger 3 at nearby Class I areas. The Class I areas potentially affected are located
more than 50 kilometers but less than 300 kilometers from the Jim Bridger 3 facility. The
Class I areas include the following wilderness areas (WA):
o Bridger WAo Fitzpatrick WAo Mt. Zirkel WA
The CALPUFF modeling system includes the CALMET meteorological model, a Gaussian
puff dispersion model (CALPUFF) with algorithms for chemical transformation and
deposition, and a post processor capable of calculating concentrations, visibility impacts, and
deposition (CALPOST). The CALPUFF modeling system was applied in a full, refined mode.
Version numbers of the various programs in the CALPUFF system used by CH2M HILL were
as follows:
o CALMET Version 5.53a,Level 040716o CALPUFF Version 5.7lla, Level0407l6o CALPOST Version 5.51, Level 030709
4.2 CALMET Methodology
4.2.1 Dimensions of the Modeling Domain
CH2M HILL used the CALMET modelto generate a three-dimensional wind field and other
meteorological parameters suitable for use by the CALPUFF model. A modeling domain was
established to encompass the Jim Bridger 3 facility and allow for a 50-kilometer buffer around
the Class I areas that were within 300 kilometers of the facility; the grid resolution was
4 kilometers. Figure 4-l shows the extent of the modeling domain. Except when specifically
instructed otherwise by the Wyoming Department of Environmental Quality - Air Quality
Division (WDEQ-AQD), CH2M HILL followed the methodology spelled out in the
WDEQ-AQD BART Modeling Protocol, a copy of which is included as Appendix B.
CH2M HILL used the Lambert Conformal Conic map projection for the analysis due to the
large extent of the domain. The latitude of the projection origin and the longitude of the central
meridian were chosen at the approximate center of the domain. Standard parallels were drawn
to represent one-sixth and five-sixths of the north-south extent of the domain to minimize
distortion in the north-south direction.
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 36 of 97
JMS EYIO2OOTOO1SIC\BART JB3 OCT2OOT FINAL.DOC
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Page 37 of 97
BART ANALYSIS FOR JIM BRIDGER UNIT 3
The default technical options listed in TRC Companies, Inc.'s (TRC) current example
CALMET.inp file were used for CALMET. Verticalresolution of the wind field included ten
layers, with vertical face heights as follows (in meters):
. 0,20,40, 100, 140,320,580, 1020, 1480,2220,3500
Other user-specified model options were set to values established by WDEQ-AQD which
appear in Table 3 of Appendix B. Table 4-1 lists the key user-specified options used for this
analysis.
TABLE +1
User-specifi ed CALMET Options
Jim Bridger 3
CALMET lnput Parameter Value
CALMET lnput Group 2
Map projection (PMAP)
Grid spacing (DGRIDKM)
Number vertical layers (NZ)
Top of lowest layer (m)
Top of highest layer (m)
CALMET lnput Group 4
Observation mode (NOOBS)
CALMET lnput Group 5
Prog. Wind data (IPROG)
(RMAXI)
(RMAX2)
Terrain influence (TERRAD)
(R1)
(R2)
CALMET lnput Group 6
Max mixing ht (ZIMAX)
Lambert Conformal
4
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20
3500
14
30
50
15
5
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3s00
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 38 of 97
JMS EY1 O2OO7OO,I SLC\BART_JB3_OCT2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
4.2.2 CALMET Input Data
CH2M HILL ran the CALMET model to produce three years of analysis: 2001,2002, and
2003. WDEQ-AQD provided l2-km resolution Mesoscale Meteorological Model, Version 5
(MM5) meteorological data fields that covered the entire modeling domain for each study year.
These three data sets were chosen because they are current and have been evaluated for quality.
The MM5 data were used as input to CALMET as the "initial guess" wind field. The initial
guess wind field was adjusted by CALMET for local terrain and land use effects to generate a
Step I wind field, and further refined using local surface observations to create a final Step 2
wind field.
Surface data for 2001 through 2003 were obtained from the National Climatic Data Center.
CH2M HILL processed the data from the National Weather Service's Automated Surface
Observing System network for all stations that are in the domain. The surface data were
obtained in abbreviated DATSAV3 format. A conversion routine available from the TRC Web
site was used to convert the DATSAV3 files to CD-144 format for input into the SMERGE
preprocessor and CALMET.
Land use and terrain data were obtained from the U.S. Geological Survey (USGS). Land use
data were obtained in Composite Theme Grid format from the USGS, and the Level I USGS
land use categories were mapped into the l4 primary CALMET land use categories. Surface
properties such as albedo, Bowen ratio, roughness length, and leaf area index were computed
from the land use values. Terrain data were taken from USGS l-degree Digital Elevation
Model data, which primarily derive from USGS l:250,000 scale topographic maps. Missing
land use data were filled with values that were assumed appropriate for the missing area.
Precipitation data were obtained from the National Climatic Data Center. All available data in
fixed-length,TD-3240 format were obtained for the modeling domain. The list of available
stations that have collected complete data varies by year, but CH2M HILL processed all
available stations/data within the domain for each year. Precipitation data were prepared with
the PXTRACT/PMERGE processors in preparation for use within CALMET.
Upper-air data were prepared for the CALMET model with the READ62 preprocessor for the
following stations:
o Denver, Coloradoo Salt Lake City, Utaho Riverton, Wyoming. Rapid City, South Dakota
Figure 4-2 shows the locations of surface and upper air stations within the MM5 modeling
domain.
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 39 of 97
JMS EYlO2OOTOOlSLC\BART J83 OCT2OOT,FINAL.DOC
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4.2.3 Validation of CALMET Wind Field
CH2M HILL used the CALDESK data display and analysis system (v2.97, Enviromodeling
Ltd.) to view plots of wind vectors and other meteorological parameters to evaluate the
CALMET wind fields. The CALDESK displays were compared to observed weather
conditions, as depicted in surface and upper-air weather maps (National Oceanic and
Atmospheric Administration, 2006).
4.3 CALPUFF Modeling Approach
For the BART controltechnology visibility improvement modeling, CH2M HILL followed
WDEQ-AQD guidance provided (WDEQ-AQD, 2006).
CH2M HILL drove the CALPUFF model with the meteorological output from CALMET
over the modeling domain described earlier. The CALPUFF model was used to predict
visibility impacts for the pre-control (baseline) scenario for comparison to the predicted
impacts for post-control scenarios for Jim Bridger 3.
4.3.1 Background Ozone and Ammonia
Hourly values of background ozone concentrations were used by CALPUFF for the
calculation of SOz and NO. transformation with the MESOPUFF II chemical transformation
scheme. CH2M HILL obtained hourly ozone data from the following stations located within
the modeling domain for 2001, 2002, and2003:
. Rocky Mountain National Park, Coloradoo Craters of the Moon National Park, Idaho. Highland, Utaho Thunder Basin National Grasslands, Wyomingo Yellowstone National Park, Wyomingo Centennial, Wyomingo Pinedale, Wyoming
For periods of missing hourly ozone data, the chemicaltransformation relied on a monthly
default value of 44 parts per billion. Background ammonia was set to 2 parts per billion. Both
of these background values were taken from the guidance document (WDEQ-AQD, 2006).
4.3.2 Stack Parameters
The stack parameters used for the baseline modeling reflect those that are in place under the
current permit for Jim Bridger 3. Post-control stack parameters reflect the anticipated
changes associated with installation of the control technology alternatives that are being
evaluated. The maximum heat input rate of 6,000 MMBtu per hour was used to calculate a
maximum emission rate. Measured velocities and stack flow rates were used in the modeling
to represent a worst-case situation.
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 41 of97
JMS EY1 O2OO7OO1 SLC\BART_JB3-OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIOGER UNIT 3
4.3.3 Emission Rates
Pre-control emission rates for Jim Bridger 3 reflect peak 24-hour average emissions that may
occur under the source's current permit. The emission rates reflect actual emissions under
normal operating conditions, as described by the EPA in the Regional Haze Regulations and
Guidelines for Best Available Retrofit Technologt Determinations; Final Rule
(40 CFR Part 5l).
CH2M HILL used available continuous emission monitoring data to determine peak 24-hour
emission rates. Data reflected operations from the most recent 3- to 5-year period unless a
more recent period was more representative. Allowable short-term (24-hour or shorter
period) emissions or short-term emission limits were used if continuous emission monitoring
data were not available.
Emissions were modeled for the following pollutants:
. SOz. NO*. Coarse particulate (PM2 5<diameter<PM16). Fine particulate (diameter<PM2 5). Sulfates
Post-control emission rates reflect the effects of the emissions control scenario under
consideration. Modeled pollutants were the same as those listed for the pre-control scenario.
4.3.4 Post-control Scenarios
Four post-control modeling scenarios were developed to cover the range of effectiveness for
the combination of the individualNO*, SO2, and PM controltechnologies being evaluated.
The selection of each control device was made based on the engineering analyses described
in Section 3 for reasonable technologies that would meet or exceed the presumptive BART
levels for each pollutant.
. Scenario 1: New LNB with OFA modifications, upgraded wet FGD system and flue gas
conditioning for enhanced ESP performance. As indicated previously, this scenario
represents CH2M HILL's preliminary BART recommendation.
. Scenario 2: New LNB with OFA modifications, upgraded wet FGD system and new
polishing fabric fi lter.
. Scenario 3: New LNB with OFA modifications and SCR, upgraded wet FGD system and
flue gas conditioning for enhanced ESP performance.
. Scenario 4: New LNB with OFA modifications and SCR, upgraded wet FGD system and
new polishing fabric filter.
The ROFA option and LNB with OFA & SCR option for NO* controlwere not included in
the modeling scenarios because their control effectiveness is between the LNB with OFA
option and the SCR option. Modeling of NO*, SOz, and PM controls alone was not
performed because any final BART solution will include a combination of control
technologies for NO*, SOz, and PM.
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 42 ot 97
JMS EYlO2OOTOOlSLC\BART JB3,OCT2OO7 FINAL.DOC
BART AMLYSIS FOR JIM BRIDGER UNIT 3
Table 4-2 presents the stack parameters and emission rates used for the Jim Bridger 3
analysis for baseline and post-control modeling. In accordance with the WDEQ BART
modeling protocol, elemental carbon stack emissions and organic aerosol emissions were not
modeled.
4.3.5 Modeling Process
The CALPUFF modeling for the control technology options for Jim Bridger 3 followed this
sequence:
. Model pre-control (baseline) emissions. Model preferred post-control scenario (if applicable). Determine degree of visibility improvement. Model other control scenarios. Determine degree of visibility improvement. Factor visibility results into the BART "five-step" evaluation
4.3.6 Receptor Grids
Discrete receptors for the CALPUFF modeling were placed at uniform receptor spacing
along the boundary and in the interior of each area of concern. Class I area receptors were
taken from the National Park Service database for Class I area modeling receptors. The TRC
COORDS program was used to convert all latitude/longitude coordinates to Lambert
Conformal Conic coordinates, including receptors, meteorological stations, and source
locations.
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 43 of 97
JMS EY.IO2OOTOO1SLC\BART JB3 OCT2OOT_FINAI.DOC
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The CALPOST processor was used to determine 24-hour average visibility results with
output specified in deciview (dV) units. Calculations of light extinction were made for each
pollutant modeled. The sum of all extinction values were used to calculate the
delta-dv (A dV) change relative to natural background. The following default light extinction
coefficients for each pollutant were used:
o Ammonium sulfate 3.0o Ammonium nitrate 3.0o PM coarse (PMro) 0.6o PM fine (PMzs) 1.0o Organic carbon 4.0o Elementalcarbon 10.0
CALPOST visibility Method 6 was used to determine the visibility impacts. Monthly relative
humidity factors were used in the light extinction calculations to account for the hygroscopic
characteristics of nitrate and sulfate particles. Table 5 of the Wyoming BART Air Modeling
Protocol (Appendix B) lists the monthly relative humidity factors for the Class I areas. These
values were used for the particular Class I area being modeled.
The natural background conditions as a reference for determining the delta-deciview (AdV)
change represented the 20 percent best natural visibility days. The EPA BART guidance
document provided dV values for the l0 percent best days for each Class I area, but did not
provide individual species concentration data for the 20 percent best days. Species
concentrations corresponding to the 20 percent best days were calculated for each Class I
area by scaling back the annual average species concentrations given in Table 2-l of
Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule
(EPA, 2003). A separate scaling factor was derived for each Class I area such that, when
multiplied by the Guidance table annual concentrations, the 20 percent best days dV value
for that area would be calculated. This procedure was taken from Protocol for BART-Related
Visibilily Improvement Modeling Analysis in North Dakota (North Dakota Department of
Health, 2005). The Wyoming BART Air Modeling Protocol (see Appendix B) did provide
natural background concentrations of aerosol components to use in the BART analysis.
Table 4-3 lists the annual average species concentrations from the BART protocol.
Exhibit No. 1c""" rlo tPc-E-13-16 4-10
T. Harvey, IPC
Page 45 of 97
JMS EY1 O2OO7OOl SLC\BART-JB3_OCT2OO7_FINAt.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
BART ANALYSIS FOR JIM BRIDGER UNIT 3
TABLE 4.3
Average Natural Levels ofAerosol Components
Jim Bidger 3
Aerosol Component
Average Natural Concentration
(micrograms per cubic meter)
for Mt. Zirkel Glass I
Wilderness Area
Average Natural Concentration
(micrograms per cubic meter)
for Fitspatrick and Bridger Glass I
Wilderness Areas
Ammonium Sulfate
Ammonium Nitrate
Organic Carbon
Elemental Carbon
Soil
Coarse Mass
0.046
0.038
0.179
0.008
0.190
1.141
0.045
0.038
0.178
0.008
0.189
1.136
NOTES:
Source: Table 6 of the Wyoming BART Air Modeling Protocol
4.5 Presentation of Modeling Results
This section presents the results of the CALPUFF visibility improvement modeling analysis
for Jim Bridger 3.
4.5.1 Visibility Changes for Baseline vs. Preferred Scenario
CH2M HILL modeled Jim Bridger 3 for the baseline conditions and post-control scenarios.
The post-control scenarios included emission rates for NO*, SOz, and PMro that would be
achieved if BART technology were installed on Jim Bridger 3.
Baseline (and post-control) 98ft percentile results were greater than 0.5 AdV for the Bridger
WA, Fitzpatrick WA, and Mt. Zirkel WA. The 98ft percentile results for each Class I area are
presented in Table 4-4.
Exhibit No. 1
^.,,Case No. IPC-E-13-16 '
T. Harvey, IPC
Page 46 of 97
JMS EY1 02OO7OO1 SLC\BART_JB3_OCT2OO7_FINAL.DOC
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Recommendations
As a result of the completed technical and economic evaluations, and consideration of the
modeling analysis for Jim Bridger 3, the preliminary recommended BART controls for NO*,
SOz, and PM are as follows:
. New LNBs and modifications to the OFA system for NO" control. Upgrade wet sodium FGD for SOz control. Add flue gas conditioning upstream of existing ESPs for PM control
The above recommendations were identified as Scenario I for the modeling analysis
described in Section 4. Visibility improvements for all emission control scenarios were
analyzed, and the results are compared below, utilizing a least-cost envelope, as outlined in
the New Source Review lY'orlcshop Manual (EPA, 1990).The purpose of this analysis is to use
an objective, EPA-approved methodology to evaluate and make the final recommendation of
BART control technology.
5.1 Least-cost Envelope Analysis
For the control scenarios modeled in Section 4, Tables 5-1 through 5-3 list the total
annualized cost, cost per dV reduction, and cost per reduction in number of days above
0.5 dV for each of the three Class I areas. A comparison of the incremental results between
selected scenarios is provided in Tables 5-4 through 5-6. Figures 5-l to 5-6 show the total
annualized cost versus number of days above 0.5 dV, and the total annualized cost versus
98th percentile AdV reduction, for the three Class I areas.
5.1.1 AnalysisMethodology
On page B-41 of the New Source Review Worlcshop Manual, the EPA states that:
"Incremental cost-effectiveness comparisons should focus on annualized cost and emission
reduction differences between dominant altematives. Dominant set of control alternatives are
determined by generating what is called the envelope of least-cost alternatives. This is a
graphical plot of total annualized costs for a total emissions reductions for all control
alternatives identified in the BACT analysis..."
An analysis of incremental cost effectiveness has been conducted. This analysis was
performed in the following way. First, the control option scenarios are ranked in ascending
order of annualized total costs, as shown in Tables 5-l through 5-3. The incremental cost
effectiveness data, expressed per day and per dV, represents a comparison of the different
scenarios, and is summarized in Tables 5-4 through 5-6 for each of the three wilderness
areas. Then the most reasonable smooth curve of least-cost control option scenarios is plotted
for each analysis. Figures 5-l through 5-6 present the two analyses (cost per dV reduction
and cost per reduction in number of days above 0.5 dV) for each of the three Class I areas
impacted by the operation of Jim Bridger 3.
Exhibit No. 1 ,,Case No. IPC-E-13-16 "-'
T. Harvey, IPC
Page 49 of 97
JMS EYlO2OOTOOlSLC\BART JB3,OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
In Figure 5-1, the four scenarios are compared as a graph of total annualized cost versus
number of days above 0.5 dV. EPA states that "in calculating incremental costs, the analysis
should only be conducted for control options that are dominant among all possible options."
In Figure 5-1, the dominant set of controloptions, Scenarios l, 3 and 4, represent the
least-cost envelope depicted by the curvilinear line connecting them. Scenario 2 is an inferior
option and should not be considered in the derivation of incremental cost effectiveness.
Scenario 2 represents inferior controls, because Scenario I provides approximately the same
amount of visibility impact reduction for less cost than Scenario 2.The incremental cost
effectiveness is determined by the difference in total annual costs between two contiguous
scenarios, divided by the difference in emissions reduction.
TABLE $1
Control Scenario Results for the Bridger Class I Wildemess Area
Jim Bridger 3
Scenario Controls
ggth
Percentile
Deciview
(dv)
Reduction
Average
Number ofDays Tota!Above Annualized
0.5 dV Cost(Days) (Million$)
Cost per
Reduction in
No. of Days
Above 0.5 dV
(Million$/Day
Reduced)
Cost per dV
Reduction
(Million$/dV
Reduced)
Base Current Operation with 0.00
Wet Flue Gas
Desulfurization (FGD),
Electrostatic
Precipitator (ESP)
0.00.00.00.0
0.37.93.410.70.43
0.99.7
1.318.1
1.60.64
Low-NO, Burners
(LNBs) with Over Fire
Air (OFA), upgraded
wet FGD system, flue
Gas Conditioning
(FGC) for enhanced
ESP performance
LNB with OFA,
upgraded wet FGD
system, and new
polishing fabric filter
LNB with OFA and
Selective Catalytic
Reduction (SCR),
upgraded wet FGD
system, FGC for
enhanced ESP
performance
LNB with OFA and
SCR, upgraded wet
FGD system, new
polishing fabric filter
0.46
0.63
11.3
14.3
15.0 24.4
21.2
28.5
37.9
Exhibit No. 'l
Case No. IPC-E-13-16
T. Harvey, IPC
Page 50 of 97
JMS EY1 O2OO7OO1 SLC\BART-JB3-OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
TABLE $2
Control Scenario Results for the Fitzpatrick Class I Wildemess Area
Jim Bridoer 3
Scenario Controls
ggth
Percentile
dV
Reduction
Average
Number ofDays TotalAbove Annualized
0.5 dV Cost(Days) lMillion$)
Cost per
Reduction in
No. of Days
Above 0.5 dV
(Million$/Day
Reduced)
Gost per dV
Reduction
(Million$/dV
Reduced)
0.00.00.00.00 0.0BaseCunent Operation with
Wet Flue Gas
Desulfurization (FGD),
Electrostatic
Precipitator (ESP)
Low-NO, Burners
(LNBs) with Over Fire
Air (OFA), upgraded
wet FGD system, flue
Gas Conditioning
(FGC) for enhanced
ESP performance
LNB with OFA,
upgraded wet FGD
system, and new
polishing fabric filter
LNB with OFA and
Selective Catalytic
Reduction (SCR),,
upgraded wet FGD
system, FGC for
enhanced ESP
performance
LNB with OFA and
SCR, upgraded wet
FGD system, new
polishing fabric filter
0.35
0.35 7.0 24.4
52.3
70.0
2.618.17.0
3.5
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 5'l of 97
JMS EY1 O2OO7OO1 SLC\BART_JB3_OCT2OO7-FINAL,DOC s3
BART ANALYSIS FOR JIM BRIDGER UNIT 3
TABLE $3
Control Scenario Results for the lvtt. Zirkel Class I Wildemess Area
Jim Bridoer 3
Scenario Gontrols
ggth
Percentile
dv
Reduction
Average
Number of
Days
Above
0.5 dv
(Days)
Cost perTota! dVAnnualized ReductionCost (Million$/dV(Million$) Reduced)
Gost per
Reduction in No.
of Days Above
0.5 dv
(Million$/Day
Reduced)
Current Operation with
Wet Flue Gas
Desulfurization (FGD),
Electrostatic
Precipitator (ESP)
Low-NO, Burners
(LNBs) with Over Fire
Air (OFA), upgraded
wet FGD system, flue
Gas Conditioning
(FGC) for enhanced
ESP performance
LNB with OFA,
upgraded wet FGD
system, and new
polishing fabric filter
LNB with OFA and
Selective Catalytic
Reduction (SCR),
upgraded wet FGD
system, FGC for
enhanced ESP
performance
LNB with OFA and
SCR, upgraded wet
FGD system, new
polishing fabric filter
0.0
$6.117.00.56
17.70.60
0.87
0.88
27.3
28.3
$0.0
s3.4
$9.7
$18.1
$24.4
$0.0
s16.1
$20.9
$27.8
$0.2
$0.6
$0.7
$0.9
TABLE S4
Bridger Class I Wildemess Area lncremental Analysis Data
Jim Bridoer 3
Options Compared
!ncremental
Reduction in
Days Above Incremental dV
0.5 Deciview Reductions
(dV) (Days) (dV)
lncrcmental
lncremental Cost Cost
Effectiveness Effectiveness(Million$/Days) (Million$/dV)
Baseline and Scenario 1
Scenario 1 and Scenario 2
Scenario 1 and Scenario 3
Scenario 1 and Scenario 4
10.7
0.7
3.7
4.3
0.43
0.03
0.20
0.21
$0.32
$e.5
$4.0
$4.9
$7.9
$221.1
$72.5
$98.6
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 52 of97
JMS EY1 O2OO70O1 SLC\BART-JB3-OCT2OO7-FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
TABLE $5
FiEpatrick Class I Wildemess Area lncremental Analysis Data
Jim Bridger 3
Options Compared
lncremental
Reduction in
Days Above Incrcmental dV
0.5 Deciview Reductions
(dv) (Days)) (dv)
lncremental
Incrementa! Cost CostEffectiveness Effectiveness(Million$/Days) (Million$/dV)
Baseline and Scenario 1
Scenario 1 and Scenario 2
Scenario 1 and Scenario 3
Scenario 1 and Scenario 4
5.3
NA
1.7
1.7
0.24
0.01
0.11
0.11
$0.64
NA
$8.8
$12.6
$14.2
$463.8
$137.7
$191.7
TABLE $6
Mt. Zirkel Class I Wildemess Area lncrementalAnalysis Data
Jim Bridger 3
Options Compared
!ncrcmental
Reduction in
Days Above
0.5 Deciview
(dV) (Days)
lncremental
lncrementa! dV lncremental Cost CostReductions Effectiveness Effectiveness(dV) (Million$/Days) (Million$/dV)
Baseline and Scenario 1
Scenario 1 and Scenario 2
Scenario 1 and Scenario 3
Scenario '1 and Scenario 4
17.0
0.7
10.3
11.3
0.56
0.0s
0.31
0.32
$0.20
$s.s
$1.4
$1.9
$6.09
$134.9
$47.6
$65.6
Exhibit No. 1
Case No. IPC-E-13-'16
T. Harvey, IPC
Page 53 of 97
JMS EY1O2OO7OO1 SLC\BART_JB3_OCT2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
FIGURE $I
Least-cost Envelope Bridger Class I WA Days Reduction
Jin ffier3
930.0
$0.0
t)
I s2o.o
aooE$ sts.o
asEE
E $10.0
o
4681012
Reduction in Days of Exceedlng 0.5 dV (days)
FIGURE 5.2
Least-cost Envelope Bridger Class I WA 98u' Percentile Reduction
Jin Bridger 3
$30.0
$15.0
s10.0
$20.0
C
.
to(,
Eox
6
tc
Eo
$0.0 (>
0.00 0.20 0.30 0.40 0.50
98th Percentilc Delta-Deciview Reductlon (dV)
Exhibit No. 1
Case No.|PC-E-13-16
T. Harvey,lPC
Page 54 of 97
(,
Scanario 4 ,II
Acenario g
I
tI
aI
{cenaao zr'
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-t
aBcenario
I
I
fscenario a,
,
ScefErio 2 aa
Baseline
ti."-*no,
JMS EY1 O2OO7OO1 SLC\BART-JB3-OCT2()O7-FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
FIGURE $3
Least+ost Envelope FiEpatrick Class I WA Days Reduction
Jim Bridger3
$30.0
$2s.0
0
- $20.0
aoo!$ sts.o
6eEE
E $10.0
o
$5.0
$0.0
F]GURE 5.{
Least-cost Envelope FiEpatrick Class I WA 98u' Percentile Reduction
Jin Bridger3
e
!! 0zo.o
aooEf; srs.o
o
Ec
E $10.0
o
$s.0
so.o(>
0.00
23456
Reduction ln Days of Exceedlng 0.5 dV (daye)
0.15 0.20 0.25
98th Porcentllc Delta.Declvlew Reductlon (dV)
930.0
$25.0
Exhibit No. I -Cr"" flo. iPC-E-13-16 s7
T. Harvey,IPC
Page 55 of 97
tScenario 4
?
,Scenario 3
I
I,I
Scenario 2
-a'--' ScenariolBaseline
<) Scenario 4
Oscenario 3I,
,
Scenario 2 ,a
Baserine -/ -Scenariol
JMS EYlO2OOTOO1SLC\BART-JB3-OCT2OO7-FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
FIGURE 5.5
Least-cost Envelope Mt. Zirkel Class IWA Days Reduction
Jim Eridger 3
$30.0
0
- $20.0
oooEI srs.og
E5tE
E $10.0
o
FIGURE 56
Least-cost Envelope Mt. Zirkel Class I WA 98tr Percentile Reduction
Jim BridgerS
$30.0
$0.0
0.00
10 15 20
Reductlon in Days of Exceedlng 0.5 dV (dap)
0.30 0.40 0.50 0.60 0.70
98th Percentile Delta-Deciview ReducUon (dV)
0
. $20.0
oooltft $ts.o
attE
; $10.0
o
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 56 of97
Scenario 4 OIII
aI, Scenario 3I
III
Scenario 2
Baseline
a Scenario 4
I
I
II Scenario s
/
Scenario2 /,/
Baseline
JMS EYl()2()OT()OlSLC\BART-JB3-OCI2OO7-FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
5.1.2 Analysis Results
Results of the least-cost Analysis, shown in Tables 5-l through 5-6 and Figures 5-l through
5-6 on the preceding pages, confirm the selection of Scenario l, based on incremental cost
and visibility improvements. Scenario 2 is eliminated because it is to the left of the curve
formed by the "dominant" control alternative scenarios, which indicates a scenario with
lower improvement and/or higher costs. Scenario 3 is not selected due to very high
incremental costs for both a cost per day of improvement and a cost per dV reduction. While
Scenario 4 provides some potential visibility advantage over Scenario l, the projected
improvement is less than half a dV, and the projected costs are excessive.
Analysis of the results for the Jim Bridger Class I WA in Tables 5-l and 5-4 and Figures 5-l
and 5-2 illustrates these conclusions. The greatest reduction in 98th percentile dV and number of
days above 0.5 dV is between the Baseline and Scenario l. The incremental cost-effbctiveness
for Scenario l----compared to the Baseline for the Bridger WA, for example-is reasonable at
$320,000 per day and $7.9 million/dV. However, the incremental cost effectiveness for
Scenario 3 compared to Scenario l, again for the Bridger WA, is excessive at $4.0 million per
day and $72.5 million per dV. The same conclusions are reached for each of the three
wilderness areas studied. Therefore, Scenario I represents BART for Jim Bridger 3.
5.2 Recommendations
5.2.1 NO, Emission Control
The BART presumptive NO* limit assigned by EPA for tangentially-fired boilers burning
sub-bituminous coal is 0.15 lb per MMBtu. However, as documented in Section 3.2.1, the
characteristics of the Jim Bridger coals are more closely aligned with bituminous coals, and
have been assigned a presumptive BART NO* limit of 0.28 lb per MMBtu.
CH2M HILL recommends LNB with OFA as BART for Jim Bridger 3, based on the
projected significant reduction in NO* emissions, reasonable control costs, and the
advantages of no additional power requirements or non-air quality environmental impacts.
NO* reductions are expected to be similar to those realized at Jim Bridger 2. CH2M HILL
recommends that the unit be permitted at a rate of 0.26Ib per MMBtu.
5.2.2 SOz Emission Control
CH2M HILL recommends upgrading the existing wet sodium FGD system as BART for
Jim Bridger 3, based on the significant reduction in SOz emissions, reasonable control costs,
and the advantages of both minimal additional power requirements and non-air quality
environmental impacts. This upgrade approach will meet the BART presumptive SOz limit of
0.15 lb per MMBtu.
5.2.3 PMro Emission Control
CH2M HILL recommends finalizing the permitting of the FGC system to enhance the
performance of the existing ESP as BART for Jim Bridger 3, based on the significant
reduction in PMro emissions, reasonable control costs, and the advantages of minimal
additional power requirements and no non-air quality environmental impacts.
Exhibit.No..l _ _^ _^ ,eCase No. IPC-E-13-'16 -
T. Harvey, IPC
Page 57 of 97
JMS EY1 OMOTOOl SLC\BARI_JB3_OCI2OO7-FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 3
5.3 Just-Noticeable Differences in Atmospheric Haze
Conclusions reached in the reference document "Just-Noticeable Differences in Atmospheric
Haze" by Dr. Ronald Henry (2002), state that only dV differences of approximately 1.5 to
2.0 dV, or more are perceptible by the human eye. Deciview changes of less than 1.5 cannot
be distinguished by the average person. Therefore, the modeling analysis results indicate that
only minimal, if any, observable visibility improvements at the Class I areas studied would
be expected under any of the scenarios. Thus the results indicate that even though many
millions of dollars will be spent, only minimal if any visibility improvements may result.
Finally, it should be noted that none of the data were corrected for natural obscuration. Water
in various forms (fog, clouds, snow, or rain) or other naturally caused aerosols may obscure
the atmosphere and reduce visibility. During the period of 2001 through 2003, there were
severalmega-wildfires that lasted for many days, with a significant impact on background
visibility in these Class I areas. If natural obscuration lessens the achievable reduction on
visibility impacts modeled for BART controls at the Jim Bridger 3 facility, the overall effect
would be to increase the costs per dV reduction that are presented in this report.
Exhibit.No-l _ .^ .^ $toCase No. IPC-E-13-16 -'
T. Harvey, IPC
Page 58 of97
JMS EY1 O2OO7OO.I SLC\BART-JB3-OCT2OO7_FINAL.DOC
6.0 References
40 CFR Part 51. Regional Haze Regulations and Guidelines for Best Available Retrofit
Technology Determinations; Final Rule. July 6,2005.
Energy Information Administration, 2006. Official Energlt Statistics from the U.S.
Government: Coal. http://www.eia.doe.sov/fuelcoal.html. Accessed October 2006.
EPA, 2003. Guidancefor Estimating Natural Visibility Conditions Under the Regional Haze
Rul e. Environmental Protection Agency. EP A-45 4 I 8-03 -005. September 2003.
EPA, 1990. New Source Review Workshop Manual-Prevention of Significant Deterioration
and Nonattainment Area Permitting. Draft. October 1990.
Henry, Ronald, 2002. "Just-Noticeable Differences in AtmosphericHaze," Journal of the Air
& Waste Management Association. Volume 52, p. 1238.
National Oceanic and Atmospheric Administration, 2006. U.S. Daily Weather Maps Project.
http://docs.lib.noaa.sov/rescue/dwm/data rescue daily weather maps.html.
Accessed October 2006.
North Dakota Department of Health, 2005. Protocolfor BART-Related Visibility
Improvement Modeling Analysis in North Dakota. North Dakota Department of
Health. October 26, 2005.
Sargent & Lundy, 2002. Multi-Pollutant Control Report. October 2002.
Sargent & Lundy, 2006. Multi-Pollutant Control Report. Revised. October 2006.
WDEQ-AQD,2006. BART Air Modeling Protocol-Individual Source Visibility Assessments
for BART Control Analpes. Wyoming Department of Environmental Quality - Air
Quality Division. September 2006.
Exhibit No- 1 _ .^ .^ 6-jCase No. IPC-E-13-'16 -
T. Harvey, IPC
Page 59 of 97
JMS EY1O2OO7OO1 SLC\BART_JB3_OCT2OO7-FINAL,DOC
APPENDIXA
Economic Ana
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 60 of 97
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Case No. IPC-E-13-16
T. Harey, IPC
Page 62 of 97
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T. Harvey, IPC
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Case No. IPC-E-13-16
T Harvey, IPC
Page 76 of 97
($) af!-'l tuEld rEaA ra^O lso3 r.luo^ luasard
APPENDIX B
BART Protocol
Exhibit No. 'l
Case No. IPC-E-13-16
T. Harvey, IPC
Page77 ot97
BART Air Modeling Protocol
Individual Source Visibility Assessments
for BART Control Analyses
September,2006
State of Wyoming
Department of Environmental Qualify
Air Quality Division
Cheyenne, WY 82002
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 78 of 97
Exhibit No. 1
Case No.|PC-E-1$16
T. Harvey,lPC 2
Page 79 of 97
1.0 INTRODUCTION
The U.S. EPA has issued final amendments to the RegionalHaze Regulations,
atong with Guidelines forBest Available Retrofit Technology (BART) Determinations.(')
The guidelines address the methodology for detennining which facilities must apply
BART (sources subject-to-BART) and the evaluation of control options.
The State of Wyoming used air quality modeling in accordance with the EPA
Guidelines to determine the Wyoming sources which are subject-to-BART. This
Protocol defines the specific methodology to be used by those sources for determining
the improvement in visibilityto be achieved by BART controls.
The methodology presented in this Protocol is consiste,nt with EPA guidance and
the Air Quality Division (AQD) detemrinatioq of subject-to-BART sources. It is
intended that all Wyoming sources that must conduct BART analyses will use this
Protocol for their evaluation of conhol technology visibility improvenrent. Any
deviations from the procedures described herein must be approved by the Division prior
to implementation.
(r) 40 CFR Part 51 : Regional Haze Regulations and Guidelines for Best Available Retrofit Tecbnology
(BART) Determinations; Final Rule. 70 Federal Register, 39103-39172, July 6, 2005.
Exhibit No. 1
Case No. IPC-E-13-16 ^T. Harvey, IPC J
Page 80 of 97
2.0 OVERVIEW
Wyoming AQD detennined that eight facilities (sources) in the state are subject-
to-BART. The sources are listed in Table 1. Division modeling indicated that each of
these sources causes or conhibutes to visibility impairment in one or more Class I areas.
Each source must conduct a BART analysis to define Best Available Retrofit Technology
(BART) applicable to that source, and quantify the improvement in Class I visibility
associated with BART controls. This Protocol sets out the procedures for quantifying
visibilityimprovement. Other aspects of the full BART analysis are not addressed here.
There are many Class I areas within and surrounding Wyomiug (See Figure 1).
On the basis of distance from subject-to-BART sources, topography, meteorology, and
prior modeling, the AQD has determined that only five Class I areas need be addressed in
BART individual source analyses. These are Badlands and Wind Cave National Parks in
South Dakota Mt. Zirkel Wilderness Area in Colorado, and Bridger and Fitzpatrick
Wildemess Areas in Wyoming. Souces in eastem Wyoming have been shown to have
greatest visibility impacts at the two South Dakota Class I areas, and western Wyoming
sources have maximum impacts at Bridger and Fitzpatrick Wildemess Areas, and Mt.
Zirkel. Visibility improveme,nt at these highest impact areas will provide the best
measure of the effectiveness of BART conhols.
Each facility slrould ca.ry out modeling with the CALPUFF modeling system for
the Class I areas specified in Table 2. The AQD will provide meteorological input for
CALMET for the years 2001, 2A02, and 2003. The model domain covered by the AQD
meteorological data is centered in southwest Wyoming, and extends roughly from Twin
Falls, ID in the west to the Missouri River in the east, and from Denver in the south to
Helena, MT in the north. The domain is shown, along with Class I areas, in Figure 1.
Sources may wish to utilize a smaller domain for CALPUFF modeling. Smaller
domains are acceptable if they provide adequate additional area beyond the specific
source and Class I areas being addressed. Figure 1 includes a "southwest Wyoming"
domain which represents the minimum acceptable area for sources impacting the Bridger
and Fitzpatrick Wildemess Areas, and the Mt. Zirkel Wildemess Area, and a "northeast
Wyoming" domain as a minimum area for Badlands and Wind Cave National Palks
modeling.
The CALPUFF model should be used with each of the three years of
meteorological data to calculate visibility impacts for a baseline (existing ernissions)
case, and for cases reflecting BART controls. The control scenarios are to include
individual scenarios for proposed BART controls for each pollutant (SOz, NO*, and
particulate matter), and a combined scenario representing application of all pmposed
BART controls. If desired, additional modeling may be performed for controls that are
not selected as BART. This might be done, for example, to provide data useful in
identifying the control technologies that represent BART. However, visibility modeling
is required only for the proposed BART controls.
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey,lPC 4
Page 81 of97
Basin Electric Laramie River Power Plant Boilers #1.2-3
FMC Comoration Granser Soda Ash Plant Boilers #1.2
FMC Comoratiou Green River Sodium Plant Three boilers
General Chemical Co.Green River Soda Ash Two boilers
PacifiCom Dave Johnson Power Plant Boilers #3,4
PacifiCorp Jim Brideer Power Plant Boilers #1-4
PacifiCom Nauehton PowerPlant Boilers #1.2-3
PacifiCom Wvodak Power Plant Boiler
Table 1. Wyoming Sources Subjectto-BART
Results of visibility modeling will be presented as a comparison between baseline
impacts and those calculated for the BART contol sce,lrarios. Quantitative measures of
impact will be the 98th percentile deciview change (Adv) relative to the 20% best days
natural background, and the number of days with deciview change exceeding 0.5 (EPA
Regional Haze Regulations and Guidelines for Best Available Retofit Technology
(BART) Determinations, 70 FR 39103). Results should be presented for each year.
Exhibit No. 1
Case No. IPC-E-13-16 5T. Harvey, IPC
Page 82 ot 97
able 2 Class I Areas to be Addressed
Source Class I Areas to be Evaluated
Basin Electric
Lararnie River
'S/ind CaveNP, Badlands NP
FMC Corporation
Granser Soda Ash
Bridger WA, Fitzpatrick WA
FMC Corporation
Sodium Products
Bridger WA, Fitzpatrick WA
Ge,neral Chemical
Green River SodaAsh
Bridger WA, Fitzpatrick WA
Pacificorp
Dave Johnston
Wiud CaveNP, Badlands NP
Pacificorp
Jim Brideer
Bridger Wd Fitzpatick WA,
Mt. Zirkel WA
Pacificorp
Nauehton Plaut
Bridger WA, Fitzpatrick WA
Pacificorp
Wvodak
Wind CaveNP, BadlandsNP
Exhibit No. 1
Case No. IPC-E-13-16,
T. Harvey,lPC 6
Page 83 of 97
3.0 EMISSIONS DATA FOR MODELING
CALPUFF model input requires source (stack) - specific eurission rates for each
pollutant, and stack pararneters (height, diameter, exit gas temperature, and exit gas
velocity), Per EPA BART guidance, these parameters must be representative of
maximum actual 24-hour average emitting conditions for baseline (existing) operation,
and mo<imum proposed 24-hour average emissions for futrue (BART) operations.
3.1 Baseline Modeling
Sources are required to utilize representative baseline emission conditions if data
are available; baseline emissions n:ust be documented. Possible sources of emission data
are stack tests, CEM datq fuel consumption dat4 etc. Remember that emissions should
represent maximum 24-hour rates. EPA BART guidance states that you should "Use the
24-hour average actual emission rate from the highest emitting day of the meteorological
period modeled (for the pre-conkol scenario)." Thus, baseline conditions should
reference datafiom2001 througb2003 (or 2004).
As a minimum, modeled emissions must include:
SOz sulfur dioxideNO* oxides of nitrogenPMz.s particles with diameter less than 2.5pm
PMro-z.s particles with diarneters greater than 2.5prn but less
than or equal to 10 pm
If the fraction of PMro in the PMz.s (fine) and PMro-z.s (coarse) categories cannot
be determined all particulate matter should be assumed to be PMz.s.
In addition, direct emissions of suHate (SOa) should be included where possible.
Sulfate can be emitted as sulfuric acid (HzSO+), sulfur trioxide (SOl), or as suifate
compounds; emissions should be quantified as the equivalent mass of SO+.
lVhen test or engineering data are not available to speciff SO+ emissions or the
relative fractions of fine and coarse particles, use can be made of speciation profiles
available from Federal Land Managers at the website
htlpllww2.nature.nps.gov/airlpermits/ect/index.cfrn. Profiles are available for a number
of source type and control technology combinations. The FLM speciation factors are
acceptabie ifdata are available for the appropriate source type.
Emissions of VOC (volatile organic compounds), condensable organics measured
in stack tests, and elemental carbon components of PMro do not need to be included for
BART modeling. The only other pollutant noted ir EPA BART guidance is ammonia
ffir). Though ammonia is not believed to be a significant contributor to visibility
Exhibit No. 1
Case No. IPC-E-13-'16 'T. Harvey, IPC t
Page 84 of 97
impairment in most cases in Wyoming, it could be important for sources with significant
ammonia emissions - for example from some NO* control systems. Sor:rces that are
expected to emit ammonia (in pr+or post-control configurations) should include
ammonia emissions in theirmodel input.
If quantitative baseline emissions data are unavailable and sources believe that the
maximum 24-hour emission rates estimated by the Division (presented in the Subject-to-
BART final report) are representative of baseline conditions for their facility, they may
be used for baseline modeling. However, emissions of sulfate and ammonia (if
applicable) should be included based on the best available test information or speciation
factors from current literature.
3.2 Post-Control Modeling
A1l pollutants described above should be included for each post-control scenario.
Post-conhol emissions (ma:<imum Z4-hour average) will generally be the baseline
emissions multiplied by a control factor appropriate to the BART control. However,
some proposed controls may simply increabe the efhciency of existing controls; others
may result in an increase in emissions of one pollutant while controlling another. These
factors must all be considered in defining emission rates for post-control modeling. Any
changes in stack parameters resulting from conhol application must also be included.
The required visibility assessment will include the effect of each proposed BART
control. For example, if a source proposes to add a scrubber for SOz control, low NO,
bumers for NO* control, and a baghouse for particulate control, four sets of visibility
results should be developed:
o Use of SOz control aloneo Use ofNO* control aloneo Use ofparticulate control aloneo Use of proposed combination of all three controls
All pollutants should be modeled in each CALPUFF model run, but the modeled
emissions should reflect only the specifrc controls or combination of controls addressed
in that run.
Additional modeling could be necessary in situations where a facility is
comprised of more than one subject-to-BART source, and different BART controls are
applicable to different sources. Excessive modeling to address multiple control
combinations is not necessary; however, visibility modeling should quantify the effect of
BART controls on all affected sourcas for each pollutant, and of all facility BART
controls combined.
Exhibit No. 1
Case No. IPC-E-l3-'16^
T. Harvey, IPC U
Page 85 of 97
4.0 METEOROLOGICAL DATA
'Wyoming AQD will provide MM5 meteorological data fields for years 2001,
2002, and 2003 that can be utilized as input to CALMET. The MM5 output will have 12
kilometer resolution and cover the full domain shown in Figure 1.
Mesoscale meteorological data (MM5) were developed and evaluated as part of
the AQD's southwest Wyoming NO2 increment analysis. Three years of MM5 data at 36
km resolution were used to initialize t2 km MM5 simulations. The 12km MM5
modeling used identical physics options to the original 36 km runs. CALMM5 was then
used as a preprocessor to produce CALMET - ready MM5 data input fiIes, Quality
assurance was performed by comparing the original MM5 output on the 36lsn national
RPO gdd to the 12 km MM5 output and observations.
The CALMET model (version 5.53a, level 040716) should be used to prepare
meteorological input for CALPUFF. The user may select a domain smaller than the
MM5 domain for CALMET and CALPUEF modeling if desired. Figure 1 shows
minimum domain areas for modeling of westem and eastem Wyoming BART sources.
Fourkilometer resolution should be specified for CALMET output.
CALMET processing should use the AQD MM5 dat4 and appropriate sruface,
upper ar, and precipitation data. Figure 2 shows the iocations of surface and upper air
stations within the MM5 model domain. The MM5 data are used as the initial guess
wind field; this wind field is then adjusted by CALMET for tenain and land use to
geuerate a step I wind fie14 and refined using surface and upper air data to create the
final step 2 wind field.
Surface, upper air, and precipitation data can be obtained from the National
Climatic Data Center. Land use and terrain data are available from the U.S. Geological
Survey. Data can be formatted for use in CALMET with standard conversion and
processing program s available with the CALMEUCALPUFF software.
Table 3 provides a listing of appiicable CALMET input variables for BART
meteorological processing. The table includes inputs that are specific to Wyoming
BART modeling. Inputs not shown in Table 3 are not relevant to the present application,
are dependent on the specific model domain of the user, use model default values, or are
obvious from the context.
Exhibit No. 1
Case No. IPC-E-13-16 -
T. Harvey, IPC 9
Page 86 of 97
Table 3. CALMET Control File krputs
Variable Descriotion Value
Inout Grouo I
IBYR Year 2001
2002
2003
BTZ Base time zone 7
IRTYPE Run twe 1
LCALGRD Compute data fields for CALGRID T
Input Group 2
PMAP Map proiection LCC
DGRIDK]\,I Grid spacine fl<rn)4
NZ Number of lavers 10
ZFACE Cell face heishts (m)0
20
40
100
140
320
580
1020
1480
2220
3500
lnout Grouo 4
NOOBS No observation Mode 0
Inout Grouo 5
IWFCOD Model selection variable 1
IFRADJ Froude number adiustment 1
IKINE Kinematic effects 0
IOBR Use O'Brien procedure 0
ISLOPE Slooe flow effects 1
IEXTRP Extraoolate surface wind observations -4
ICALM Exhaoolate calm surface winds 0
BIAS Biases for weights of surface and upper
air stations
All0
RMIN2 Minimum distance for extrapolation -1
IPROG Use eridded pnc.qnostic model output t4
ISTEPPG Time Step (hours)I
LVARY Use varvins radius of influence F
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC l0
Page 87 of 97
Table 3. CALMET Control File Inputs (continued)
Variable Description Value
RMAX I Maximr:mradius of inJluence ftm)30
RMAX2 Maximumradius of influence fl<rn)s0
RMIN Minimum radius of influence 0sr)0.1
TERRAD Radius of influence for tenain 0cr)15
R1 Relative weighting of first guess wind field and
observations ftm)
5
R2 Relative weiehtine aloft ftm)25
IDIOPT 1 Surface temoerature 0
IDIOPT 2 Uooer air laose rate 0
ZrJPT Lanse rate deoth (m)200
IDIOPT 3 Average wind comoonents 0
IUPWND Uoper air station -l
zrJPwND (1)
AJPWND (2)
Bottom and top of layer for domain
seale winds (m)
1,1000
1,1000
IDIOPT4 Surface wiud cornponents 0
IDIOPT5 Uooer air wind comoonents 0
Inout Grouo 6
IAVEZI Soatial averasins 1
MNMDAV Max search radius I
HTqFANIG Half anele for averaeins (dee)30
ILE'VZT Laver of winds in averaEins I
ZfrvTAX Macimum overland mixine heisht (m)3500
ITPROG 3D temoerature source I
IRAD Intemolation ture I
TRADKM Radius of influence *temoerature flon)s00
NI.JMTS Ma,ximum number of Stations 5
IAVET Spatiai averaging of temperatrues I
NFLAGP Precipitation interpolation 2
Exhibit No. 1
Case No. IPC-E-13-16.,
T. Harvey, IPC I I
Page 88 of 97
5.0 CALPUFF MODEL APPLICATION
The CALPUFF model (version 5.7l1a,level 040716) will be used to calculate
pollutant concenhations at receptors in each Class I area. Application of CALPUFF
should, in general, follow the guidance presented in the Interagency Workgroup on Air
Quality Modeling (IWAQM) Phase 2 report (EPA - 454lR98-019) and the EPA Regional
Haze Regulations and Guidelines for BART Determinations (70 FR 39103).
Appropriate CALPUFF control lile inputs are in Table 4. Note should be taken of
the basis for several of the recommended CALPUFF inputs.
. Building downwash effects need not
distances involved and the fact that
downwash is unlikely to have a
concentrations
be included. Because of the transport
most sources have tall stacks, building
significant effect on model-predicted
Puff splitting is not required. The additional computation time necessary for puff
splitting is not justified for purposes of BART analyses.
Hourly ozone files should be used to define background ozone concenEation.
Data are available from the following sites within the model domain.
RockyMountainNP, CO
Craters of the Moon NP, ID
AIRS -Highland UT
Mountain Thunder, WY
YellowstoneNP, WY
Centennial, WY
Pinedale, WY
The background ozone concentration shown in Table 4 is used only when hourly
data are missing.
A constant background ammouia concentration of 2.0 ppb is specified. This value
is based upon monitoring data from nearby states and IWAQM guidance.
Experience suggests that 2.0 ppb is conservative in that it is unlikely to
significantly limit nitrate formation in the model computations.
MESOPUFF II chemical transformation rates should be used.
The species to be modeled should be the seven identified in CALPUFF: SOz,
SOl, NO*, HNOr, NO3, PM2.5, and PMto-2.s. If ammonia (I.IH, is emitted it
should be added to the species list. In most cases, all pollutants modeled will also
be emitted, except for HNO: and NOr.
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey,lPC 12
Page 89 of 97
Concentration calculations should be made for receptors covering the areas of the
Class I areas being addressed. Receptors in each Class I area will be fhose designated by
the Federal Land Managers and available from the National Park Service website.
Table 4. CALPUFF Contol File Iaputs
Exhibit No. 1
Case No. IPC-E-13-16..
T. Harvey, IPC LJ
Page 90 of 97
Variable Description Value
Inout Group I
METRTIN Control oarameter for runnins all neriods in met file 1
IBYR Starting year 2001
2002
2003
reTZ Base time zone 7
NSPEC Number of chemical species modeled 7 (or 8)
NSE Number of species ernitted 5 (or 6)
METFM Meteoroloeicai data format I
Inout Grouo 2
MGAUSS Vertical distribution in near field t
MCTADJ Terrain adiustment method 3
MCTSG Submid scale comolex terrain 0
MSLUG ElonEated puffs 0
MTRANS Transitional plume rise I
MTIP Stack tio downwash 1
MSHEAR Vertical wind shear 0
MSPLIT Puff splittine allowed?0
MCHEM Chemical mechanism I
MAOCHEM Aqueous phase transformation 0
MWET Wet removal I
MDRY Drv deposition 1
MDISP Disoersion Coefficients 3
MROUGH Adiust sisma for roushness 0
MPARTL Partial plume penehation of inversions I
MPDF PDF for convective conditions 0
lnput Group 4
PMAP Mao oroiection LCC
DGRIDKM Grid soacins 4
Table 4. CALPUTF Control File Inputs (continued)
ZFACE Cell face heiehts (m)0
20
40
100
t40
320
580
t0z0
1480
2220
3500
Lrout Grouo 6
NHILL Number of terrain features
Inout Group 7
0
Dry Gas Depo Chemical parameters for
dry eas deposition
Defaults
Input Groun 8
Dry Part. Depo Size parameters for dry
particle deposition
SO+, NOr, PM25
PMlO
Defaults
6.5" 1.0
Input Group 11
MOZ Qzone Input option I
BCKO3 Background ozone all
months (ppb)
44.0
BCKNH3 Background ammonia - all
months (oob)
2.0
Erout Grouo 12
)0\4AXZI Maximum mixing height
(m)
3500
)O\4INZ Minimum mixing height
(m)
50
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey,lPC 14
Page 91 of97
6.0 POST PROCESSING
Visibility impacts are calculated from the CALPUFF concentration results using
CALPOST. CALPOST version 5.51, level 030709 should be used; the output from
CALPOST will provide the highest deciview impact on each day from all receptors
within each C1ass I area modeled.
For some CAIPUFF applications such as deposition calculations, the POSTUTIL
prograrn is used prior to CALPOST. POSTUTIL is also used to repartition total nitate
by accounting for ammonia limiting. The ammonia limiting calculation in POSTUTIL
should not be applied for Wyoming BART modeling. U you believe that ammonia
limiting is appropriate for a specific BART analysis, justification should be discussed
with the Divisionprior to its used.
Visibility calculations by CALPOST for BART pryposes use Method 6. This
method requires input of monthly relative humidity factors, f(RII), for each Class I area.
The EPA guidance document provides appropriate data for each area. Table 5 lists
monthly f(REI) factors to use for the Wyoming, Colorado, and South Dakota areas to be
addressed in BART modeling. The factors shown in Table 5 include averages for the
adjacent Class I areas, and are within 0.2 units of the Guideline table values for the
individual Class I areas.
Natural background conditions as a reference for determination of the delta-dv
change due to a source should be represeuiative of the Z}Yobest natural visibility days.
EPA BART guidance provides the 20oh best days deciview values for each Class I area
on arr annual basis, but does not provide species concentration data for the 20% best
background conditions. These concentrations are needed for input to CALPOST.
Annual species concentations coresponding to the 20Yo best days were
caiculated for each Class I area to be addressed by scaling back the annual average
concentrations given in Guidance for Estimating Natural Visibility Conditions Under the
Regionai Haze Rule (Table 2-1). A separate scaling factor was derived for each Class I
area such that, when multiplied by the Guidance table annual concemtrations, the 20%
best days deciview value for that area would be calculated. The scaled aerosol
concentrations were averaged for the Bridger and Fitzpatrick WAs, and for Wind Cave
and Badlands NPs, because of their geographical proximity and similar annual
background visibility. T\e 20o/o best days aerosol concentrations to be used for each
month for Wyoming BART evaluatious are listed in Table 6.
Table 7 is a list of inputs for CALPOST. These inputs should be used for all
BART visibility calculations. Output from CALPOST should be configured to provide a
ranked list of the highest delta-decivisw values in each Class I area. The 98th percentile
delta-deciview value and the number of values exceeding 0.5 can then be deterrnined
directly from the CALPOST output.
Exhibit No. 1
Case No. IPC-E-13-16- -
T. Harvey, IPC l)
Page 92 of 97
Table 5.Factors for Class I AreasT(H
Month Ifind CaveNP
Badlands NP
Bddger WA
Fitzpatrick WA
Mt. Zirkel WA
January 2.65 2.50 2.20
February 2.65 2.30 2.20
March 2.65 2.30 2.00
Aoril 2.55 2.10 2.t0
May 2.70 2.to 2.20
June 2.60 1,80 1.80
July 2.30 1.50 1.70
Auzust 2.30 1.50 1.80
Septernber 2.20 1.80 2.00
October 2.25 2.00 1.90
November 2.75 2.50 2.10
December 2.65 2.40 2.ta
Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC 16
Page 93 of 97
forBARTAnal
Aerosol
Comoonent
Wind Cave NP
Badlands NP
Fitzpatrick WA
BridserWA
Mt. Zirkel WA
Ammonium Sulfate .047 .045 .046
Ammonium Nitate .040 .038 .038
Oreanic Carbon .186 .178 .179
Elemental Carbon .008 .008 .008
Soil .198 .189 .190
Coarse Mass 1.191 1.136 t.t41
Table 6. Natural Background Concentrations of Aerosol Components for 20Yo Best Days
Exhibit No. 1
Case No. IPC-E-I3-16 -T. Harvey, IPC L t
Page 94 of 97
LPOST Control Fileable 7. CA
Variable Descriotion Value
Input Group 1
ASPEC Species to Process VISIB
ILAYER Laver/deposition code I
A,B ScalinE factors 0.0
LBACK Add b acksround concentrations?F
BTZONE Base time zone 7
LVS04 Species to be included in extinction T
LVNO3 T
LVOC F
LVPMC T
LVPMF T
LVEC F
LVBK Include backsround?T
SPECPMC Species name for particulates PMlO
SPECPMF PM25
EEPMC Extinction efficiencies 0.6
EEPMF 1.0
EEPMCBK 0.6
EES04 3.0
EENO3 3.0
EEOC 4.0
EESOIL 1.0
EEEC 10.0
MVISBK Visibility calculation method 6
RTMAC Monthly RH adiustment factors Table 5
BKS04 Backsround concentrations Table 6
BKNO3 Table 6
BKPMC Table 6
BK OC Table 6
BKSOIL Table 6
BKEC Table 6
BEXTRAY Extinction due to Ravleieh scatterine 10.0
Exhibit No. 1
Case No. IPC-E-13-'16
T. Harvey, IPC 18
Page 95 of 97
7.0 REPORTING
A report on the BART visibility analysis should be submitted that clearly
compares impacts for post-control emissions to those for baseline emissions. Data for
baseline and BART sienarios should include both the 98ft percentile values and the
number of days with delta-deciview values exceeding 0.5. Results should be given for
each model year.
Table 8 is an exarnple of a recommended format for presentation of model input
and model results. The example is for baseline conditions; sirnilar tables should be
provided for each confrol scenario (SOz, NOx, and PM10) and for the combination of all
BART controls. Your report tables need not follow the exact format shown in Table 8;
but the same information should be provided in a concise and clear form. If additional
scenarios were modeled or you wish to present supplemental infomration, they should be
provided in an appendix or separate from the specified final results.
Exhibit No. 'l
Case No. IPC-E-13-1q o
T. Harvey, IPC Ll
Page 96 of 97
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Exhibit No. 1
Case No. IPC-E-13-16
T. Harvey, IPC
Page 97 of 97
Final Report
BART Analysis for
Jim Bridger Unit 4
Prepared For:
PacifiCorp
1407 West North Temple
Salt Lake City, Utah 84116
December 2007
Prepared By:
GH2]UlHILL
215 South State Street, Suite 1000
Salt Lake City, Utah 84111
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPG
Page 1 of96
o
F inal Rrport
BART Analysis for
Jim Bridger Unit 4
Submitted to
PacifiCorp
December 2007
GH2N'IHILL
Exhibit No. 2
Case No. IPC-E-13-'16
T. Harvey, IPC
Page 2 of 96
Executive Summary
Background
In response to the Regional Haze Rule and Best Available Retrofit Technology (BART)
regulations and guidelines, CH2M HILL was requested to perform a BART analysis for
PacifiCorp's Jim Bridger Unit 4 (hereafter referred to as Jim Bridger 4). A BART analysis has
been conducted for the following criteria pollutants: nitrogen oxides (NO*), sulfur dioxide
(SOz), and particulate matter less than l0 micrometers in aerodynamic diameter (PMro). The
Jim Bridger Station consists of four 530-megawatt (MW) units with a total generating
capacity of 2,120 MW. Because the total generating capacity of the Jim Bridger Station
exceeds 750 MW, presumptive BART emission limits apply to Jim Bridger 4, based on the
United States Environmental Protection Agency's (EPA) guidelines. BART emissions limits
must be achieved within 5 years after the State Implementation Plan (SIP) is approved by the
EPA. A compliance date of 2014 was assumed for this analysis.
In completing the BART analysis, technology altematives were investigated and potential
reductions in NO*, SOz, and PMro emissions rates were identified. The following technology
alternatives were investigated, listed below by pollutant:
r NO* emission controls:
Low-NO* burners (LNBs) with over-fire air (OFA)
LNBs with rotating opposed fire air (ROFA)
LNBs with selective non-catalytic reduction (SNCR) system
LNBs with selective catalytic reduction (SCR) system
SOz emission controls:
Dry flue gas desulfurization (FGD) system with existing electrostatic precipitator
(ESP)
Dry FGD system with new polishing fabric filter
Wet FGD system and new stack with existing ESP
PM ro emission controls:
Sulfur trioxide (SO3) injection flue gas conditioning system on existing ESP
Polishing fabric filter
Exhibit No. 2 ."-nCase No. IPC-E-13-16 -" '
T. Harvey, IPC
Page 3 of 96
JMS EY1 O2OO7OO1 SLC\BART-JB4-OCT2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
BART Engineering Analysis
The specific steps in a BART engineering analysis are identified in the Code of Federal
Regulations (CFR) at 40 CFR 51, Appendix Y, Section IV. The evaluation must include:
o The identification of available, technically feasible, retrofit control options
o Consideration of any pollution control equipment in use at the source (which affects the
availability of options and their impacts)
. The costs of compliance with the control options
. The remaining useful life of the facility
. The energy and non-air quality environmental impacts of compliance
. The degree of visibility improvement that may reasonably be anticipated from the use of
BART
The following steps are incorporated into the BART analysis:
o Step 1 - Identify All Available Retrofit Control Technologies
. Step 2 - Eliminate Technically Infeasible Options
The identification of available, technically feasible, retrofit control options
Consideration of any pollution control equipment in use at the source (which affects
the applicability of options and their impacts)
. Step 3 - Evaluate Control Effectiveness of Remaining Control Technologies
. Step 4 - Evaluate Impacts and Document the Results
The costs of compliance with the control options
The remaining useful life of the facility
The energy and non-air quality environmental impacts of compliance
. Step 5 - Evaluate Visibility Impacts
The degree of visibility improvement that may reasonably be anticipated from the use
ofBART
Separate analyses have been conducted for NO*, SOz, and PMro emissions. All costs included
in the BART analyses are in 2006 dollars, and costs have not been escalated to the assumed
2014 BART implementation date.
Coal Characteristics
The main source of coal burned at Jim Bridger 4 will be the Bridger Underground Mine.
Secondary sources are the Bridger Surface Mine, the Bridger Highwall Mine, the Black Butte
Mine, and the Leucite Hills Mine. These coals are ranked as sub-bituminous, but are closer in
Exhibit No. 2 -^.c""" No. rpt-E-1 3-1o ES-2
T. Harvey, IPC
Page 4 of 96
JMS EY1 O2OO7OO1 SLC\BART_JB4_OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
characteristics to bituminous coal in many of the parameters influencing NO* formation.
These coals have higher nitrogen content than coals from the Powder River Basin (PRB),
which represent the bulk of sub-bituminous coal use in the U.S. This BART analysis has
considered the higher nitrogen content and different combustion characteristics of PRB coals
as compared to those coals used at Jim Bridger 4, and has evaluated the effect of these
qualities on NO* formation and achievable emission rates.
Recommendations
CH2M HILL recommends installing the following control devices, which include LNBs with
OFA, upgrading the existing FGD system, and operating the existing electrostatic
precipitator with an SOI flue gas conditioning system. This combination of control devices is
identified as Scenario I throughout this report.
NO' Emission Control
The BART presumptive NO* limit assigned by the EPA for tangentially fired boilers burning
sub-bituminous coal is 0.15 pound (lb) per million British thermal units (MMBtu). However,
as documented in this analysis, the characteristics of the Jim Bridger coals are more closely
aligned with bituminous coals, and have been assigned a presumptive BART NO* limit of
0.28 lb per MMBtu.
CH2M HILL recommends LNBs with OFA as BART for Jim Bridger 4, based on the
projected significant reduction in NO* emissions, reasonable control costs, and the
advantages of no additional power requirements or non-air quality environmental impacts.
NO* reductions are expected to be similar to those realized at Jim Bridger 2. CHZMHILL
recommends that the unit be permitted at a rate of 0.26Ib per MMBtu.
SOz Emission Control
CH2M HILL recommends upgrading the existing wet sodium FGD system as BART for
Jim Bridger 4, based on the significant reduction in SO2 emissions, reasonable control costs,
and the advantages of minimal additional power requirements and minimal non-air quality
environmental impacts. This upgrade approach will meet the BART presumptive SOz limit of
0.15 lb per MMBtu.
PMro Emission Control
CH2M HILL recommends finalizing the permitting of the flue gas conditioning (FGC)
system to enhance the performance of the existing ESP as BART for Jim Bridger 4, based on
the significant reduction in PMro emissions, reasonable control costs, and the advantages of
minimal additional power requirements and no non-air quality environmental impacts.
BART Modeling Analysis
CH2M HILL used the CALPUFF modeling system to assess the visibility impacts of
emissions from Jim Bridger 4 at Class I areas. The Class I areas potentially affected are
located more than 50 kilometers, but less than 300 kilometers, from the Jim Bridger Plant.
Exhibit No. 2 -^.cr"" No tpt-e-tg-to ES-3
T. Harvey, IPC
Page 5 of 96
JMS EY1 O2OO7OO1 SLC\BART-JB4-OCT2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
The Class I areas include the following wilderness areas:
. Bridger Wilderness Area. Fitzpatrick Wildemess Area. Mt. Zirkel Wilderness Area
Because Jim Bridger 4 will simultaneously control NO*, SO2, and PMro emissions, four
post-control atmospheric dispersion modeling scenarios were developed to cover the range of
effectiveness for combining the individual NO*, SO2, and PMro control technologies under
evaluation. These modeling scenarios, and the controls assumed, are as follows:
. Scenario 1: New LNB with OFA modifications, upgraded wet FGD system, and FGC for
enhanced ESP performance. As indicated previously, this scenario represents
CH2M HILL's preliminary BART recommendation.
. Scenario 2: New LNB with OFA modifications, upgraded wet FGD system, and new
polishing fabric filter.
. Scenario 3: New LNB with OFA modifications and SCR, upgraded wet FGD system,
and FGC for enhanced ESP performance.
. Scenario 4: New LNB with OFA modifications and SCR, upgraded wet FGD system,
and new polishing fabric filter.
Visibility improvements for all emission control scenarios were analyzed, and the results
were compared using a least-cost envelope, as outlined in the New Source Review Workshop
Manual.l
Least-cost Envelope Analysis
The EPA has adopted the least-cost envelope analysis methodology as an accepted
methodology for selecting the most reasonable, cost-effective controls. Incremental
cost-effectiveness comparisons focus on annualized cost and emission reduction differences
between dominant alternatives. The dominant set of control alternatives is determined by
generating the envelope of least-cost alternatives. This is a graphical plot of total annualized
costs for a total emissions reductions for all control altematives identified in the BART
analysis.
To evaluate the impacts of the modeled control scenarios on the three Class I areas, the total
annualized cost, cost per deciview (dV) reduction, and cost per reduction in number of days
above 0.5 dV were analyzed. This report provides a comparison of the average incremental
costs between relevant scenarios for the three Class I areas; the total annualized cost versus
number of days above 0.5 dV, and the total annualized cost versus 98tr percentile
delta-deciview (AdV) reduction.
Results of the least-cost envelope analysis validate the selection of Scenario l, based on
incremental cost and visibility improvements. Scenario 2 (LNB with OFA, upgraded wet
FGD, and polishing fabric filter) is eliminated, because it is to the left of the curve formed by
1 EPR, 'lggO. New Source Review Workshop Manual. Draft. Environmental Protection Agency. October, 1990.
Exhibit No. 2 -^c""" r.r" IPC-E-13-16 ES 4
T. Harvey, IPC
Page 6 of 96
JMS EY1 O2OO7OO1 SLC\BART-JB4-OCT2OO7_FINAL.OOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
the dominant control alternative scenario, which indicates a scenario with lower
improvement and/or higher costs. Scenario 3 (LNB with OFA and SCR, upgraded wet FGD,
and FGC for enhanced ESP performance) is not selected due to very high incremental costs,
on the basis of both a cost per day of improvement and cost per dV reduction. While
Scenario 4 (LNB with OFA and SCR, upgraded wet FGD, and polishing fabric filter)
provides some potential visibility advantage over Scenario l, the projected improvement
less than 0.5 dV, and the projected costs are excessive. Therefore, Scenario I represents
BART for Jim Bridger 4.
Just-Noticeable Differences in Atmospheric Haze
Studies have been conducted that demonstrate only dV differences of approximately
1.5 to 2.0 dV or more are perceptible by the human eye. Deciview changes of less than 1.5
cannot be distinguished by the average person. Therefore, the modeling analysis results
indicate that only minimal, if any, observable visibility improvements at the Class I areas
studied would be expected under any of the control scenarios. Thus, the results indicate that
only minimal discernable visibility improvements may result, even though PacifiCorp will be
spending many millions of dollars at this single unit, and over a billion dollars when
considering its entire fleet of coal-fired power plants.
Exhibit No. 2c"". f.r" tPC-g-tg-to E$s
T. Harvey, IPC
Page 7 of 96
JMS EY1 O2OO7OOl SLC\BART-JB4-OCT2OO7_FINAL.DOC
Contents
r.0
2.0
3.0
Introduction.............
Present Unit Operation.
BART Engineering Analysis
1-l
2-l
3-l
3-l
3-l
4.0
3.1 Applicability................
3.2 BART Process......
3.2.1 BART NO* Ana1ysis................ ..............3-2
3.2.2 BART SO2 Analysis............... .............3-14
3.2.3 BART PMle Analysis.............. ............3-16
BART Modeling Analysis.... .....................4-14.1 Model Selection ..........4-14.2 CALMET Methodology............... ....................4-1
4.2.1 Dimensions of the Modeling Domain...... .................4-l
4.2.2 CALMET Input Data. .........4-3
4.2.3 Validation of CALMET Wind Field.......... ...............4-64.3 CALPUFF Modeling Approach. .....................4-6
4.3.1 Background Ozone and Ammonia................ ............4-6
4.3.2 Stack Parameters........... ......4-6
4.3.3 Emission Rates.......... ..........4-7
4.3.4 Post-control Scenarios ........4-7
4.3.5 Modeling Process...... ..........4-8
4.3.6 Receptor Grids ......... ...........4-84.4 CALPOST .................4-104.5 Presentation of Modeling Results .................4-11
4.5.1 Visibility Changes for Baseline vs. Preferred Scenario.............4-l I
Preliminary Assessment and Recommendations ......5-15.1 Least-cost Envelope Analysis.... ......................5-1
5.1.1 Analysis Methodology................ ...........5-l
5.1.2 Analysis Results....... ...........5-95.2 Recommendations...... ...................5-9
5.2.1 NO, Emission Control ........5-9
5.2.2 SOz Emission Control .........5-9
5.2.3 PMro Emission Control .......5-95.3 Just-Noticeable Differences in Atmospheric Haze.. .......5-10References ............ Gl
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 8 of 96
5.0
6.0
P:\PACIFICORn34SE5BARnDAVEJOHNSTON3_FINALSUBMITTAL\BART_JB4_OCT2007_FINAL.DOC
CONTENTS (CONTINUED)
3-6
3-7
4-l
4-2
4-3
4-4
Tables2-l Unit Operation and Study Assumptions2-2 Coal Sources and Characteristics3-l CoalCharacteristicsComparison3-2 NO* Control Technology Projected Emission Rates3-3 NO* Control Cost Comparison3-4 SOz Control Technology Emission Rates
3-5 Sulfur Dioxide Control Cost Comparison (Incrementalto Existing Flue Gas
Desulfurization System)
PMro Control Technology Emission Rates
PMro Control Cost Comparison (lncremental to Existing ESP)
User-specified CALMET Options
BART Model Input Data
Average Natural Levels of Aerosol Components
Costs and Visibility Modeling Results for Baseline Vs. Post-Control Scenarios at
Class I Areas
5-l Control Scenario Results for the Bridger Class I Wilderness Area
5-2 Control Scenario Results for the Fitzpatrick Class I Wilderness Area
5-3 Control Scenario Results for the Mt. Zirkel Class I Wilderness Area
5-4 Bridger Class I Wilderness Area Incremental Analysis Data
5-5 Fitzpatrick Class I Wilderness Area Incremental Analysis Data
5-6 Mt. Zirkel Class I Wildemess Area Incremental Analysis Data
Figures3-1 Illustration of the Effect of Agglomeration on the Speed of Coal Combustion3-2 Plot of Typical Nitrogen Content of Various Coals and Applicable Presumptive
BART NO* Limits3-3 Plot of Typical Oxygen Content of Various Coals and Applicable Presumptive
BART NO, Limits
First Year Control Cost for NO* Air Pollution Control Options
First Year Control Cost for PM Air Pollution Control Options
Jim Bridger Sourcespecific Class I Areas to be Addressed
Surface and Upper Air Stations Used in the Jim Bridger BART Analysis
Least-cost Envelope Bridger Class I WA Days Reduction
Least-cost Envelope Bridger Class I WA 98th Percentile Reduction
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 9 of 96
3-4
3-5
4-l
4-2
5-1
5-2
5-3
5-4
5-5
5-6
Least-cost Envelope Fitzpatrick Class I WA Days Reduction
Least-cost Envelope Fitzpatrick Class I WA 98th Percentile Reduction
Least-cost Envelope Mt. Zirkel Class I WA Days Reduction
Least-cost Envelope Mt. Zirkel Class I WA 98th Percentile Reduction
AppendicesA Economic AnalysisB 2006 Wyoming BART Protocol
JMS EYlO2OOTOOlSLC\BART J84 OCT2OOT_FINAL.DOC
Acronyms and Abbreviations
BACT
BART
CALDESK
CALMET
CALPOST
CALPUFF
COHPAC
OC
OF
dV
Adv
DEQ
ESP
EPA
Fuel NO*
FGC
FGD
,f(RH)
ID
kw
kW-Hr
LAER
lb
LNB
LOI
MMBtU
MM5
MW
Nz
NO
NO*
NWS
Best Available Control Technology
Best Available Retrofit Technology
Program to Display Data and Results
Meteorological Data Preprocessing Program for CALPUFF
Post-Processing Program for Calculating Visibility Impacts
Gaussian Puff Dispersion Model
Compact Hybrid Particulate Collector
Degrees Celsius
Degrees Fahrenheit
Deciview
Delta Deciview, Change in Deciview
Department of Environmental Quality
Electrostatic Precipitator
United States Environmental Protection Agency
Oxidation of Fuel Bound Oxides of Nitrogen
Flue Gas Conditioning
Flue Gas Desulfurization
Relative Humidity Factors
Intemal Diameter or Induced Draft
Kilowatts
Kilowatt-Hour
Lowest Achievable Emission Rate
Pound(s)
Low-NO* Burner
Loss on Ignition
Million British Thermal Units
Mesoscale Meteorological Model, Version 5
Megawatts
Nitrogen
Nitric Oxide
Nitrogen Oxides
National Weather Service
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 10 of96
JMS EY1 O2OO7OO1 SLC\BART-JB4-OCT2OO7-FINAL.DOC
ACRONYMS AND ABBREVIATIONS (CO'ITINUED)
OFA Over-fire Air
PMro Particulate Matter Less than l0 Micrometers in Aerodynamic Diameter
PRB Powder River Basin
ROFA Rotating Opposed Fire Air
S&L Sargent & Lundy
SCR Selective catalytic Reduction System
SIP State Implementation Plan
SNCR Selective Non-Catalytic Reduction System
SOz Sulfur Dioxide
SO: Sulfur Trioxide
ThermalNO,. High Temperature Fixation of Atmospheric Nitrogen in Combustion Air
USGS U.S. Geological Survey
WA Wilderness Area
WDEQ-AQD Wyoming Department of Environmental Quality-Air Quality Division
Exhibit No. 2
Case No. IPC-E-I3-16
T. Harvey, IPC
Page 11 of96
JMS EY,IO2OOTOO1SLC\BART_JB4_OCT2OO7_FINAL.DOC
1.0 lntroduction
Best Available Retrofit Technology (BART) guidelines were established as a result of United
States Environmental Protection Agency (EPA) regulations intended to reduce the
occurrence of regional haze in national parks and other Class I protected air quality areas in
the United States (40 CFR Part 5l ). These guidelines provide guidance for states when
determining which facilities must install additional controls, and the type of controls that
must be used. Facilities eligible for BART installation were built between 1962 and 1977,
and have the potential to emit more than 250 tons per year of visibility-impairing pollutants.
The Wyoming Department of EnvironmentalQuality (WDEQ) BART regulations state that
each source subject to BART must submit a BART application for a construction permit by
December 15, 2006. PacifiCorp received an extension from the WDEQ to submit the BART
report for Jim Bridger Unit 4 (hereafter referred to as Jim Bridger 4) by January 12,2007 .
The BART Report that was submitted to WDEQ in January 2007 included a BART analysis,
and a proposal and justification for BART at the source. This revised report-submitted in
October 20O7-incorporates editorial revisions since the January 2007 version.
The State of Wyoming has identified those eligible in-state facilities that are required to
reduce emissions under BART, and will set BART emissions limits for those facilities. This
information will be included in the State of Wyoming State Implementation Plan (SIP),
which the State has estimated will be formally submitted to the EPA by early 2008. The EPA
BART guidelines also state that the BART emission limits must be fully implemented within
5 years of EPA's approval of the SIP.
Five elements related to BART address the issue of emissions for the identified facilities:
. Any existing pollution control technology in use at the sourceo The cost of the controlso The remaining useful life of the sourceo The energy and non-air quality environmental impacts of complianceo The degree of improvement in visibility that may reasonably be anticipated from the use
of such technology
This report documents the BART analysis that was performed on Jim Bridger 4 by
CH2M HILL for PacifiCorp. The analysis was performed for the pollutants nitrogen oxides,
(NO*> sulfur dioxide (SOz), and particulate matter less than l0 micrometers in aerodynamic
diameter (PMro), because they are the primary criteria pollutants that affect visibility.
Section 2 of this report provides a description of the present unit operation, including a
discussion of coal sources and characteristics. The BART Engineering Analysis is provided
in Section 3. Section 4 provides the methodology and results of the BART Modeling
Analysis, followed by recommendations in Section 5 and references in Section 6. Appendices
provide more detail on the economic analysis and the 2006 Wyoming BART Protocol.
Exhibit No. 2 n_nCase No. IPC-E-13-16
T. Harvey, IPC
Page 12 of96
JMS EY,IO2OOTOOlSLC\BART,JB4.OCT2OO7 FINAL.DOC
2.0 Present Unit Operation
The Jim Bridger Station consists of four units with a total generating capacity of
2,120 megawatts (MW). Jim Bridger 4 is a nominal 530 net-MW unit located approximately
35 miles northeast of Rock Springs, Wyoming. Unit 4 is equipped with a tangentially-fired
pulverized coal boiler with low NO* burners (LNBs) manufactured by Combustion
Engineering. The unit was constructed with a Flakt wire frame electrostatic precipitator
(ESP). The unit contains a Babcock & Wilcox wet sodium flue gas desulfurization (FGD)
system with three absorber towers installed in 1982. An Emerson Ovation distributed control
system was installed in 2004.
Jim Bridger 4 was placed in service in 1979.lts current economic depreciation life is through
2040; however, this analysis is based on aZ}-year life for BART control technologies.
Assuming a BART implementation date of 2014, this will result in an approximate remaining
useful life for Jim Bridger 4 of 20 years from the installation date of any new or modified
BART-related equipment. This report does not attempt to quantiff any additional life
extension costs needed to allow the unit and these control devices at Jim Bridger 4 to operate
until2040.
Table 2-1 lists additional unit information and study assumptions for this analysis.
The BART-presumptive NO* limit for tangential-fired boilers buming sub-bituminous coal is
0.15 lb per MMBtu and the BART-presumptive NO* limit for burning bituminous coal is
0.28 lb per MMBtu. The main sources of coal bumed at Jim Bridger 4 are the Bridger Mine
and secondarily the Black Butte Mine and Leucite Hills Mine. These coals are ranked as
sub-bituminous, but are closer in characteristics to bituminous coal in many of the parameters
influencing NO* formation. These coals have higher nitrogen content than coals from the
Powder River Basin (PRB), which represent the bulk of sub-bituminous coal use in the U.S.
This BART analysis has considered the higher nitrogen content and different combustion
characteristics of PRB coals as compared to those coals used at Jim Bridger 4, and has
evaluated the effect of these qualities on NO* formation and achievable emission rates. Coal
sources and characteristics are summarized in Table 2-2.The primary source of coal will be
the Bridger Underground Mine, and data on coal from this source were used in the modeling
analysis. For the coal analysis that is presented in Section 3.2.1, the data from all the coal
sources were used.
Exhibit No. 2 ,_,Case No. IPC-E-13-16 '
T. Harvey, IPC
Page 13 of96
JMS EY1 02OO7OO1 SLC\BART_JB4_OCT2OO7-FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
TABLE 2.1
Unit Operation and Study Assumptions
Jin Bridoer 4
Genera! Plant Data
Site Elevation (feet above mean sea level)
Stack Height (feet)
Stack Exit lnside Diameter (feet) and Exit Area (square feet)
Stack Exit Temperature (degrees Fahrenheit)
Stack Exit Velocity (feet per second)
Stack Flow (actual cubic feet per minute)
Latitude deg: min : sec
Longitude deg: min : sec
Annual Unit Capacity Factor (percentage)
Net Unit Output (megawatts)
Net Unit Heat Rate (Biltish thermal units [Btu] per kilowatt-
hour)(100% load)
Boiler Heat lnput (million Btu [MMbtu] per hour)(100% load)
Type of Boiler
Boiler Fuel
Coal Sources
Coal Heating Value (Btu per pound)*
Coal Sulfur Content (wt. %)(")
Coal Ash Content (*t. %)(")
Coal Moisture Content (wt. o/of")
Coal Nitrogen Content (M. "7of"l
Current NO, Gontrols
NO, Emission Rate (pound per MMBtu)
Current Sulfur Dioxide Controls
Sulfur Dioxide Emission Rate (pound per MMBtu)
Current PMro Controls(b)
PMro Emission Rate (pound per MMBtu)(")
6669
s00
311755
120
42.4
1,920,610
41:44'.20.82 norlh
108:47:15.17 west
90
530
10,400 (as measured by fuel
throughout)
6,000 (as measured by CEM)
Tangentially fired
Coal
Bridger Mine, Black Bufte Mine,
Leucite Hills Mine
9,660
0.58
10.3
19.3
0.98
Low-NO. burners
0.4s
Sodium based wet scrubber
0.167
Electrostatic Precipitator
0.030
NOTES:(")Coal characteristics based on Bridger Underground Mine (primary coal source)(b)PM.,o refers to particulate matter less than 10 micrometers in aerodynamic diameter(')Based on maximum historic emission rate from 1999 - 2001 , prior to installation of the SOs injection
system.
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page '14 of 96
JMS EY,I O2OO7OO1 SLC\BART_JB4_OCT2OO7-FINAL.DOC
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Case No. IPC-E-13-16
T. Harvey, IPG
Page 15 of96
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3.0 BART Engineering Analysis
This section presents the required BART engineering analysis.
3.1 Applicability
In compliance with regional haze requirements, the State of Wyoming must prepare and submit
visibility SIPs to the EPA for Class I areas. The State has estimated that the formal submittal of
the SIPs will occur by early 2008. The first phase of the regional haze program is the
implementation of BART emission controls on all BART eligible units, within 5 years after
EPA approval ofthe SIP.
3.2 BART Process
The specific steps in a BART engineering analysis are identified in the Code of Federal
Regulations (CFR) at 40 CFR 51, Appendix Y, Section IV. The evaluation must include:
o The identification of available, technically feasible, retrofit control options
o Consideration of any pollution control equipment in use at the source (which affects the
availability of options and their impacts)
o The costs of compliance with the control options
o The remaining useful life of the facility
o The energy and non-air quality environmental impacts of compliance
. The degree of visibility improvement that may reasonably be anticipated from the use of
BART
The following steps are incorporated into the BART analysis:
. Step I - Identift All Available Retrofit Control Technologies
o Step 2 - Eliminate Technically Infeasible Options
The identification of available, technically feasible, retrofit control options
Consideration of any pollution control equipment in use at the source (which affects the
applicability of options and their impacts)
. Step 3 - Evaluate Control Effectiveness of Remaining Control Technologies
. Step 4 - Evaluate Impacts and Document the Results
The costs of compliance with the control options
The remaining useful life of the facility
The energy and non-air quality environmental impacts of compliance
Exhibit No. 2
Case No. IPC-E-13-16 3-1
T. Harvey, IPC
Page 16 of96
JMS EY1 O2OO7OO1 SLC\BART-J B4-OCT2OO7-FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
o
. Step 5 - Evaluate Visibility Impacts
The degree of visibility improvement that may reasonably be anticipated from the use
ofBART
To minimize costs in the BART analysis, consideration was made of any pollution control
equipment in use at the source, the costs of compliance associated with the control options, and
the energy and non-air quality environmental impacts of compliance using these existing
control devices. In some cases, enhancing the performance of the existing control equipment
was considered. Other scenarios with new control equipment were also developed.
Separate analyses have been conducted for NO*, SOz, and PMro emissions. All costs included
in the BART analysis are in 2006 dollars, and costs have not been escalated to the assumed
2014 BART implementation date.
3.2.1 BART NO, Analysis
Nitrogen oxide formation in coal-fired boilers is a complex process that is dependent on a
number of variables, including operating conditions, equipment design, and coal characteristics.
Formation of NO,
During coal combustion, NO* is formed in three different ways. The dominant source ofNO*
formation is the oxidation of fuel-bound nitrogen. During combustion, part of the fuel-bound
nitrogen is released from the coalwith the volatile matter, and part is retained in the solid
portion (char). The nitrogen chemically bound in the coal is partially oxidized to nitrogen
oxides (nitric oxide and nitrogen dioxide) and partially reduced to molecular nitrogen. A
smaller part of NO* formation is due to high temperature fixation of atmospheric nitrogen in
the combustion air. A very small amount of NO* is called prompt NO,. Prompt NO* results
from an interaction ofhydrocarbon radicals, nitrogen, and oxygen.
In a conventional pulverized coal burner, air is introduced with turbulence to promote good
mixing of fuel and air, which provides stable combustion. However, not all of the oxygen in the
air is used for combustion. Some of the oxygen combines with the fuel nitrogen to form NO*.
Coal characteristics directly and significantly affect NO* emissions from coal combustion. Coal
ranking is a means of classifuing coals according to their degree of metamorphism in the
natural series, from lignite to sub-bituminous to bituminous and on to anthracite. Lower rank
coals, such as the sub-bituminous coals from the PRB, produce lower NO* emissions than
higher rank bituminous coals, due to their higher reactivity and lower nitrogen content. The
fixed carbon to volatile matter ratio (fuel ratio), coal oxygen content, and rank are good relative
indices of the reactivity of a coal. Lower rank coals release more organically bound nitrogen
earlier in the combustion process than do higher rank bituminous coals. When used with LNBs,
sub-bituminous coals create a longer time for the kinetics to promote more stable molecular
nitrogen, and therefore result in lower NO* emissions.
Coals from the PRB are classified as sub-bituminous C and demonstrate the high reactivity and
low NO* production characteristics described above. Based on data from the Energy
Information Administration, PRB coals currently represent 88 percent of total U.S. sub-
bituminous production and73 percent ofwestern coal production (Energy Information
Administration, 2006). Most references to western coal and sub-bituminous coal infer PRB
Exhibit No. 2
Case No. IPC-E-13-16 3'2
T. Harvey, IPC
Page 17 of96
JMS EY,I O2OO7OO1 SLC\8ART-JB4_OCI2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
origin and characteristics. Emissions standards differentiating between bituminous and sub-
bituminous coals are presumed to use PRB coal as the basis for the sub-bituminous standards,
due to its dominant market presence and unique characteristics.
There are a number of western coals that are classified as sub-bituminous, however, they border
on being ranked as bituminous and do not display many of the qualities of PRB coals, including
most of the low NO* forming characteristics. Coals from the Bridger, Black Butte, and Leucite
Hills mines fall into this category.
As defined by the American Society for Testing and Materials, the only distinguishing
characteristic that classifies the coals used at Jim Bridger 4 as sub-bituminous rather than
bituminous-that is, they are "agglomerating" as compared to "non-agglomerating".
Agglomerating as applied to coal is "the property of softening when it is heated to above about
400 degrees Celsius ('C) in a non-oxidizing atmosphere, and then appearing as a coherent mass
after cooling to room temperature." Because the agglomerating property of coals is the result of
particles transforming into a plastic or semi-liquid state when heated, it reflects a change in
surface area of the particle. Thus, with the application of heat, agglomerating coals would tend
to develop a non-porous surface, while the surface of non-agglomerating coals would become
even more porous with combustion. As shown by Figure 3-1, the increased porosity provides
more particle surface area, resulting in more favorable combustion conditions. This non-
agglomerating property assists in making sub-bituminous coals more amenable to controlling
NO*, by allowing less air to be introduced during the initial ignition portion of the combustion
process. The coals from the Bridger, Black Butte, and Leucite Hills mines just barely fall into
the category of non-agglomerating coals. While each of these coals is considered non-
agglomerating, they either do not exhibit the properties of non-agglomerating coals or exhibit
them to only a minor degree. The conditions during combustion of typical non-agglomerating
coals that make it easier to control NO* emissions do not exist for the Bridger blends of coals.
FIGURE 3.1
lllustration of the Effect of Agglomeration on the Speed of Coal Combustion
Jim Bidger4
IHE EFFECI OF AGGTOTIERAIING IE.IDENCY UFON COMBUSIION
IGNINON CHAN
I
NONAGOLOMIIAII'{G0
ACCtOmEtAilNOo
IAr.*l
AI+l
rffi motEsutrActArEA/mA53
I!ult{5fASrEr
tE35gUIFACf,
alEA/xlass
IlUINSStow:t
oEvotAl[lzAiloN
AND COM!USIION
Exhibit No. 2
Case No.lPC-E-13-16
T. Harvey, IPC
Page 18 of96
JMS EY.I O2O()7OO1 SLC\BART_JB4.OCT20O7_FINAL.OOC
BART ANALYSIS FOR JIM BRIDGER TJNIT 4
Table 3-l shows key characteristics of a typical PRB coal compared to coals from the Bridger
Mine, Black Buffe, and Leucite Hills, as well as Twentymile, which is a representative western
bituminous coal.
TABLE }I
Coal Characteristics Comparison
lim P*lnorl
Parameter Typica!
PRB
Bridger
Mine
Leucite
Hills
TwentymileBlack
Butte
Nitrogen ('/" dry)
Oxygen (% dry)
Coal rank
'1.10
16.2
Sub C
1.26
13.2
Sub B
1.47
13.4
Sub B
1.48
13.2
Sub B
1.85
7.19
Bitum. high volatility B
As shown in Table 3-1, although Bridger, Black Butte, and Leucite Hills are classified as
sub-bituminous, they all exhibit higher nitrogen content and lower oxygen content than the
PRB coal. The higher nitrogen content is an indication that more nitrogen is available to the
combustion process and higher NO* emissions are likely. Oxygen content can be correlated to
the reactivity of the coal, with more reactive coals generally containing higher levels of oxygen.
More reactive coals tend to produce lower NO* emissions, and they are also more conducive to
reduction of NO* emissions through the use of combustion control measures, such as LNBs and
over-fire air (OFA). These characteristics indicate that higher NO* formation is likely with coal
from the Bridger, Black Butte, and Leucite Hills mines, rather than with PRB coal. The
Bridger, Black Butte, and Leucite Hills coals all contain quality characteristics that fall between
a typical PRB coal and Twentymile. Twentymile is a clearly bituminous coal that produces
higher NOr, as has been demonstrated at power plants burning this fuel.
Figures 3-2 and 3-3 graphically illustrate the relationship of nitrogen and oxygen content to the
BART-presumptive NO* limits for the coals listed in Table 3-l. Each chart identifies the
presumptive BART limit associated with a typical bituminous and sub-bituminous coal, and
demonstrates how the Jim Bridger coal falls between these two general coal classifications.
The Bridger blend data point represents a combination of coals from the Bridger Mine, Black
Butte, and Leucite Hills that has been used at Jim Bridger 4, and indicates the average NO*
emission rate achieved during the years 2003 through 2005. The Jim Bridger 2 datapoint
consists of the same blend of coals as Jim Bridger 4, and represents the NO, emission rate
achieved after installation of Alstom's current state of the art TFS2000 LNB and OFA system.
The long-term sustainable emission rate for this system is expected tobe 0.24Ib per MMBtu.
All four units at Jim Bridger consist of identical boilers; and while there may be some
differences in performance among them, installation of the TFS2000 firing system at
Jim Bridger 4 would likely result in performance and NO* emission rates comparable to those
at Jim Bridger 2.
Figures 3-2 and 3-3 both demonstrate that for the Jim Bridger units with the TFS2000 low-NO*
emission system installed and burning a combination of the Bridger, Black Butte, and Leucite
Hill coals, the likely NO* emission rate will be closer to the bituminous end (0.28) of the
BART-presumptive NO* limit range, rather than the BART-presumptive NO" limit of 0.15 lb
Exhibit No. 2
Case No. lPc-E-13-16 3-4
T. Harvey, IPC
Page 19 of96
JMS EY1 O2OOTOOlSLC\BART-JB4_OCT2OO7-FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
per MMBtu for sub-bituminous coal. All these factors are consistent with the observed
sustainable rate of 0.24Ib per MMBtu.
FIGURE 3.2
Plot of Typical Nitrogen Content of Various Coals and Applicable Presumptive BART NO Limib
Jim Bridgu4
g'".
IJ o.25
T
A
Bridgcr BlGnd
--{---Bituminoua Pr€3umptive Limit - 0.28 lb/I\rMBtu _tyiyl1'_Blt'llr'_"_*-\im Brioger2
PRB Subbituminou3 Subbituminoua Prclumptive Limit - O.15 lb/MMBtu
1.OO 1.30 1.40 1.50 1.60 1.70
Typi€l Nliroe.n Cont nt (%-Dry B[1.)
1.90
FIGURE 3.3
Plot of Typical Orygen Content of Various Coals and Applicable Presumptive BART NO, Limits
Jim Brdger4
0.45
0.45
o.'r
g'".
IJ 0.25t
o.2
0.15
o.1
6.OO to.oo 12.oo
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 20 of 96
ABridgcr Blcnd
r*.tvt"ir" eiiii*"
-----Bituminous Prssumotiv6 Limit - O.28 lb,/MMBtu
---lim ariogerz
_-...,- -_-...,_ -_--- -_-- - -_- _-_- - - -a-_ -_--- -Subbituminoua Prcaumotivo Limit - O.lslb/MMBt, pRB Subbituminous
JMS EY1 O2OO7O()1 SLC\BART_JB4-OCT2OO7_FINAL.DOC
Typlal OxlE.n Cont nt (%-Dry B.!i.)
BART ANALYSIS FOR JIM BRIDGER UNIT 4
Coal quality characteristics also impact the design and operation of the boiler and associated
auxiliary equipment. Minor changes in quality can sometimes be accommodated through
operational adjustments or changes to equipment. It is important to note, however, that
consistent variations in quality or assumptions of o'average" quality for performance projections
can be problematic. This is particularly troublesome when dealing with performance issues that
are very sensitive to both coal quality and combustion conditions, such as NO* formation.
There is significant variability in the quality of coals burned at Jim Bridger 4. In addition to
burning coal from Black Butte and Leucite Hills, Jim Bridger 4 burns coal supplied from the
Bridger Mine consisting of three sources: underground, surface, and highwall operations. Each
of these coal sources has different quality characteristics, as well as inherent variability in
composition of the coal within the mine.
Several of the coal quality characteristics and their effect on NO* formation have been
previously discussed. There are some additional considerations that illustrate the complexity of
achieving and maintaining consistent low NO* emissions with pulverized coal on a shorter
term, such as a 30-day rolling average basis.
Good combustion is based on the "three Ts": time, temperature, and turbulence. These
parameters, along with a "design" coal, are taken into consideration when designing a boiler
and associated firing equipment such as fans, burners, and pulverizers. If a performance
requirement such as NO* emission limits is subsequently changed, conflicts with and between
other performance issues can result.
Jim Bridger 4 is located at an altitude of 6,669 feet above sea level. At this elevation,
atmospheric pressure is lower (l1.5 lbs per square inch) as compared with sea level pressure of
14.7 lbs per square inch. This lower pressure means that less oxygen is available for
combustion for each volume of air. In order to provide adequate oxygen to meet the
requirements for efficient combustion, larger volumes of air are required. When adjusting air
flows and distribution to reduce NO" emissions, using LNBs and OFA, original boiler design
restrictions again limit the modifications that can be made and still achieve satisfactory
combustion performance.
Another significant factor in controlling NO,. emissions is the fineness of the coal entering the
burners. Fineness is influenced by the grindability index (Hardgrove) of the coal. Finer coal
particles promote release of volatiles and assist char burnout as a result of more surface area
exposed to air. NO* reduction with high volatile coals is improved with greater fineness and
with proper air staging. The lower rank sub-bituminous coals such as PRB coals are quite
friable and easy to grind. Coals with lower Hardgrove Grindability Index values, such as those
used at Jim Bridger 4, are more difficult to grind and can contribute to higher NO* levels. In
addition, coal fineness can deteriorate over time periods between pulverizer maintenance and
service as pulverizer grinding surfaces wear.
In summary, when all the factors of agglomeration versus non-agglomeration, nitrogen and
oxygen content of the coals, and the grindability index are taken into account, this analysis
demonstrates that, for the coal used at Jim Bridger 4, the more applicable presumptive BART
limit for NO* emissions is 0.28 lb per MMBtu. The BART analysis for NO* emissions from
Jim Bridger 4 is further described below.
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page21 of96
JMS EY1 O2OO7OOl SLC\BARI_JB4-OCI2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
Step 1: ldentify All Available Retrofit Control Technologies
The first step of the BART process is to evaluate NO* control technologies with practical
potential for application to Jim Bridger 4, including those control technologies identified as
Best Available Control Technology (BACT) or lowest achievable emission rate (LAER) by
permitting agencies across the United States. Broad-ranging information sources were reviewed
in an effort to identift potentially applicable emission control technologies. NO* emissions at
Jim Bridger 4 are currently controlled through good combustion practices and OFA.
The following potential NO* control technology options were considered:
o New/modified LNBs with advanced OFAo Rotating opposed fire air (ROFA)r LNB with OFA and conventional selective non-catalytic reduction (SNCR) systemo LNB with OFA and selective catalytic reduction (SCR) system
Step 2: Eliminate Technically lnfeasible Options
For Jim Bridger 4, a tangential-fired configuration buming sub-bituminous coal, technical
feasibility will primarily be determined by physical constraints, boiler configuration, and the
ability to achieve the regulatory presumptive limit of 0.28 lb per MMBtu. Jim Bridger 4 has an
uncontrolled NO* emission rate of 0.45 lb per MMBtu.
For this BART analysis, information pertaining to LNBs, OFA, SNCR, and SCR were based on
the Multi-Pollutant Control Report (Sargent and Lundy, 2002,hereafter referred to as the S&L
Study). Updated cost estimates for SCR and SNCR were used (Sargent & Lundy, 2006).
PacifiCorp provided additional emissions data and costs developed by boiler vendors for LNBs
and OFA. Also, CH2M HILL solicited a proposal from Mobotec for their ROFA technology.
With SNCR, an amine-based reagent such as ammonia, or more commonly urea, is injected
into the fumace within a temperature range of 1,600 degrees Fahrenheit ('F) to 2,100oF, where
it reduces NO* to nitrogen and water. NO* reductions of up to 40 to 60 percent have been
achieved, although l5 to 30 percent is more realistic for most applications. SNCR is typically
applied on smaller units. Adequate reagent distribution in the furnaces of large units can be
problematic.
Table 3-2 summarizes the control technology options evaluated in this BART analysis, along
with projected NO* emission rates. All technologies can meet the applicable presumptive
BART limit of 0.28 lb per MMBTU.
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 22 of 96
JMS EYlO2OOTOOISLC\BART J84 OCT2OOT FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
TABLE 3.2
N0, Control Technology Projected Emission Rates
Jin Bridoer4
Technology Projected Emission Rate (pounds per
million British thermal units)
Presumptive Best Available
Retrofit Technology Limit
Low NO, Blower (LNB) with
Over-Fire Air (OFA)
Rotating Opposed Fire Air
LNB with OFA and Selective
Non-Catalytic Red uction System
LNB with OFA and Selective
Catalytic Reduction System
0.28
0.24
0.22
0.20
0.07
Step 3: Evaluate Control Effectiveness of Remaining Contro! Technologies
Preliminary vendor proposals, such as those used to support portions of this BART analysis,
may be technically feasible and provide expected or guaranteed emission rates; however, the
proposals include inherent uncertainties. These proposals are usually prepared in a limited
timeframe, may be based on incomplete information, may contain over-optimistic conclusions,
and are non-binding. Therefore, emission rate values obtained in such preliminary proposals
must be qualified, and it must be recognized that contractual guarantees are established only
after more detailed analysis has been completed. The following subsections describe the control
technologies and the control effectiveness evaluated in this BART analysis.
New LNBs with OFA System. The mechanism used to lower NO* with LNBs is to stage the
combustion process and provide a fuel-rich condition initially; this is so oxygen needed for
combustion is not diverted to combine with nitrogen and form NO*. Fuel-rich conditions favor
the conversion of fuel nitrogen to Nz instead of NO*. Additional air (or OFA) is then introduced
downstream in a lower temperature zone to burn out the char.
Both LNBs and OFA are considered to be capital cost, combustion technology retrofits. For
LNB retrofits to units configured with tangential-firing such as Jim Bridger 4, it is generally
necessary to increase the bumer spacing; this prevents interaction of the flames from adjacent
burners and reduces burner zone heat flux. These modifications usually require boiler
waterwall tube replacement.
Information provided to CH2M HILL by PacifiCorp-based on the S&L Study and data from
boiler vendors-indicates that new LNB and OFA retrofit at Jim Bridger 4 would result in an
expected NO* emission rate of 0.24Ib per MMBtu. PacifiCorp has indicated that this rate
corresponds to a vendor guarantee, not a vendor prediction, and they believe that this emission
rate can be sustained as an average between overhauls. This emission rate represents a
significant reduction from the current NO* emission rate, and is below the more applicable
presumptive NO* emission rate of 0.28 lb per MMBtu.
Exhibit No. 2
Case No. lPc-E-13-16 18
T. Harvey, IPC
Page 23 of 96
JMS EY1 O2OO7OO1 SLC\BART-JB4_OCT2OO7_FINAL.OOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
ROFA. Mobotec markets ROFA as an improved second generation OFA system. Mobotec states
that "the flue gas volume of the furnace is set in rotation by asymmetrically placed air nozzles.
Rotation is reported to prevent laminar flow, so that the entire volume of the furnace can be
used more effectively for the combustion process. In addition, the swirling action reduces the
maximum temperature of the flames and increases heat absorption. The combustion air is also
mixed more effectively." A typical ROFA installation would have a booster fan(s) to supply the
high velocity air to the ROFA boxes, and Mobotec would propose two 4,000 to
4,300 horsepower fans for Jim Bridger 4.
Mobotec proposes to achieve a NO* emission rate of 0.18 lb per MMBtu using ROFA
technology. An operating margin of 0.04 lb per MMBtu was added to the expected rate due to
Mobotec's limited ROFA experience with westem sub-bituminous coals. Under the Mobotec
proposal, which is primarily based on ROFA equipment, the operation of existing LNB and
OFA ports would be analyzed. While a typical installation does not require modification to the
existing LNB system and the existing OFA ports are not used, results of computational fluid
dynamics modeling would determine the quantity and location of new ROFA ports. The
Mobotec proposal includes bent tube assemblies for OFA port installation.
Mobotec would not provide installation services, because they believe that the Owner can more
cost-effectively contract for these services. However, they would provide one onsite
construction supervisor during installation and startup.
SNCR. Selective non-catalytic reduction is generally used to achieve modest NO* reductions on
smaller units. With SNCR, an amine-based reagent such as ammonia-or more commonly
urea-is injected into the fumace within a temperature range of 1,600'F to 2,100"F, where it
reduces NO* to nitrogen and water. NO* reductions of up to 60 percent have been achieved,
although 20 to 40 percent is more realistic for most applications.
Reagent utilization, which is a measure of the efficiency with which the reagent reduces NO*,
can range from 20 to 60 percent, depending on the amount of reduction, unit size, operating
conditions, and allowable ammonia slip. With low reagent utilization, low temperatures, or
inadequate mixing, ammonia slip occurs, allowing unreacted ammonia to create problems
downstream. The ammonia may render fly ash unsaleable, react with sulfur to foul heat
exchange surfaces, and/or create a visible stack plume. Reagent utilization can have a
significant impact on economics, with higher levels of NO* reduction generally resulting in
lower reagent utilization and higher operating cost.
Reductions from higher baseline concentrations (inlet NO*) are lower in cost per ton, but result
in higher operating costs, due to greater reagent consumption. To reduce reagent costs, S&L
has assumed that combustion modifications including LNBs and advanced OFA, capable of
achieving a projected NO* emission rate of 0.24Ib per MMBtu, At a further reduction of
l5 percent in NO* emission rates for SNCR would result in a projected emission rate of 0.20 lb
per MMBtu.
SCR. SCR works on the same chemical principle as SNCR, but SCR uses a catalyst to promote
the chemical reaction. Ammonia is injected into the flue-gas stream, where it reduces NO* to
nitrogen and water. Unlike the high temperatures required for SNCR, in SCR the reaction takes
place on the surface of a vanadium/titanium-based catalyst at a temperature range between
580'F to 750oF. As a result of the catalyst, the SCR process is more efficient than SNCR and
Exhibit No. 2
Case No. IPC-E-13-16 }e
T. Harvey, IPC
Page 24 of 96
JMS EY1 O2OO7OO1 SLC\BART_JBI_OCT2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
results in lower NO* emissions. The most common type of SCR is the high-dust configuration,
where the catalyst is located downstream from the boiler economizer and upstream of the air
heater and any particulate control equipment. In this location, the SCR is exposed to the full
concentration of fly ash in the flue gas that leaves the boiler. The high-dust configuration is
assumed for Jim Bridger 4.ln a full-scale SCR, the flue ducts are routed to a separate large
reactor containing the catalyst. With in-duct SCR, the catalyst is located in the existing gas
duct, which may be expanded in the area of the catalyst to reduce flue gas flow velocity and
increase flue gas residence time. Due to the higher removal rate, a full-scale SCR was used as
the basis for analysis at Jim Bridger 4.
S&L prepared the design conditions and cost estimates for SCR at Jim Bridger 4. As with
SNCR, it is generally more cost effective to reduce NO* emission levels as much as possible
through combustion modifications, in order to minimize the catalyst surface area and ammonia
requirements of the SCR. The S&L design basis for LNB with OFA and SCR results in a
projected NO* emission rate of 0.07 lb per MMBtu. Additional catalyst surface was included in
the SCR design to accommodate the characteristics of the coal used at Jim Bridger 4.
Level of Confidence for Vendor Post-Control Emissions Estimates. To determine the level of NO*
emissions needed to consistently achieve compliance with an established goal, a review of
typical NO* emissions from coal-fired generating units was completed. As a result of this
review, it was noted that NO* emissions can vary significantly around an average emissions
level. Variations may result for many reasons, including coal characteristics, unit load, boiler
operation including excess air, boiler slagging, burner equipment condition, coal mill frneness,
and so forth.
The steps used for determining a level of confidence for the vendor expected values are as
follows:
l. Establish expected NO* emissions value from vendor.
2. Evaluate vendor experience and historical basis for meeting expected values.
3. Review and evaluate unit physical and operational characteristics and restrictions. The
fewer variations there are in operations, coal supply, etc., the more predictable and less
variant the NO* emissions are.
4. For each technology expected value, there is a corresponding potential for actualNO*
emissions to vary from this expected value. From the vendor information presented, along
with anticipated unit operational data, an adjustment to the expected value can be made.
Step 4: Evaluate lmpacts and Document the Results
This step involves the consideration of energy, environmental, and economic impacts
associated with each controltechnology. The remaining useful life of the plant is also
considered during the evaluation.
Energy lmpacts. Installation of LNBs and modification to the existing OFA systems are not
expected to significantly impact the boiler effrciency or forced-draft fan power usage.
Therefore, these technologies will not have energy impacts.
Exhibit No. 2
Case No. IPC-E-13-16 3-1o
T. Harvey, IPC
Page 25 of 96
JMS EY1 O2OO7OO1 SLC\BART_JB4-OCT2OO7-FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
The Mobotec ROFA system would require installation and operation of two 4,000 to
4,300 horsepower ROFA fans (6,410 kilowatts [kW] total). The SNCR system would require
approximately 530 kW of additional power.
SCR retrofit impacts the existing flue gas fan systems, due to the additional pressure drop
associated with the catalyst, which is typically a 6- to 8-inch water gage increase. Total
additional power requirements for SCR installation at Jim Bridger 4 are estimated at
approximately 3,360 kW, based on the S&L Study.
Environmental lmpacts. Mobotec has predicted that carbon monoxide (CO) emissions, and
unburned carbon in the ash, commonly referred to as loss on ignition (LOI), would be the same
or lower than previous levels for the ROFA system.
SNCR and SCR installation could impact the saleability and disposal of fly ash due to ammonia
levels, and could potentially create a visible stack plume, which may negate other visibility
improvements. Other environmental impacts involve the storage of ammonia, especially if
anhydrous ammonia is used, and the transportation of the ammonia to the power plant site.
Economic lmpacts. Costs and schedules for the LNBs, OFA, SNCR, and SCR were fumished to
CH2M HILL by PacifiCorp, developed using S&L's internal proprietary database, and
supplemented (as needed) by vendor-obtained price quotes. The relative accuracy ofthese cost
estimates is stated by S&L to be in the range of plus or minus 20 percent. Cost for the ROFA
system was obtained from Mobotec.
A comparison of the technologies on the basis of costs, design control efficiencies, and tons of
NO* removed is summarized in Table 3-3, and the first year control costs are presented in
Figure 3-4. The complete economic analysis is contained in Appendix A.
Preliminary BART Selection. CH2M HILL recommends selection of LNBs with OFA as BART
for Jim Bridger 4 based on its significant reduction in NO* emissions, reasonable control cost,
and no additional power requirements or environmental impacts. LNB with OFA does not meet
the EPA-presumptive limit of 0.15 lb per MMBtu for sub-bituminous coal, but it does meet an
emission rate that falls between the presumptive limit of 0.28 lb per MMBtu for bituminous
coal and the limit of 0.15 lb per MMBtu for sub-bituminous coal. As discussed in the section
on coal quality, the recommended technology and the achieved emission rate are deemed
appropriate as BART for NO* emissions from the coals combusted at Jim Bridger 4.
Step 5: Evaluate Visibility lmpacts
Please see Section 4, BART Modeling Analysis.
Exhibit No. 2
Case No.|PC-E-13-16
T. Harvey, IPC
Page 26 of 96
JMS EY1 O2OO70O1 SLC\BART-J B4_OCT20OT.FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
TABLE 3.3
NO, Control Cost Comparison
Jin Bridoer 4
Factor
Low NO,
Blower (LNB)
with Over-
Fire Air
(oFA)
Rotating
Opposed Fire
Air
LNB with
OFA&
Selective
Non-
Catalytic
Reduction
System
LNB with OFA
Selective
Catalytic
Reduction
System
Total lnstalled Capital Costs
Total First Year Fixed & Variable Operation
and Maintenance Costs
Total First Year Annualized Cost
Power Consumption (megawatts)
Annual Power Usage (1000 megawatt-hours
per year)
Nitrogen Oxides Design Control Efficiency
Nitrogen Oxides Removed per Year (Tons)
First Year Average Control Cost
($ per Ton of Nitrogen Oxides Removed)
lncremental Control Cost
($ per Ton of Nitrogen Oxides Removed)
$8.7 million
$0.'1 million
$0.9 million
0
0
46.7Yo
4,967
$181/ton
$'181/ton
$20.5 million
$2.6 million
$4.6 million
6.4
50.6
51.1o/o
5,440
$843/ton
$7,797lton
22.1 million
$1.5 million
$3.6 million
0.5
4.2
55.6%
5,913
$613/ton
$2,88S/ton
$147.6 million
$3.4 million
$17.4 million
3.4
26.5
84.4%o
8,987
$1,936/ton
$4,479/ton
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 27 of 96
JMS EYl O2OO7OO1 SLC\BART_JB4_OCT2OO7-FINAL,DOC 3-12
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Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 28 of 96
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BART ANALYSIS FOR JIM BRIDGER UNIT 4
3.2.2 BART SOz Analysis
Sulfur dioxide forms in the boiler during the combustion process, and is primarily dependent on
coal sulfur content. The BART analysis for SOz emissions on Jim Bridger 4 is described below.
Step 1: ldentify All Available Retrofit Control Technologies
A broad range of information sources were reviewed, in an effort to identifu potentially
applicable emission control technologies for SOz at Jim Bridger 4. This included control
technologies identified as BACT or LAER by permitting agencies across the United States.
The following potential SOz controltechnology options were considered:
o Optimize current operation of existing wet sodium FGD system. Upgrade wet sodium FGD system to meet SO2 emission rate of 0.10 lb per MMBtuo New dry FGD system
Step 2: Eliminate Technically lnfeasible Options
Technical feasibility will primarily be based on the regulatory presumptive limit (used as a
guideline) of 95 percent reduction in SOz emissions, or 0.15 lb per MMBtu. Based on the coal
that Jim Bridger 4 currently burns, the unit would be required to achieve an 87.5 percent SO2
removal efficiency to meet the presumptive limit of 0.15 lb per MMBtu.
Table 3-4 summarizes the control technology options evaluated in this BART analysis, along
with projected SOz emission rates. Only one technology option can meet the applicable
presumptive BART limit of 0.15 lb per MMBtu.
TABLE 34
SOz Control Technology Emission Rates
Jim Bridoer4
Technology Projected Emission Rate (pounds
per million British thermal units)
Presumptive Best Available Retrofit
Technology Limit
Upgrade Existing Wet Sodium System
Optimize Existing Wet Sodium System
New Dry Flue Gas Desulfurization
System
0.1 5
0.10
0.17
0.21
Wet Sodium FGD System Wet sodium FGD systems operate by treating the flue gas in large
scrubber vessels with a soda ash solution. The scrubber mixes the flue gas and alkaline reagent
using a series of spray nozzles to distribute the reagent across the scrubber vessel. The sodium
in the reagent reacts with the SOz in the flue gas to form sodium sulfite and sodium bisulfite,
which are removed from the scrubber and disposed.
The wet sodium FGD system at Jim Bridger 4 currently achieves approximately 86 percent SO2
removal to achieve an SOz outlet emission rate of 0.17 lb per MMBtu. Upgrading the wet FGD
system would achieve an SOz outlet emission rate of 0.10 lb per MMBtu (91.7 percent SOz
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 29 of 96
JMS EY.IO2OOTOO1SLC\BART_JB4-OCI2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
removal) by closing the bypass damper to eliminate routine bypass flue gas flow used to reheat
the treated flue gas from the scrubber, relocating the opacity monitor, adding new fans, adding
a stack liner and drains for wet operation, and using a refined soda ash reagent. It is considered
to be technically infeasible for the present wet FGD system to achieve 95 percent SO2 removal
(0.06 lb per MMBtu) on a continuous basis since this high level of removal must be
incorporated into the original design of the scrubber.
The wet FGD system is achieving an outlet SOz emission rate of 0.17 lb per MMBtu. It is not
expected that any significant additional SOz reduction would occur with optimization of the
wet sodium scrubbing FGD system. This option would not meet the presumptive limit of
0.15 lb per MMBtu. Therefore, this option is eliminated as technically infeasible for this
analysis. An upgraded wet sodium scrubbing FGD system is projected to achieve an outlet
emission rate of 0.10 lb per MMBtu (91.7 percent SOz removal), which would meet the
presumptive limit of 0.15 lb per MMBtu for Jim Bridger 4.
New Dry FGD System. The lime spray dryer typically injects lime slurry in the top of the
absorber vessel with a rapidly rotating atom\zer wheel. The rapid speed of the atomizer wheel
causes the lime slurry to separate into very fine droplets that intermix with the flue gas. The
SOz in the flue gas reacts with the calcium in the lime slurry to form dry calcium sulfate
particles. At Jim Bridger 4 this dry particulate matter would be captured downstream in the
existing ESP, along with the fly ash. A lime spray dryer system typically produces a dry waste
product suitable for landfill disposal.
The dry FGD system with the existing ESP is projected to achieve 82.5 percent SOz removal at
Jim Bridger 4. This would result in a controlled SOz emission rate of 0.21 lb per MMBtu, based
on an uncontrolled SO2 emission rate of 1.20 lb per MMBtu. Therefore, this option cannot meet
the presumptive limit of 0.15 lb per MMBtu, and is eliminated from further analysis as
technically infeasible.
Step 3: Evaluate Control Effectiveness of Remaining Control Technologies
When evaluating the control effectiveness of SOz reduction technologies, each option can be
compared against benchmarks of performance. One such benchmark is the presumptive BART
emission limit because Jim Bridger 4 is required to meet this limit. As indicated previously, the
presumptive limit for SOz on a BART-eligible coal burning unit is 95 percent removal, or
0.15 lb per MMBtu.
The projected emission rate for an upgraded wet sodium FGD system for Jim Bridger 4 would
be 0.10 lb per MMBtu. This option would meet the presumptive SOz limit of 0.15 lb per
MMBtu.
Step 4: Evaluate lmpacts and Document the Results
This step involves the consideration of energy, environmental, and economic impacts
associated with each control technology. The remaining useful life ofthe plant is also
considered during the evaluation.
Energy lmpacts. Upgrading the existing wet sodium FGD system would require an additional
520 kW ofpower.
Exhibit No. 2
Case No. lPc-E-13-16 31s
T. Harvey, IPC
Page 30 of 96
JMS EYlO2OOTOO1SLC\BART JB4 OCT2OOT FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
Environmental lmpacts. There will be incremental additions to scrubber waste disposal and
makeup water requirements.
Economic lmpacts. A summary of the costs and amount of SOz removed for the upgraded wet
sodium FGD system is provided in Table 3-5. The complete economic analysis is contained in
Appendix A.
TABLE 3.5
Sulfur Dioxide Control Cost Comparison (lncrementalto Existing Flue Gas Desulfurization System)
Jin Bddoer4
Factor Upgraded Wet Flue Gas DesuJfurization
Total lnstalled Capital Costs
Total First Year Fixed & Variable O&M Costs
Total First Year Annualized Cost
Additional Power Consumption (megawatts)
Additional Annual Power Usage (1000 megawatt-
hours per year)
lncremental Sulfur Dioxide Design Control Efficiency
lncremental Tons Sulfur Dioxide Removed per Year
First Year Average Control Cost ($ per Ton of Sulfur
Dioxide Removed)
lncremental Control Cost
($ per Ton of Sulfur Dioxide Removed)
$5.8 Million
$0.7 Million
$1.2 Million
0.5
4.2
40.1Yo (91.7Yo based on
Uncontrolled Sulfur Dioxide)
1,585
761
761
Preliminary BART Selection. CH2M HILL recommends upgrading the existing wet sodium FGD
system as BART for Jim Bridger 4 based on its significant reduction in SOz emissions (meeting
presumptive limit of 0.15 lb per MMBtu), reasonable control costs, and the advantages of
minimal additional power requirements, and environmental impacts.
Step 5: Evaluate Visibility lmpacts
Please see Section 4, BART Modeling Analysis.
3.2.3 BART PMro Analysis
Jim Bridger 4 is currently equipped with an ESP. ESPs remove particulate matter from the flue
gas stream by charging fly ash particles with a very high direct current voltage, and attracting
these charged particles to grounded collection plates. A layer of collected particulate matter
forms on the collecting plates and is removed by periodically rapping the plates. The collected
ash particles drop into hoppers below the precipitator and are removed periodically by the fly
ash-handling system. Historically, the ESP at Jim Bridger 4 has controlled PMro emissions to
levels below 0.030 lb per MMBtu.
The BART analysis for PMro emissions at Jim Bridger 4 is described below. For the modeling
analysis in Section 4, PMro was used as an indicator for particulate maffer, and PMro includes
PMzs as a subset.
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 31 of96
JMS EY1 O2OO7OO1 SLC\BART_JM_OCT2OO7-FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
Step 1: ldentify All Available Retrofit Contro! Technologies
Two retrofit control technologies have been identified for additional particulate matter control:
. Flue gas conditioning (FGC). Polishing fabric filter (baghouse) downstream of existing ESP
Another available control technology is replacing the existing ESP with a new fabric frlter.
However, because the environmental benefits that would be achieved by a replacement fabric
filter are also achieved by installing a polishing fabric filter downstream of the existing ESP at
lower costs, installation of a full fabric filter was not considered in the analysis.
Step 2: Eliminate Technically lnfeasible Options
Flue Gas Conditioning. If the fly ash from coal has high resistivity, such as fly ash from
sub-bituminous coal, the ash is not collected effectively in an ESP. This is because the high
resistivity makes the particles less willing to accept an electrical charge. Adding FGC, which is
typically accomplished by injection of sulfur trioxide (SO:), will lower the resistivity of the
particles so that they will accept more charge and allow the ESP to collect the ash more
effectively. FGC systems can account for large improvements in collection efficiency for small
ESPs.
Polishing Fabric Filter. A polishing fabric filter could be added downstream of the existing ESP
at Jim Bridger 4. One such technology is licensed by the Electric Power Research Institute, and
referred to as a Compact Hybrid Particulate Collector (COHPAC). The COHPAC collects the
ash that is not collected by the ESP, thus acting as a polishing device. The ESP needs to be kept
in service for the COHPAC fabric filter to operate effectively.
The COHPAC fabric filter is about one-half to two-thirds the size of a full size fabric filter,
because the COHPAC has a higher air-to-cloth ratio (7 to 9:l), compared to a full size pulse jet
fabric filter (3.5 to 4.1).
Step 3: Evaluate Control Effectiveness of Remaining ControlTechnologies
The existing ESP at Jim Bridger 4 is achieving a controlled particulate matter emission rate of
0.030 lb per MMBtu. Using FGC upstream of the existing ESP is projected to not reduce
particulate matter emissions, but it would help maintain long term operation at an emission
level of 0.030 lb per MMBtu. Adding a COHPAC fabric filter downstream of the existing ESP
is projected to reduce particulate matter emissions to approximately 0.015 lb per MMBtu.
The PMl6controltechnology emission rates are summarized in Table 3-6.
TABLE }6
PMro Control Technology Emission Rates
Jim Bridoer4
Control Technology Short-Term Expected PMro
Emission Rate (pounds per
million British therma! units)
Flue Gas Conditioning
Polishing Fabric Filter
0.030
0.015
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 32 of 96
JMS EY1 O2OO7OO1 SLC\BART-J B4-OCT20O7-FINAL.DOC
EART ANALYSIS FOR JIM BRIDGER UNIT 4
Step 4: Evaluate lmpacts and Document the Results
This step involves the consideration of energy, environmental, and economic impacts
associated with each control technology. The remaining useful life ofthe plant is also
considered during the evaluation.
Energy lmpacts. Energy is required to overcome the additional pressure drop from the
COHPAC fabric filter and associated ductwork. Therefore, a COHPAC retrofit will require an
induced draft (ID) fan upgrade and upgrade of the auxiliary power supply system. A COHPAC
fabric filter at Jim Bridger 4 would require approximately 3.4 MW of power, equating to an
annual power usage of approximately 26.7 million kilowatt-hours (kW-Hr). There is only a
small power requirement of approximately 50 kW associated with FGC.
Environmental lmpacts. There are no negative environmental impacts from the addition of a
COHPAC polishing fabric filter or flue gas conditioning system.
Economic lmpacts. A summary of the costs and particulate matter removed for COHPAC and
FGCs are recorded in Table 3-7, and the first-year control costs for FGC and fabric filters are
shown in Figure 3-5. The complete economic analysis is contained in Appendix A.
TABLE 3.7
PMro Control Cost Comparison (lncrementalto Existing ESP)
Jim Bidoer 4
Flue Gas
Conditioning Polishing Fabric FilterFactor
Total lnstalled Capital Costs
Total First Year Fixed & Variable O&M Costs
Total First Year Annualized Cost
Additional Power Consumption (megawatts)
Additional Annual Power Usage (Million kilowatt-hours per
year)
lncremental Particulate Matter Design Control Efficiency
lncremental Tons Particulate Matter Removed per Year
First Year Average Control Cost
($ per Ton of Particulate Matter Removed)
lncremental Control Cost
($ per Ton of Particulate Matter Removed)
$0
$0.2 million
$0.2 million
0.05
0.4
0.0%
0
N/A
N/A
$48.4 million
$1.8 million
$ 6.4 million
3.39
26.7
s0.0%
355
17,946
17,452
Preliminary BART Selection. CH2M HILL recommends selection of FGC upstream of the
existing ESP as BART for Jim Bridger 4 based on the significant reduction in particulate matter
emissions, reasonable control costs, and advantages of minimal additional power requirements
and no environmental impacts.
Step 5: Evaluate Visibility lmpacts
Please see Section 4, BART Modeling Analysis.
Exhibit No- 2^ 3_18Case No. IPC-E-13-16
T. Harvey, IPC
Page 33 of 96
JMS EY1 O2OOTOOlSLC\BART.JB4-OCT2OO7_FINAL.DOC
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Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 34 of 96
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4.2
4.1 Model Selection
CH2M HILL used the CALPUFF modeling system to assess the visibility impacts of emissions
from Jim Bridger 4 at nearby Class I areas. The Class I areas potentially affected are located
more than 50 kilometers but less than 300 kilometers from the Jim Bridger 4 facility. The
Class I areas include the following wilderness areas:
o Bridger Wildemess Areao Fitzpatrick Wilderness Areao Mt. Zirkel Wilderness Area
The CALPUFF modeling system includes the CALMET meteorological model, a Gaussian
puff dispersion model (CALPUFF) with algorithms for chemical transformation and
deposition, and a post processor capable of calculating concentrations, visibility impacts, and
deposition (CALPOST). The CALPUFF modeling system was applied in a full, refined mode.
The following version numbers of the various programs in the CALPUFF system were used by
CH2M HILL:
o CALMET Version 5.53a, Level040716o CALPUFF Version 5.7lla, Level0407l6o CALPOST Version 5.51, Level 030709
CALMET Methodology
4.2.1 Dimensions of the Modeling Domain
CH2M HILL used the CALMET model to generate a three-dimensional wind field and other
meteorological parameters suitable for use by the CALPUFF model. A modeling domain was
established to encompass the Jim Bridger 4 facility and allow for a 50-km buffer around the
Class I areas that were within 300 km of the facility. Grid resolution was 4 km. Figure 4-l
shows the extent of the modeling domain. Except when specifically instructed otherwise by the
Wyoming Department of Environmental Quality-Air Quality Division (WDEQ-AQD),
CH2M HILL followed the methodology spelled out in the WDEQ-AQD BART Modeling
Protocol, a copy of which is included in this report as Appendix B.
CH2M HILL used the Lambert Conformal Conic map projection for the analysis due to the
large extent of the domain. The latitude of the projection origin and the longitude of the central
meridian were chosen at the approximate center of the domain. Standard parallels were drawn
to represent one-sixth and five-sixths of the north-south extent of the domain to.minimize
distortion in the north-south direction.
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 35 of 96
JMS EY1 O2OO7OO,I SLC\BART-JB4-OCT2OO7-FINAL.DOC
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Page 36 of 96
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The default technical options listed in TRC Companies, Inc.'s (TRC) current example
CALMET.inp file were used for CALMET. Vertical resolution of the wind field included ten
layers, with vertical face heights as follows (in meters):
. 0,20,40, 1 00, 140, 320,580, 1 020, 1480,2220, 3500
Other user-specified model options were set to values established by WDEQ-AQD, which
appear in Table 3 of Appendix B. Table 4-l lists the key user-specified options used for this
analysis.
TABLE +1
User-specifi ed CALMET Opttons
Jin Bidoer4
CALMET lnput Parameter
CALMET lnput Group 2
Map projection (PMAP)
Grid spacing (DGRIDKM)
Number vertical layers (NZ)
Top of lowest layer (m)
Top of highest layer (m)
CALMET lnput Group 4
Observation mode (NOOBS)
CALMET lnput Group 5
Prog. Wind data (IPROG)
(RMAX1)
(RMM2)
Tenain influence (TERRAD)
(R1)
(R2)
CALMET lnput Group 6
Max mixing ht (ZIMAX)
Lambert Conformal
4
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3500
14
30
50
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4.2.2 CALMET lnput Data
CH2M HILL ran the CALMET model to produce 3 years of analysis: 2001,2002, and 2003.
WDEQ-AQD provided l2-km resolution Mesoscale Meteorological Model, Version 5 (MM5)
meteorological data fields that covered the entire modeling domain for each study year.
These three data sets were chosen because they are current and have been evaluated for quality.
The MM5 data were used as input to CALMET as the "initial guess" wind field. The initial
guess wind field was adjusted by CALMET for local terrain and land use effects to generate a
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 37 of 96
JMS EYlO2OOTOOlSLC\BART JB4-OCI2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
Step I wind field, and further refined using local surface observations to create a final Step 2
wind field.
Surface data for 2001 through 2003 were obtained from the National Climatic Data Center.
CH2M HILL processed the data from the National Weather Service's Automated Surface
Observing System (ASOS) network for all stations that are in the domain. The surface data
were obtained in abbreviated DATSAV3 format. A conversion routine available from the
TRC Web site was used to convert the DATSAV3 files to CD-144 format for input into the
SMERGE preprocessor and CALMET.
Land use and terrain data were obtained from the U.S. Geological Survey (USGS). Land use
data were obtained in Composite Theme Grid format from the USGS, and the Level I USGS
land use categories were mapped into the l4 primary CALMET land use categories. Surface
properties such as albedo, Bowen ratio, roughness length, and leaf area index were computed
from the land use values. Terrain data were taken from USGS l-degree Digital Elevation
Model data, which primarily derive from USGS l:250,000 scale topographic maps. Missing
land use data were filled with values that were assumed appropriate for the missing area.
Precipitation data were obtained from the National Climatic Data Center. All available data in
fixed-length,TD-3240 format were obtained for the modeling domain. The list of available
stations that have collected complete data varies by year, but CH2M HILL processed all
available stations/data within the domain for each year. Precipitation data were prepared with
the PXTRACT/PMERGE processors in preparation for use within CALMET.
Upper-air data were prepared for the CALMET model with the READ62 preprocessor for the
following stations:
o Denver, Coloradoo Salt Lake City, Utaho Riverton, Wyoming. Rapid City, South Dakota
Figure 4-2 shows the locations of surface and upper air stations within the MM5 modeling
domain.
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 38 of 96
JMS EY1 O2OO7OO1 SLC\BART-JB4-OCT2OO7-FINAL.DOC
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Page 39 of 96
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4.2.3 Validation of GALMET Wind Field
CH2M HILL used the CALDESK data display and analysis system (v2.97, Enviromodeling
Ltd.) to view plots of wind vectors and other meteorological parameters to evaluate the
CALMET wind fields. The CALDESK displays were compared to observed weather
conditions, as depicted in surface and upper-air weather maps (National Oceanic and
Atmospheric Administration, 2006).
4.3 CALPUFF Modeling Approach
For the BART control technology visibility improvement modeling, CH2M HILL followed
WDEQ-AQD guidance provided in the document titled BART Air Modeling
Protocol-Individual Source Visibility Assessments for BART Control Analyses (September,
2006).
CH2M HILL drove the CALPUFF model with the meteorological output from CALMET
over the modeling domain described earlier. The CALPUFF model was used to predict
visibility impacts for the pre-control (baseline) scenario for comparison to the predicted
impacts for post-control scenarios for Jim Bridger 4.
4.3.1 Background Ozone and Ammonia
Hourly values of background ozone concentrations were used by CALPUFF for the
calculation of SOz and NO. transformation with the MESOPUFF II chemical transformation
scheme. CH2M HILL obtained hourly ozone data from the following stations located within
the modeling domain for 2001, 2002, and2003:
o Rocky Mountain National Park, Coloradoo Craters of the Moon National Park, Idahoo Highland, Utaho Thunder Basin National Grasslands, Wyomingo Yellowstone National Park, Wyomingo Centennial, Wyomingo Pinedale, Wyoming
For periods of missing hourly ozone data, the chemical transformation relied on a monthly
default value of 44 parts per billion. Background ammonia was set to 2 parts per billion. Both
of these background values were taken from the guidance document (WDEQ-AQD, 2006).
4.3.2 Stack Parameters
The stack parameters used for the baseline modeling reflect those that are in place under the
current permit for Jim Bridger 4. Post-control stack parameters reflect the anticipated
changes associated with installation of the control technology altematives that are being
evaluated. The maximum heat input rate of 6,000 MMBtu per hour was used to calculate a
maximum emission rate. Measured velocities and stack flow rates were used in the modeling
to represent a worst-case situation.
Exhibit No. 2
Case No. IPC-E-13-16 4-6
T. Harvey, IPC
Page 40 of 96
JMS EY1 O2OO7OO1 SLC\BART-JB4-OCT2OO7_FINAL,DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
4.3.3 Emission Rates
Pre-control emission rates for Dave Johnston 3 reflect peak 24-hour average emissions that
may occur under the source's current permit. The emission rates reflect actual emissions
under normal operating conditions, as described by the EPA in the Regional Haze
Regulations and Guidelines for Best Available Retrofit Technologt Determinations; Final
Rule (40 CFR Part 5l).
CH2M HILL used available continuous emission monitoring data to determine peak 24-hour
emission rates. Data reflected operations from the most recent 3- to 5-year period, unless a
more recent period was more representative. Allowable short-term (24-hour or shorter
period) emissions or short-term emission limits were used if continuous emission monitoring
data were not available.
Emissions were modeled for the following pollutants:
. SOz. NO*. Coarse particulate (PM2 5<diameter<PMls). Fine particulate (diameter<PM2 5). Sulfates
Post-control emission rates reflect the effects of the emissions control scenario under
consideration. Modeled pollutants were the same as those listed for the pre-control scenario.
4.3.4 Post-control Scenarios
Four post-control modeling scenarios were developed to cover the range of effectiveness for
the combination of the individual NO*, SO2, and PM control technologies being evaluated.
The selection of each control device was made based on the engineering analyses performed
in Section 3 for reasonable technologies that would meet or exceed the presumptive BART
levels for each pollutant.
. Scenario 1: New LNB with OFA Modifications, upgraded wet FGD system and FGC for
enhanced ESP performance. As indicated previously, this scenario represents
CH2M HILL's preliminary BART recommendation.
. Scenario 2: New LNB with OFA modifications, upgraded wet FGD system and new
polishing fabric filter
. Scenario 3: New LNB with OFA modifications and SCR, upgraded wet FGD system and
FGC for enhanced ESP performance.
. Scenario 4: New LNB with OFA modifications and SCR, upgraded wet FGD system and
new polishing fabric filter.
The ROFA option and LNB with OFA and SCR option for NO* control were not included in
the modeling scenarios because their control effectiveness is between the LNB with OFA
option and the SCR option. Modeling of NO*, SOz, and particulate matter controls alone was
not performed because any final BART solution will include a combination of control
technologies for NO*, SOz, and particulate matter.
Exhibit No..1 _ __ .^ 4_tCase No. IPC-E-13-16
T. Harvey, IPC
Page41 of96
JMS EYlO2OOTOOlSLC\BART_JB4.OCT2OO7-FINAL,DOC
BqRT ANALYSIS FOR JIM BRIDGER UNIT 4
Table 4-2 presents the stack parameters and emission rates used for the Jim Bridger 4
analysis for baseline and post-control modeling. In accordance with the WDEQ BART
modeling protocol, elemental carbon stack emissions and organic aerosol emissions were not
modeled.
4.3.5 Modeling Process
The CALPUFF modeling for the control technology options for Jim Bridger 4 followed this
sequence:
. Model pre-control (baseline) emissions. Model preferred post-control scenario (if applicable). Determine degree of visibility improvement. Model other control scenarios. Determine degree of visibility improvement. Factor visibility results into the BART "five-step" evaluation
4.3.6 Receptor Grids
Discrete receptors for the CALPUFF modeling were placed at uniform receptor spacing
along the boundary and in the interior of each area of concem. Class I area receptors were
taken from the National Park Service database for Class I area modeling receptors. The TRC
COORDS program was used to convert all latitude/longitude coordinates to Lambert
Conformal Conic coordinates, including receptors, meteorological stations, and source
locations.
Exhibit No. 2c""" r,r" tpt-E-te-to +8
T. Harvey, IPC
Page 42 of 96
JMS EY1 O2OO7OO1 SLC\BART-JB4-OCT2OO7-FINAL,DOC
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BART ANALYSIS FOR J!M BRIDGER UNIT 4
4.4 CALPOST
The CALPOST processor was used to determine 24-hour average visibility results with
output specified in deciview (dV) units. Calculations of light extinction were made for each
pollutant modeled. The sum of all extinction values were used to calculate the
delta-dV (AdV) change relative to natural background. Default light extinction coefficients
for each pollutant, as follows, were used.
. Ammonium sulfate. Ammonium nitrate. Particulate matter coarse (PMro). Particulate matter fine (PMzs). Organic carbon. Elementalcarbon
3.0
3.0
0.6
1.0
4.0
10.0
CALPOST Visibility Method 6 was used to determine the visibility impacts. Monthly
relative humidity factors t/(RH)] were used in the light extinction calculations to account for
the hygroscopic characteristics of nitrate and sulfate particles. Table 5 of the Wyoming
BART Air Modeling Protocol (Appendix B) lists the monthly,f(RH) factors for the Class I
areas. These values were used for the particular Class I area being modeled.
The natural background conditions as a reference for determining the delta-dV (AdV) change
represented the 20 percent best natural visibility days. The EPA BART guidance document
provided dV values for the I 0 percent best days for each Class I area, but did not provide
individual species concentration data for the 20 percent best background conditions. Species
concentrations corresponding to the 20 percent best days were calculated for each Class I
area by scaling back the annual average species concentrations given in Table 2-l of
Guidance for Estimating Natural Yisibility Conditions Under the Regional Haze Rule (EPA,
2003). A separate scaling factor was derived for each Class I area such that, when multiplied
by the guidance table annual concentrations, the 20 percent best days dV value for that area
would be calculated. This procedure was taken from Protocolfor BART-Related Visibility
Improvement Modeling Analysis in North Dakota (North Dakota Department of Health,
2005). However, the Wyoming BART Air Modeling Protocol (see Appendix B) provided
natural background concentrations of aerosol components to use in the BART analysis.
Table 4-3 lists the annual average species concentrations from the BART protocol.
Exhibit No. 2
c""" r.r" lpt-e-tg-to +10
T. Harvey, IPC
Page 44 of 96
JMS EYlO2OOTOOlSLC\BART JB4-OCT2OO7 FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
TABLE +3
Average Natural Levels ofAerosol Components
Jin Bridoer4
Aerosol Component
Average Natura! Concentration
(micrograms per cubic meter)
for Mt Zirkel Class I
Wilderness Area
Average Natural Goncentration
(micrograms per cubic meter)
for FiEpatrick and Bridger Glass I
Wilderness Areas
Ammonium Sulfate
Ammonium Nitrate
Organic Carbon
Elemental Carbon
Soil
Coarse Mass
0.046
0.038
0.179
0.008
0.190
1.141
0.045
0.038
0.178
0.008
0.189
1.136
NOTE:
Source: Table 6 of the Wyoming BART Air Modeling Protocol
4.5 Presentation of Modeling Results
This section presents the results of the CALPUFF visibility improvement modeling analysis
for Jim Bridger 4.
4.5.1 Visibility Changes for Baseline vs. Preferred Scenario
CH2M HILL modeled Jim Bridger 4 for the baseline conditions and four post-control
scenarios. The post-control scenarios included emission rates for NO*, SOz, and PMro that
would be achieved if BART technology were installed on Unit 4.
Baseline (and post-control) 98tr percentile results were greater than 0.5 AdV for the Bridger,
Fitzpatrick, and Mt. Zirkel Wilderness Areas. The 98h percentile results for each Class I area
are presented in Table 4-4.
ExhibitNo-1_ -^.^4_11Case No. IPC-E-I3-16 '
T. Harvey, IPC
Page 45 of 96
JMS EY1O2OO7OO1 SLC\BART JB4_OCT2OO7_FINAL.DOC
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Page 46 of 96
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T. Harey, IPC
Page 47 of 96
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5.1
5.0 Preliminary Assessment and
Recommendations
As a result of the completed technical and economic evaluations, and consideration of the
modeling analysis for Jim Bridger 4, the preliminary recommended BART controls for NO*,
SOz, and PM16 are as follows:
. New LNBs and modifications to the OFA system for NO* control. Upgrade wet sodium FGD for SOz control. Add flue gas conditioning upstream of existing ESPs for PM control
These recommendations were identified as Scenario I for the modeling analysis described in
Section 4. Visibility improvements for all emission control scenarios were analyzed, and the
results are compared below, utilizing a least-cost envelope, as outlined inthe New Source
Review Workshop Manual (EPA, 1990, hereafter referred to as NSR Manual).
Least-cost Envelope Analysis
For the control scenarios modeled in Section 4, Tables 5-l through 5-3 list the total
annualized cost, cost per dV reduction, and cost per reduction in number ofdays above
0.5 dV for each of the three Class I areas. A comparison of the incremental results between
selected scenarios is provided in Tables 5-4 through 5-6. Figures 5-l to 5-6 show the total
annualized cost versus number of days above 0.5 dV, and the total annualized cost versus
98ft percentile AdV reduction, for the three Class I areas.
5.1.1 AnalysisMethodology
On page B-41 of the New Source Review (NSR) Manual, EPA states that "lncremental
cost-effectiveness comparisons should focus on annualized cost and emission reduction
differences between dominant alternatives. Dominant set of control alternatives are
determined by generating what is called the envelope of least-cost alternatives. This is a
graphical plot of total annualized costs for a total emissions reductions for all control
alternatives identified in the BACT analysis..."
An analysis of incremental cost effectiveness has been conducted. This analysis was
performed in the following way. First, the control option scenarios are ranked in ascending
order of annualized total costs, as shown in Tables 5-l through 5-3. The incremental cost
effectiveness data, expressed per day and per dV, represents a comparison of the different
scenarios, and is summarized in Tables 5-4 through 5-6 for each of the three wilderness
areas. Then the most reasonable smooth curve of least-cost control option scenarios is plotted
for each analysis. Figures 5-l through 5-6 present the two analyses (cost per dV reduction
and cost per reduction in number of days above 0.5 dV) for each of the three Class I areas
impacted by the operation of Jim Bridger 4.
Exhibit No. 2 -
Case No. IPC-E-13-16 '-'
T. Harvey, IPC
Page 48 of 96
JMS EY1 02OO7OO1 SLC\BART_JB4_OCT2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
In Figure 5-1, the four scenarios are compared as a graph of total annualized cost versus
number of days above 0.5 dV. The EPA states that'oln calculating incremental costs, the
analysis should only be conducted for control options that are dominant among all possible
options." In Figure 5-1, the dominant set of control options (Scenarios l, 3, and 4) represent
the least-cost envelope depicted by the curvilinear line connecting them. Scenario 2 is an
inferior option and should not be considered in the derivation of incremental cost
effectiveness. Scenario 2 represents inferior controls because Scenario I provides
approximately the same amount of visibility impact reduction for less cost than Scenario 2.
The incremental cost effectiveness is determined by the difference in total annual costs
between two contiguous scenarios divided by the difference in emissions reduction.
TABLE $1
Control Scenario Results for the Bridger Class I Wildemess Area
Jim Bridser Unit 4
Scenario Controls
ggth
Percentile
deciview
(dv)
Reduction
Reduction
in Average
Number of
Days
Above
0.5 dv
(days)
Total
Annualized
Cost
(mi!!ion$)
Cost per
dv
Reduction
(million$
per
dv
reduced)
Cost per
Reduction in
No. of Days
Above 0.5 dV
(million$ per
day reduced)
Base Current Operation with Wet
Flue Gas Desulfurization
(FGD), Electrostatic
Precipitator (ESP)
Low-NO. Burner (LNB) with
Over-Fire Air (OFA),
upgrade wet FGD and Flue
Gas Conditioning (FGC) for
enhanced ESP
performance
LNB with OFA, Upgrade
Wet FGD, new polishing
fabric filter
LNB with OFA and
Selective Catalytic
Reduction (SCR) System,
upgrade wet FGD and FGC
for enhanced ESP
performance
LNB with OFA and SCR,
upgrade wet FGD, new
polishing fabric filter
0.00
0.38
0.38
0.58
$o.o0.0
$2.17.3
$0.0 $0.0
$5.6 $0.3
7.3
12.0
$8.5
$18.6
$25.0
$22.1
$32.3
$19.9
$1.2
$1.6
$1.2201.25
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 49 of 96
JMS EY1 O2OO7OO1 SLC\BART_J B4.OCT2OO7-FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
TABLE 5.2
Control Scenario Results for he Fitzpatrick Class I Wildemess Area
Jim Bridser Unrt 4
Reduction
in Average Cost per Cost per98m Number of dv Reduction inPercentile Days Total Reduction No. of Daysdeciview Above Annualized (million$ Above 0.5 dV(dV) 0.5 dV Cost per dV (million$ per
Scenario Gontrols Reduction (days) (million$) reduced) Day reduced)
Base Current Operation with Wet Flue 0.00 0.0 $0.0 $0.0 $0.0
Gas Desuffurization (FGD),
Electrostatic Precipitator ( ESP)
1 Low-NO, Burner (LNB) with 0.19 5.0 $2.1 $1 1 .3 $0.4
Over-Fire Air (OFA), upgrade
wet FGD and Flue Gas
Conditioning (FGC) for
enhanced ESP performance
2 LNB with OFA, Upgrade Wet 0.19 5.0 $8.5 $44.4 $1.7
FGD, new polishing fabric filter
3 LNB with OFA and Selective 0.29 6.0 $18.6 $64.7 $3.1
Catalytic Reduction (SCR)
System, upgrade wet FGD and
FGC for enhanced ESP
performance
4 LNB with OFA and SCR, 0.29 6.7 $25.0 $8s.4 $3.7
upgrade wet FGD, new
polishing fabric filter
Exhibit No. 2 -c""" No. rpt-E-13-16 t3
T. Harvey, IPC
Page 50 of 96
JMS EY1 O2OO7OO1 SLC\BART_JB4_OCT2OO7_FINAt.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
TABLE $3
Control Scenario Results for the lvlt. Zirkel Class I Wildemess Area
Jin Bridger4
Scenario Gontrols
ggth
Percentile
declview
(dv)
Reduction
Reduction
in Average
Number of
Days
Above
0.5 dv
(days)
Tota!
Annualized
Cost
lmillion$)
Cost per
dv
Reduction
(million$
per dV
reduced)
Cost per
Reduction in
No. of Days
Above 0.5 dV
(mi!!ion$ per
Day reduced)
Current Operation with Wet Flue
Gas Desulfurization (FGD),
Electrostatic Precipitator ( ESP)
Low-NO, Burner (LNB) with
Over-Fire Air (OFA), upgrade
wet FGD and Flue Gas
Conditioning (FGC) for
enhanced ESP performance
LNB with OFA, Upgrade Wet
FGD, new polishing fabric filter
LNB with OFA and Selective
Catalytic Reduction (SCR)
System, upgrade wet FGD and
FGC for enhanced ESP
performance
LNB with OFA and SCR,
upgrade wet FGD, new
polishing fabric filter
0.00
0.51
0.52
0.81
0.82
0.0
11.7
12.3
22.7
23.3
$o.o
$2.1
$8.5
$18.6
$o.o
$4.1
$16.2
$22.9
$o.o
$0.2
$0.7
$0.8
$1.1$2s.0 $30.4
TABLE S4
Bridger Class I Wildemess Area lncrementalAnalysis Data
Jim Bridoer Unit 4
Options Compared
lncremental
Reduction in
Days Above lncrcmental dV
0.5 deciview Reductions
(dV) (days) (dv)
lncremental
Cost-Effectiveness
(million$ per days)
lncremental
Cost-Effectiveness
(million$ per dV)
Baseline and Scenario 1
Scenario 1 and Scenario 2
Scenario 1 and Scenario 3
Scenario 1 and Scenario 4
7.3
0.0
4.7
12.7
0.38
0.01
0.20
0.88
$0.29
N/A
$3.5
$1.8
$5.61
$734.6
$81.s
$26.0
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 51 of96
JMS EY1O2OO7OO1 SLC\BART JB4 OCT2OOT_FINAL,DOC
BART ANALYSIS FOR JIM BRIOGER UNIT 4
TABLE $5
FiEpatrick Class I Wildemess Area lncrementalAnalysis Data
Jin Bridoer Unit4
Options Gompared
lncremental
Reduction in
Days Above
0.5 deciview
(dv) (days)
lncremental dV lncrementalReductions Cost-Effectiveness(dV) (million$ per days)
lncremental
Cost-Effectiveness
(million$ per dV)
Baseline and Scenario 1
Scenario 1 and Scenario 2
Scenario 1 and Scenario 3
Scenario 1 and Scenario 4
5.0
0.0
1.0
1.7
0.19
0.00
0.10
0.11
$0.42
NA
$16.5
$13.7
$45.s4
$1,364.3
$162.8
$215.0
TABLE $6
Mt. Zirkel Class I Wildemess Area lncrementalAnalysis Data
Jin Bridoer Unit4
Options Gompared
lncremental
Reduction in lncremental dV
Days Above Reductions
0.5 dV (days) (dv)
lncremental
Cost-Effectiveness
(million$/days)
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(million$ per dV)
Baseline and Scenario 't
Scenario 1 and Scenario 2
Scenario 1 and Scenario 3
Scenario 1 and Scenario 4
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Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 52 of 96
JMS EY102007001S1C\BART_JB4_OCT2007_FrNAL.00C
BART ANALYSIS FOR JIM BRIDGER UNIT 4
FIGURE 5.1
Least-cost Envelope Bddger Class I WA Days Reduction
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Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey,IPC
Page 53 of 96
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JMS EY1 O2OO7OO1 SLCtsART-JB4-OCTMOT.FINAL.DOC
98th Porcentllo Delta-Declvlew Roduction (dV)
BART ANALYSIS FOR JIM BRIDGER UNIT 4
FIGURE 5.3
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Exhibit No. 2 *,Case No. IPC-E-I3-16 -'
T. Harvey,lPC
Page 54 of 96
JMS EY1O2OO7OO1 SLC\BART.JB4_OCTMOT_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
F]GURE '5Least-cost Envelope Mt. Zirkel Class I WA Days Reduction
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Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey,IPC
Page 55 of 96
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JMS EYI 02007001 SLC\&{RT_JB4_0CT2007_FINAL.DOC
BART ANALYSIS FOR JIM BRIOGER UNIT 4
5,2
5.2.1
5.1.2 Analysis Results
Results of the least-cost analysis, shown in Tables 5-l through 5-6 and Figures 5-l through
5-6 on the preceding pages, confirm the selection of Scenario 1, based on incrementalcost
and visibility improvements. Scenario 2 is eliminated because it is to the left of the curve
formed by the "dominant" control alternative scenarios, which indicates a scenario with
lower improvement and/or higher costs. Scenario 3 is not selected due to very high
incremental costs for both a cost per day of improvement and a cost per dV reduction. While
Scenario 4 provides some potential visibility advantage over Scenario l, the projected
improvement is less than 0.5 dV, and the projected costs are excessive.
Analysis of the results for the Jim Bridger Class I Wilderness Area in Tables 5-l and 5-4 and
Figures 5-1 and 5-2 illustrates the conclusions stated above. The greatest reduction in
98ft percentile dV and number of days above 0.5 dV is between the Baseline and Scenario l.
The incremental cost effectiveness for Scenario I compared to the Baseline for the Bridger
Wilderness Area, for example, is reasonable at $290,000 per day and $5.6 million per dV.
However, the incremental cost effectiveness for Scenario 3 compared to Scenario 1, again for
the Bridger Wilderness Are4 is excessive at $3.5 Million per day and $81.9 million per dV.
The same conclusions are reached for each of the three wilderness areas studied. Therefore,
Scenario I represents BART for Jim Bridger 4.
Recommendations
NO, Emission Control
The BART presumptive NO* limit assigned by EPA for tangentially-fired boilers burning
sub-bituminous coal is 0.15 lb per MMBtu. However, as documented in Section 3.2.1, the
characteristics of the Jim Bridger coals are more closely aligned with bituminous coals, and
have been assigned a presumptive BART NO* limit of 0.28 lb per MMBtu.
CH2M HILL recommends LNBs with OFA as BART for Jim Bridger 4, based on the
projected significant reduction in NO* emissions, reasonable control costs, and the
advantages of no additional power requirements or non-air quality environmental impacts.
NO* reductions are expected to be similar to those realized at Jim Bridger 2. CH2M HILL
recommends that the unit be permitted at a rate of 0.26 lb per MMBtu.
5.2.2 SOz Emission Control
CH2M HILL recommends upgrading the existing wet sodium FGD system as BART for
Jim Bridger 4, based on the significant reduction in SO2 emissions, reasonable control costs,
and the advantages of minimal additional power requirements and minimal non-air quality
environmental impacts. This upgrade approach will meet the BART presumptive SOz limit of
0.15 lb per MMBtu.
5.2.3 PMro Emission Control
CH2M HILL recommends finalizing the permitting of the FGC system to enhance the
performance of the existing ESP as BART for Jim Bridger 4, based on the significant
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 56 of 96
JMS EY1O2OO7OO1 SLC\BART JB4_OCI2OO7_FINAL.DOC
BART ANALYSIS FOR JIM BRIDGER UNIT 4
reduction in PMro emissions, reasonable control costs, and the advantages of minimal
additional power requirements and no non-air quality environmental impacts.
5.3 Just-Noticeable Differences in Atmospheric Haze
Conclusions reached in the reference document "Just-Noticeable Differences in Atmospheric
Haze" by Dr. Ronald Henry of the University of Southern California (Henry, 2002), state that
only dV differences of approximately 1.5 to 2.0 dV, or more are perceptible by the human
eye. Deciview changes of less than 1.5 cannot be distinguished by the average person.
Therefore, the modeling analysis results indicate that only minimal, if any, observable
visibility improvements at the Class I areas studied would be expected under any of the
scenarios. Thus the results indicate that even though many millions of dollars will be spent,
only minimal if any visibility improvements may result.
Finally, it should be noted that none of the data were corrected for natural obscuration. Water
in various forms (fog, clouds, snow, or rain) or other naturally caused aerosols may obscure
the atmosphere and reduce visibility. During the period of 2001 through 2003, there were
several mega-wildfires that lasted for many days, with a significant impact on background
visibility in these Class I areas. If natural obscuration lessens the achievable reduction in
visibility impacts modeled for BART controls at the Jim Bridger 4 facility, the overall effect
would be to increase the costs per dV reduction that are presented in this report.
Exhibit No- 1 _ .^ .^ s_roCase No. IPC-E-13-16 -'
T. Harvey, IPC
Page 57 of 96
JMS EYlO2OOTOO1SLC\BART JB4-OCT2OO7_FINAL,DOC
6.0 References
40 CFR Part 5l . Regional Haze Regulations and Guidelines for Best Available Retrofit
Technologt Determinations; Final Rule. July 6,2005.
Energy Information Administration, 2006. Official Energt Statistics from the U.S.
Govemrnent: Coal. http://www.eia.doe.eov/fuelcoal.html. Accessed October 2006.
EPA, 1990. New Source Review Worl<shop Manual-Prevention of Significant Deterioration
and Nonattainment Area Perrnitting. Draft. October 1990.
EPA, 2003. Guidancefor Estimating Natural Visibility Conditions Under the Regional Haze
Rule. Environmental Protection Agency. EPA-454/8-03-005. September 2003.
Henry, Ronald, 2002. "Just-Noticeable Differences in AtmosphericHaze," Journal of the Air
& ll'aste Management Association. Volume 52, p. 1238.
National Oceanic and Atmospheric Administration, 2006. U.S. Daily Weather Maps Project.
http://docs.lib.noaa.eov/rescue/dwn/data_rescue daily weather maps.html.
Accessed October 2006.
North Dakota Department of Health, 2005. Protocolfor BART-Related Visibility
Improvement Modeling Analysis in North Dakota. North Dakota Department of
Health. October 26, 2005.
Sargent & Lundy, 2002. Multi-Pollutant Control Report. October 2002.
Sargent & Lundy, 2006. Multi-Pollutant Control Reporr. Revised. October 2006.
WDEQ-AQD, 2006. BART Air Modeling Protocol-Individual Source Visibility Assessments
for BART Control Analyses. Wyoming Department of Environmental Quality - Air
Quality Division. September 2006.
Exhibit No. 2 61
Case No. IPC-E-13-16
T. Harvey, IPC
Page 58 of 96
JMS EYlO2OOTOOlSLC\BART_JB4_OCTMOT-FINAt.DOC
APPEI\DD(A
Economic Ana
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 59 of 96
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Case No. IPC-E-13-16
T. Harvey, IPC
Page 74 of 96
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Case No IPC-E-13-16
T. Harvey, IPC
Page 75 of96
($) afl] luPld rea^ Jo^O lsoC r{UoM luaserd
BART Protocol
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 76 of 96
BART Air Modeling Protocol
Individual Source Visibility Assessments
for BART Control Analyses
September,2006
State of Wyoming
Department of Environmental Quality
Air Quality Division
Cheyenne, WY 82002
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 77 of 96
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Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey,lPC 2
Page 78 of 96
1.0 INTRODUCTION
The U.S. EPA has issued final asrendments to the Regional Haze Regulations,
along with Guidelines for Best Available Rerofit Technology (BART) Determinations.(t)
The guidelines address the methodology for determining which facilities must apply
BART (souroes subject-to-BART) and the evaluation of control options.
The State of Wyoming used air quality modeling in accordance with the EPA
Guidelines to determine the Wyoming sources which are subject-to-BART. This
Protocol defines the specific methodology to be used by those sources for determining
the improvement in visibility to be achieved by BART controls.
The methodology presented in this Protocol is consistent with EPA guidance and
the Air QualiU Division (AQD) determination of subject-to-BART sources. It is
intended that all Wyoming sources that must conduct BART analyses will use this
Protocol for their evaluation of conhol tecbnology visibility improvement. Any
deviations &om the procedures described herein must be approved by the Division prior
to implementation.
(r) 40 CTR Part 5l: Regional Haze Regulations and Guidelines for Best Available Retrofit Techaology
(BART) Determinations; Final Rule. 70 Federal Register, 39103-39172, July 6, 2005.
Exhibit No. 2
Case No. IPC-E-13-'16 ^T. Harvey, IPC 5
Page 79 of 96
o
2.0 ovERvtEw
Wyoming AQD determined that eight facilities (sources) in the state are subject-
to-BART. The sources are listed in Table 1. Division modeling indicated that each of
these sources causes or conkibutes to visibility impairment in one or more Class I areas.
Each source must conduct a BART analysis to define Best Available Retrofit Technology
(BART) applicable to that source, and quantify the improvement in Class I visibility
associated with BART controls. This Protocol sets out the procedures for quantifying
visibilityimprovement. Other aspects of the full BART analysis are not addressed here.
There are many Class I areas within and surrounding V/yoming (See Figure 1).
On the basis of distance from subject-to-BART sources, topography, meteorology, and
prior modeling, the AQD has determined that only five Class I areas need be addressed in
BART individual source analyses. These are Badlands and Wind Cave National Parks in
South Dakota Mt. Zirkel Wilderness Area in Colorado, and Bridger and Fitzpatrick
Wildemess Areas in Wyoming. Sotuces in eastem Wyoming have been shown to have
greatest visibility impacts at the two South Dakota Class I areas, and westem Wyoming
sources have maximum impacts at Bridger and Fitzpatrick Wilderness Areas, and Mt.
Zkkel. Visibility improvement at these highest impact areas will provide the best
measure of the effectiveness of BART controls.
Each facility should carqr out modeling with the CALPLIFF modeling system for
the Class I areas specified inTableZ. The AQD will provide meteorological input for
CALMET for the years 2001, 2002, and 2003. The model domain covered by the AQD
meteorological data is centered in southwest Wyoming, and extends roughly from Twin
Falls, ID in the west to the Missouri River in the east, and from Denvu in the south to
Helena, MT in the north. The domain is shown, along with Class I areas, in Figure 1.
Sources may wish to utilize a smaller domain for CALPUFF modeling. Smaller
domains are acceptable if they provide adequate additional area beyond the specific
source and Class I areas being addressed. Figure 1 includes a "southwest Wyoming"
domain which represents the minimum acceptable area for sources impacting the Bridger
and Fitzpatrick Wildemess Areas, and the Mt. Zirkel Wilde,mess Area, and a "northeast
Wyoming" domain as a minimum area for Badlands and Wind Cave National Parks
modeling.
The CALPUFF model should be used with each of the three years of
meteorological data to calculate visibility impacts for a baseline (existing emissions)
case, and for cases reflecting BART controls. The contol scenarios are to include
individual sce,narios for proposed BART controls for each pollutant (SOz, NO*, and
particulate matter), and a combined scenario representing application of all proposed
BART controls. If desired, additional modeling may be performed for controls that are
not selected as BAR.T. This might be done, for example, to provide data useful in
identifying tlre control technologies that represent BART. However, visibility modeling
is required only for the proposed BART controls.
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC 4
Page 80 of 96
Basin Eleckic Laramie River Power Plant Boilers #1.2-3
FMC Comoration Granger Soda Ash Plant Boilers #1.2
FMC Comoration Green River Sodium Plant Three boilers
General Chemical Co.Green River Soda Ash Two boilers
PacifiCom Dave Johnson Power Plant Boilers #3.4
PacifiCom Jim Brideer Power Plant Boilers #1-4
PacifiCom Nauehton Power Plant Boilers #1.2-3
PacifiCom Wyodak Power Plant Boiler
Table 1. Wyoming Sources Subject-to-BART
Results of visibility modeling will be presented as a comparison between baseline
impacts and those calculated for the BART conhol scecrarios. Quantitative measures of
impact will be the 98th percentile deciview change (Adv) relative to the 20% best days
natural background, and the number of days with deciview change exceeding 0.5 (EPA
Regional Haze Regulations and Guidelines for Best Available Retofit Technology
(BART) Determiuations, 70 FR 39103). Results should be presented for each year.
Exhibit No. 2
Case No. IPC-E-13-16 5T. Harvey, IPC
Page 81 of96
Class I Areas to be Addressed
Class I Areas to be Evaluated
Basin Electric
LaramieRiver
Wind CaveNP, Badlands NP
FMC Corporation Bridger WA, Fitzpatrick WA
FMC Corporation
Soditrm Products
Bridger WA, Fitzpafrick WA
Ge,reral Chemical
Green River Soda Ash
Bridger WA, Fitzpatrick WA
Paoificorp
Dave Johnston
Wiud Cave NP, Badlands NP
Pacificorp
Jim Brider
Bridger WA, Fitzpatick'WA,
Mt. Zirkel WA
Bridger V/A, Fitzpatrick WA
Pacificorp
Wvodak
Wind CaveNP, BadlandsNP
Exhibit No. 2
Case No. IPC-E-13-16-
T. Harvey, IPC 6
Page 82 of 96
3.0 EMISSIONS DATA FOR MODELING
CALPUFF model input requires source (stack) - specific emission rates for each
pollutant, and stack parameters (height, diameter, exit gas temperatrrre, and exit gas
velocity), Per EPA BART guidance, these parameters must be representative of
maximum actual 24-hour average emitting conditions for baseline (existing) operation,
andmaximum proposed 24-hour average e,missions forfuture (BART) operations.
3.1 Baseline Modeliug
Sources are required to utilize representative baseline emission conditions if data
are available; baseline emissions must be documented. Possible sources of emission data
are stack tests, CEM data, fuel consumption data, etc. Remember that emissions should
represent maximum 24-hour rates. EPA BART guidance states that you should "Use the
24-hour average actual emission rate from the highest emitting day of the meteorological
period modeled (for the pre-contol scenario)." Thus, baseline conditions should
reference data &om 2001 through 2003 (or 2004).
As a minimum, modeled emissions must include:
SOz sulfur dioxideNO* oxides ofnikogenPMz.s particles with diaureter less than 2.5pm
PMto-z.s particles wittr diameters greater than 2.5pm but less
than or equal to 10 prn
If the fraction of PMro in the PMz.s (fine) and PMro-z.s (coarse) categories cannot
be determined all particulate matter should be assumed to be PMz.s.
In addition, direct emissions of suthte (SO4) should be included where possible.
Sulfate can be emitted as sulfuric acid (H2SOa), sulfur trioxide (SOr), or as sulfate
compounds; emissions should be quantified as the equivalent mass of SOa.
When test or engineering data are not available to speciff SOI emissions or the
relative fractions of fine and coarse particles, use can be made of speciation profiles
available from Federal Land Managers at the website
httpllww2.nature.nps.gov/airlpermits/ecUindex.cfrn. Profiles are available for a number
of source tlpe and control technology combinations. The FLM speciation factors are
acceptable ifdata are available for the appropriate source type.
Emissions of VOC (volatile organic compounds), condensable organics measured
in stack tests, and elemental carbon components of PMro do not need to be included for
BART modeling. The only other pollutant noted in EPA BART guidance is ammonia
(NH3). Thougtr ammonia is not believed to be a signilicant contributor to visibility
Exhibit No. 2
Case No. IPC-E-13-16 -t
T. Harvey, IPC t
Page 83 of 96
o
3.2
impairment in most cases in Wyoming, it could be important for sources with significant
ammonia emissions - for example from some NO* control systems. Sources that are
expected to emit ammonia (in pre-or post-control configurations) should include
ammonia emissions in theirmodel input.
If quautitative baseline emissions data are unavailable and sources believe that the
manimum 24-hour emission rates estimated by the Division (ptesented in the Subject-to-
BART final report) are representative of baseline conditions for their facility, they may
be used for baseline modeling. However, emissions of sulfate and ammonia (if
applicable) should be included based on the best available test information or speciation
factors from current literature.
Post-Control Modeling
All pollutants described above should be included for each post-conhol scenario.
Post-contol emissions (ma<imum 24-hour average) will generally be the baseline
emissions multiplied by a control factor appropriate to the BART control. However,
some proposed controls may simply increabe the efficiency of existing contols; others
may result in an increase in emissions of one pollutant while controiling another. These
factors must all be considered in defining emission rates for post-control modeling. Any
changes in stack parameters resulting from conkol application must also be included.
The required visibility assessment willinclude the effect of each proposed BART
conhol. For example, if a source proposes to add a scrubber for SOz control, low NO,
bumers for NO* control, and a baghouse for particulate control, four sets of visibility
results should be developed:
o Use of SOz control aloneo Use of NO* control aloneo Use ofparticuiate coutrol aloneo Use of proposed combination of all three controls
All pollutants should be modeled in each CALPUFF model run, but the modeled
emissions should reflect only the specific controls or combination of controls addressed
in that run.
Additional modeling could be necessary in situations where a facility is
comprised of more than one subject-to-BART source, and different BART controls are
applicable to different sources. Excessive modeling to address multiple control
combinations is not necessary; however, visibility modeling should quantify the effect of
BART controls on all affected sourcqs for each pollutant, and of all facility BART
controls combined.
Exhibit No. 2
Case No. IPC-E-13-16.
T. Harvey, IPC 6
Page 84 of 96
4.0 METEOROLOGICAL DATA
Wyoming AQD will provide MM5 meteorological data fields for years 2001,
2002, and 2003 that can be utilized as input to CALMET. The MM5 output will have 12
kilometer resolution and cover the fuIl domain shown in Figure 1.
Mesoscale meteorological data (MM5) were developed and evaluated as part of
the AQD's southwest Wyoming NOz increment analysis. Three years of MM5 data at 36
km resolution were used to initialize 12 km MM5 simulations. The 12km MM5
modeling used identical physics options to the original 36 km runs. CALMM5 was t}ren
used as a preprooessor to produce CALMET - ready MM5 data input files. Quality
assurance was performed by comparing the original MM5 output on the 36lcn national
RPO gdd to the 12 hn MM5 output and obsenrations.
The CALMET model (version 5.534 level 04071Q should be used to prepare
meteorological input for CALPUFF. The user may select a domain smaller than the
MM5 domain for CALMET and CALPUEF modeling if desired. Figure 1 shows
minimum domain areas for modeling of westem and eastem Wyoming BART sourc,es.
Four kilometer resolution should be specified for CALMET output.
CALMET processing should use the AQD MM5 dat4 and appropriate surface,
upper air, and precipitation data. Figure 2 shows the locations of surface and upper air
stations within the MM5 model domain. The MM5 data are used as the initial guess
wind f,eld; this wind field is then adjusted by CALMET for terrain and land use to
generate a step I wind fiel4 and refined using surface and upper air data to oreate the
final step 2 wind field.
Surface, upper air, and precipitation data can be obtained from the National
Climatic Data Center. Land use and terrain data are available from the U-S. Geological
Suwey. Data can be fomtatted for use in CALMET with standard conversion and
processing programs available with the CALMET/CALPUFF software.
Table 3 provides a listing of applicable CALMET input variables for BART
meteorological processing. The table includes inputs that are specific to Wyoming
BART modeling. Inputs not shown in Table 3 are not relevant to the present application,
are dependent on the specific model domain of the user, use model default values, or are
obvious from the context.
Exhibit No. 2
Case No. IPC-E-13-16 -
T. Harvey, IPC 9
Page 85 of 96
o
Table 3. CALMET Control File Inputs
Variable Descriotion Value
Input Group 1
IBYR Year 2001
2002
2003
]BTZ Base time zone 7
IRTYPE Run twe 1
LCALGRD Compute data fields for CALGRID T
Inout Grouo 2
PMAP Mao oroiection LCC
DGRIDK]VI Grid spacine (km)4
NZ Number of layers t0
ZFACE Cell face heiehts (m)0
20
40
100
t40
320
580
1020
1480
2220
3500
Inout Grouo 4
NOOBS No observafion Mode 0
Inout Grouo 5
TWFCOD Model selection variable 1
IFRADJ Froude number adiustment 1
IKINE Kinematic effects 0
IOBR Use O'Brien procedure 0
ISLOPE Slooe flow effects I
MXTRP Extapolate surface wind observations -4
ICALM Exhapolate calm surface winds 0
BIAS Biases for weights of surface and upper
air stations
A1l0
RMIN2 Mininrum distance for- extrapolation -l
IPROG Use eridded pro.qnostic model output t4
ISTEPPG Time Step (hours)I
LVARY Use varvins radius of influence F
Exhibit No. 2
Case No. IPC-E-I3-16
T. Harvey,lPC 10
Page 86 of 96
Table 3. CALMET Contol File lnputs (continued)
Variable Descriotion Value
RMAX 1 Maximr.mradius of influence (km)30
RMAX 2 Maximumradius of influence (kn)50
RMIN Mnimum radius of influence 0mr)0.1
TERRAD Radius of influence for tenain (km)15
RI Relative weighting of first guess wind fieid and
observations ftm)
5
R2 Relative weip:htine aloft (hn)25
IDIOPT 1 Surface temperature 0
IDIOPT 2 Upper air lapse rate 0
zuW Laose rate depth (m)200
IDIOPT 3 Average wind components 0
IUPWND Uoper air station -1
aiPwND (1)
ZUPWND (2)
Bottom and top of layer for domain
scale winds (m)
1, 1000
1.1000
IDIOPT4 Surface wind components 0
IDIOPT5 Upoer air wind components 0
Input Grouo 6
I.AVBZI Soatial averaqins 1
MNMDAV Ma:r search radius 1
HAFA}IG Half anele for averagine (dee)30
ILEVZT Laver of winds in averaeins 1
ZfrVTAX Maximum overland mixins heipht (m)3500
ITPROG 3D temperature source I
IRAD Intemolation twe I
TRADKM Radius of influence - temoerature Om)500
NUMTS Maximum number of Stations 5
IAVET Soatiai averasins of temoeratures 1
NFLAGP Precipitation interpolation 2
Exhibit No. 2
Case No. IPC-E-13-16. .
T. Harvey, IPC r I
Page 87 of 96
t
5.0 CALPUFF MODEL APPLICATION
The CALPUFF model (version 5.7lla5level 040716) will be used to calculate
pollutant concenh'ations at receptors in each Class I aiea. Application of CALPTIFF
shouid, in general, follow the guidance presented in the Interagency Workgroup on Air
Quality Modeling (IWAQM) Phase zreport (EPA - 454lR98-019) and the EPA Regional
Haze Regulations and Guidelines for BART Determinations (70 FR 39103).
Appropriate CALPUFF control file inputs are in Table 4. Note should be taken of '
the basis for several of the recommended CALPUFF inputs,
. Building downwash effects need not be included. Because of the hansport
distances involved and the fact that most sources have tall stacks, building
downwash is unlikely to have a significant effect on model-predictod
concentrations
Puff splitting is not required. The additional computation time necessary for puff
splitting is not justified for purposes of BART analyses.
Hourly ozone files should be used to define background ozone concentration.
Data are available from the following sites within the model domain.
Rocky Mountain NP, CO
Craters of the Moon NP, ID
AIRS -Highland UT
Mountain Thunder, WY
YellowstoneNP, WY
Centennial, WY
Pinedale, WY
The background ozone concentration shown in Table 4 is used only when hourly
data are missing.
A constant background ammouia concentration of 2.0 ppb is specified. This value
is based upon monitoring data from nearby states and ilMAQM guidance.
Bxperience suggests thal 2.0 ppb is conservative in that it is unlikely to
significantly limit nitrate formation in the model computations.
MESOPUFF II chemical transformation rates should be used.
The species to be modeled should be the seven identified in CIT.PUFF: SO2,
SO+, NO*, HNOr, NOl, PMz.s, and PMro-2s. If anrmonia (i.IH, is emitted it
should be added to the species list. In most cases, all pollutants modeled will also
be emitted, except for HNOI and NOr.
Exhibit No. 2
Case No.lPC-E-13-16
T. Harvey,lPC 12
Page 88 of 96
Concentration calculations should be made for receptors covering the areas of the
Class I areas being addressed. Receptors in each Class I area will be tbose designated by
the Federal Land Managers and available from the National Park Service website.
Table 4. CALPUFF Conffol File Inputs
Exhibit No. 2
Case No. IPC-E-13-16. ^T. Harvey, IPC IJ
Page 89 of 96
Variable Description Value
Inout Group I
METRTIN Control oarameter for nrnnins all periods in met file I
IBYR Starting year 2001
2402
2003
reTZ Base time zone 7
NSPEC Number of chemical soecies modeled 7 (or 8)
NSE Number of species emitted 5 (or 6)
METFM Meteorolosicai data format I
Inout Group 2
MGAUSS Vertical distribution in near field I
MCTADJ Terrain adiushnent method 3
MCTSG Suberid scale comolex terrain 0
MSLUG Elonsated puffs 0
MTRA}IS Transitional plume rise I
MTIP Stack tip downwash I
MSIIEAR Vertical wind shear 0
MSPLIT Puffsolittine allowed?0
MCHEM Cherrical mechanism I
MAOC}IEM Aoueous phase transformation 0
MWET Wet removal I
MDRY Drv denosition 1
MDISP Dispersion Coefficients 3
MROUGH Adiust signa for roushness 0
MPARTL Partial plume oenetration of inversions I
MPDF PDF for convective conditions 0
Input Group 4
PMAP Mao proiection LCC
DGRIDKM Grid soacine 4
o
Table 4. CAI-PUFF Control File Inputs (continued)
TFACE Cell face heiehts (m)0
20
40
100
140
320
580
1020
1480
2220
3500
lnput Group 6
NHILL Number of terrain features
Inout Group 7
0
Dry GasDepo Chemical parameters for
dry eas deposition
Defaults
Inout Grouo I
DryPart. Depo Size parameters for dry
particle deposition
SOa, NOr, PM25
PMIO
Defaults
6.5. 1.0
Inout Grouo Ll
MOZ Ozone Inout ootion 1
BCKO3 Background ozone all
months (ppb)
44.0
BCKNH3 Background ammonia - all
months (oob)
2.0
Input Group 12
)CtvIAXZl Ma:<imum mixing height
(m)
3s00
)O\4INZI Minimum mixing height
(m)
50
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey,lPC 14
Page 90 of 96
6.0 POST PROCESSING
Visibility impacts are calculated from the CALPUFF concentration results using
CALPOST. CALPOST version 5.51, level 030709 should be used; the output from
CALPOST will provide the highest deciview impact on each day from all recqltors
within each Class I area modeled.
For some CAIPUFF applications such as deposition calculations, the POSTUTIL
program is used prior to CALPOST. POSTUTIL is also used to repartition total nifrate
by accounting for ammonia limiting. The ammonia lirniting calculation in POSTUTIL
should not be applied for Wyoming BART modeling. If you believe that ammonia
limiting is appropriate for a specific BART analysis, justification should be discussed
with the Division prior to its used.
Visibility calculations by CALPOST for BART pulposes use Method 6. This
method requires input of monthly relative humidity factors, f(RH), for each Class I area.
The EPA guidance document provides appropriate data for each area. Table 5 lists
monthly f(RII) factors to use for the 'Wyoming, Colorado, and South Dakota areas to be
addressed in BART modeling. The factors shown in Table 5 include averages for the
adjacent Class I areas, and are within 0.2 units of the Guideliue table values for the
individual Class I areas.
Natural backgror:nd conditions as a reference for determination of the delta-dv
change due to a source should be represe,ntative of the 20Yo best natural visibility days.
EPA BART guidance provides the 20Yo best days deciview values for each Class I area
on an annual basis, but does not provide species concentration data for the 20% best
background conditions. These concentrations are needed for input to CALPOST.
Annual species concentations corresponding to the 20% best days were
calculated for each Class I area to be addressed, by scaling back the annual average
concentrations given in Guidance for Estimating Natural Visibility Conditions Under the
Regional Haze Rule (Table 2-1). A separate scaling factor was derived for each Class I
area such that, when multiplied by the Guidance table annual concentrations, the 20%
best days deciview value for that area would be calculated. The scaled aerosol
concentrations were averaged for the Bridger and Fitzpatrick WAs, and for Wind Cave
and Badlands NPs, because of their geographical proximity and similar annual
background visibility. T\e 20o/o best days aerosol concenhations to be used for each
month for Wyoming BART evaluations are listed in Table 6.
Table 7 is a list of inputs for CAIPOST. These inputs should be used for all
BART visibility calculations. Output from CALPOST should be configured to provide a
ranked list of the highest delta-deciview values in each Class I area. The 98th percentile
delta-deciview value and the number of values exceeding 0.5 can then be determined
directly from the CALPOST output.
Exhibit No. 2
Case No. IPC-E-13-16- -T. Harvey, IPC l)
Page 91 of96
o
Tabie 5.KH Factors for Class I Areas
Month Wind CaveNP
Badlands NP
BridgerWA
Fitzoatrick WA
Mt. Zirkel WA
January 2.65 2.50 2.20
February 2.65 2.30 2.20
March 2.6s 2.30 2.04
Aoril 2.55 2.10 2.10
May 2.70 2.t0 2.20
June 2.60 1.80 1.80
July 2.30 1.50 1.70
Auzust 7.30 1.50 1.80
Septernber 2.20 1.80 2.00
October 2.25 2.00 1.90
November 2.75 2.50 2.t0
December 2.65 2.40 2.ta
Exhibit No. 2
Case No.|PC-E-13-16
T. Harvey,lPC 16
Page 92 of 96
forBARTAnal
Aerosol
Comoonent
Wind Cave NP
BadlandsNP
FitzpafrickWA
BridserWA
Mt. Zirkel WA
Ammonium Sulfate .047 .045 .046
Ammonium Nitate .040 .038 .038
Oreanic Carbon .186 .178 .t79
Elemental Carbon .008 .008 .008
Soil .198 .189 .190
Coarse Mass 1.191 1.136 1.I41
Table 6.Natural Background Concentrations of Aerosol Components for 20% Best Days
Exhibit No. 2
Case No. IPC-E-13-14 -T. Harvey, IPC I I
Page 93 of 96
o
Table 7. CALPOST Control File
Variable Descriotion Value
Inout Grouo 1
ASPEC Soecies to Process VISiB
ILAYER Layer/deoosition code I
A,B Scaline factors 0,0
IBACK Add b acksound concentrations?F
BTZONE Base time zone 7
LVS04 Species to be included in extinction T
LVNO3 T
LVOC F
LVPMC T
LVPMF T
LVEC F
LVBK Include backeround?T
SPECPMC Soecies name for particulates PMlO
SPECPMF PM25
EEPMC Extinction efficiencies 0.6
EEPMF 1.0
EEPMCBK 0.6
EES04 3.0
EENO3 3.0
EEOC 4.0
EESOIL 1.0
EEEC 10.0
MVISBK Visibilitv calculation method 6
RTtr'AC Monthlv RH adiustment factors Table 5
BKS04 Backsround concentrations Table 6
BKNO3 Table 6
BKPMC Table 6
BK OC Table 6
BKSOIL Table 6
BKEC Table 6
BEXTRAY Extinction due to Ravleieh scatterins 10.0
Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey,lPC 18
Page 94 of 96
7.0 REPORTING
A report on the BART visibility analysis should be submitted that clearly
compar€s impacts for post-control emissions to those for baseline emissions. Data for
baseline and BART sienarios should include both the 98ft percentile values and the
number of days with delta-deciview values exceeding 0.5. Results should be given for
each model year.
Table 8 is an exanrple of a recommended format for presentation of model input
and model results. The example is for baseline conditions; similar tables should be
provided for each control scenario (SOz, NOx, and PM10) and for the combination of all
BART controls. Your report tables need not follow the exact format shown in Table 8;
but the same information should be provided in a concise and clear form. If additional
scenarios were modeled or you wish to present supplemental information, they should be
provided in an appendix or separate from the specified final results.
Exhibit No. 2
Case No. IPC-E-13-10ro
T. Harvey, IPC L/
Page 95 of 96
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Exhibit No. 2
Case No. IPC-E-13-16
T. Harvey, IPC
Page 96 of 96
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--I'hc \\'yr.ltring Dcpartnrcnt rrIEnvirortutcrttrl r)ualitr, i\ir QLrulitl, Dilisiorr (rlic -"UiZlbq^,
"DEQTAQD") anti PucifiCoqr Errcrgr- a divisiort o1'l'acifiC'oqr 1"Plci1i['orp"). entcl inlo thjs ''r+iia?
IlAR"l- Appual Srttlcnrcnt,,\qlcelttctrt (tlrc ''Settlcnrcnl Aulccrtteut") trr lrrllv arrrl llrrali\ rc:s,rlrc Lil
l'ircifiC'oqr's rippcal hc:Rrre lhc \Vt'oming linlirontncrrtal Qtrrrlitl'('ourrcil lthr "llQC"'t in Dot:kct
lro. l()-l8ol u,hcrciu PauiliC'orp chrllrsrrgutl cerrtain uontlitiorrs o1'LJ,4,11l Pcnuit Nos. \,1 D-()()+()
anri \1D-6()42 fbr the Jirn Brirlgcr aud Naugltlon []o\\'cr ]rlrrnts. 'l'hc i)[Q,AQD arrd Pri:ili('or-p
arc collcctivcly refcrrctl to hercin as tltc "Partics" ancl sonrctinres indiviclually'as ''Partv." Tlrc
Srrtllsr:tent Agreernetrt shall be efl'cctive bcls'cert thc Parties tirt lhc datc that thc last siuni.iluu'u rs
alljxcd belou'(the "Etl'ective Datc"). ccrriditionctl ort altpror,al [r1,tlrc [.Q('as rlcst:ribr-.d hcrcin.
\\;r,o. Slal. l6-3-l()7(n)atrrl Clrapter l.
^s
ll ol'the DF-i(.)'s Itulr.:s ol Practir-rcr & Prrrcr:t'lrrrc
prrliitlc li,1 11,".lisp,r::iiirtrt ol'tltis c(ir"rtcstu(l crtsu [r.v \tll]uiatirrn o1'lirr; Itrrtics ulxrn lrppror;rl hi,
rlre F(](. Atltlitiorriill-r,.\\'ro.Stat1i-<-ll-lllcmlx)\\.'irsthuI:(.X [ooltlclthcnrr-rrliilulliorrol'
UAI{ [ l'cnnir N,:s. MD-6(i40 and i\'lD-6(]-ll t'r r,iisolr'c this eontcste(l L'r.rsc. -fo tlrirt cnd.
PlcifiC"orp ancl lhe DEQIAQD, condilioncd ott thc irppror,ll ol'tlre EQ('. herehv slipulirtc arr,-i
strcc il\ litllrrrvs.
I . Bacltground: As part ol'its obligaliort under'llre C'lenn Air r\r.:t's I(esionul l-lrrzc
Proglanr. lhe State of \\Ivonring. thlotrglt thc DEQTAQD. pronrulgalLld rusul.rti()r'15
recluiring tlre installatiorr ol'Bcst Avarlahlc Ilctroiit 'feclrrroio-9\, (''lJ:\li'1"') trrr
c.\tuit1 eligible facilities. PaciliCorp tiurell, conrl;lied rvith tlrcse rL.gulirti()n{ l))
tiling applications for ll.r\,ltT pcrrrrits iirr its eligiblc trcilities, includirrg lrr
application lor its I3ridgor pr)\\crr- plunt on January 16. 2(X)7. and its \rrr.rrrlrttrn
p(t\1jcr plaut ott February 12. 1007 Pacrit'i('r.rrlt hrrthcr flled irclditional irtlirlrtratirru
rvith the DEQ/AQD relatiug to tltese aPplications. Folluw'ing Prrblic nlticc nril
cornrncnl. and public hcarings. thc DEQI,,\QD issued BAIIT pennit Nos. \.'lD-
6040 fbr the Bridgcr powe r plartt artd \l D-60+2 lirr the Nauglrtrrrr pcr\\.cr pllnt ()n
Deccnrhcr 31,:009. C)u l-cbruerr, 26. l()l(). PlciliC'orp linrell, lllcil an a1'r1:eal ro
thc EtJ('t:['ccnain plovisiorts in 8,,\llT perrnil Nos. \'lD-(r()40 and .\.'lD-6()]2.
I.-irigation ertsuctl. inclLrtlirtg tlisctor,crn anrl rrurtiorr prilcticc. l'his Sctilctrcrrr
Agrccnreut rcsrrlr'cs ull issues t'uiscrl iu thal litig;rtitru. Also. iu ct-,rrneclirrrr u,itlr
tiris Scttlcrncnt r\grec:ntcttt. Paci fiC'ot'p liits pr,n.irlctl to Dl:Q'AQD thc
rnlirrnratirrir attuchctl ls Erliitrit A rvltich ihr-: l::ltics intcrrd to hc rrscil in the
\\jy'onrirtg Rcgic'rtal !lszc SIP as that lcnu is tlcscriherl l-.clori.
Dcl'initions: i\s rrscd irt tltis Agrccmcrtt. tlrc ttlllorviug tcrr)]s al'c rlcl'rncci ai:
"UAll,T Perrlit Appeal" nrcnns: PacitlCcrrlr's Arrpeal ancl Petitirtu {'or Rci ieu,tri
BART Pcr"nrits l'r'grrr(ling thc Briclgcr 8.,\R-f Pcnuit arrd tlrc Naughrnn lJAlt I
Pt'rnrit. r'ctin'ccl lo as [)t'rckct No. l0-2fi()1. huli'r't: rlrc l'it-)('.
"Ll.\lt I ;\p1lelrls.,\rgtrntotts'' tilcilns: .Ihr lrgrrrrrerrl.s ririsci.l [rr, l)ir,.'ill('orlr iit lhr
IIAR'l'l)er-r"nil A1t1lcll. irrt'lrrrlirru its \fulinrr lirr ['ar'tilrl Strurrnlirr..l ritigrri,-rrr iin,l
Exhibit No. 3
Case No. IPC-E-13-'to
T. Harvey, IPC
Page 1 of 17
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Agrccnrenl: '[-ltc Paltics havc crrgagccl in ncgrrtirtiorts tri r(:1ircl] i. sr:iLluri
rcsoltttiort to this ctrrtir:siar.l r)ilsc, Thc Irar-iies lrit,.e ligrcc.!. up()ll tlru tcl-]us
!',ilrrlililrc(l Iicrr:irt. to sut[lc ql1{ g1r1111'ly1rn:ise I}reili('or'qr's Lii\li'l Pcn'urt ,\;.r|cirl.
i nc.l r.rdi ug the B.\ R T .{ ;r1':ca I r;,{rgur.n crrt s.
I'crlirrrrratrcc lrY PlrciliCor"J): lr reliurrcc uporr tlrc rulcrrcs. .r.glc'ulnr:nl.s. rr(l
rr:prrsuututir-rr:s rrf'thc DEQ,'AQD in tlris Scttlcrncirl Asrer.-':rren1. artcl conclitiuur.'rl
u;rou lhc E(JCI's apprrrr.al o1'tlti-s Settlertrent Agrccurent rirrrl its tclrns. PaciilC,,rll
slrail rlo the lbllorvirrs:
\rrushton - PaciiiCorp shall uitlrdlaiv irs ll,,\R-l' ,\ppeirls Alglulcrrrt.
rcuer(litlg llrc Nrurghton l)(1\!er lrlnrrt- clirnriss its Bi\liT ['t'nnil ,/"rplt'lrl
it rclatc.s l.o iltL' \iir.lr.!,1)t()n l)i)\\cr'pla:rt. lriri il.srec lo uhiilc irr'(lru tcnns
llre N.irrglrtr'u il.\l{ I I'r'r'uiil:
(h1 Briil g,;r- - Pacifi C'l,rp slr;rl l u' j rhdrinv r l s Il,{ l{' l A ppci.rl s r\rltrn'rtrnts
rcrrrrLlirril thc 13r'irlgcr i)()\\cr-plirnt. disriri-*s its lJ,\l('l I'elnril ,\ppcul lis il
lulatus to thc i-)riilgcl p()\\ cr irlillrt. lli.lrl rsl'r'( t{} rrbielc ilte to'urs o1'Ilit:
Blir-lgcr BAI('f Purrnil rrs rn,rclifler.l br tlrc l:(.)C'iri iir'cor(liuluc riitlr tliis
Scltlcnrurrt ..\t1tr'ctttt'trt. itrcluiling tirc lr:rnovul tii-('ortilititrns l7 lnri lS:
(r'i ii(-)r Ctrtrtlt.rl lirr IJlirlr:cr t-inits I untl -.1 \\ritlr rr:sPC(r lt, []r-rtl".'r'L.lriirs -i
iirrrl J- Prreilr(orp sh;rll: ii1irrstrll S('l{:tii)insi;r[! iillclrrritiri utlrl-rrn ]\(tx
t'ollIfol slslci]rs. ,ir (iii) trtltcrtrisr: t'r'tlut'c \( ).rl crtrrssiort: iir lre lue vc :t (].ttl
Il, rtritllttr l(i-iill tolling i'l\L:rir!u l,\()r r:;ttissitiris r'lr[(. '['lrc::rr instirillti,,:ls
siliil t,.:t'tir- lrrlti rri tlti. crnissiorr rlrlc.,,.'ill lic liclii,.ri.:i,i. rrrr I 11ti-i;'rt'ior'1r'
Exhibit No. 3
Case No. IPC-E-13-'t6
T. Harvey, IPC
Page 2 of 17
il5
oi
(d)
[)('ccl]rhcr I l.lft Ii lrnil Ilrri{-l lrrirrrlo I)i'ci'rnhcr'.1 I.l() I( -lltc.c
iustirlliltii'rrs shirll ()ccur. arid i,r this ctrissit'rt rutc: u iii bc rr"hie,. cti. rrt
con.lunction rvith PacitiCor'1t's planncd or:cllraul scht'Llule tirr tlti:s.: r-rrrrl.
and pursuanl t() a cor"lstr'!rclion or'olher pernrit application to lrc slrt'lruitlctl
by Paci{iColp to AQD I'lo latcl tltart Dccenrber'-l l" f0l2: arirl
NOr Clorrtrol iilr BridQ.er Urrrts I ancl 2 -- \\'itlr rcsllcct tti [Jritlger t.,nits I
aud 2- I'}acrllCorp slrall: (i) instell SCI(:(iitilrstrrll itlteilltit'c adtl-on Nt)r
corrtrol svsterlrs: or (iii) otlterrvisr: rctluec NO.r ertrissiorts ltcrt itr crccerl rr
0.()7 Ib/rrrr:rBtLt i0-da1, rtrllirrg a\era{.r,c NOx cr:rissirrrrs ratc. TIrcsc
installrtions shall rrccur'. .rrirl,rrl this crtiissiorr rrrtt' ,.r ill bc aclticvctl. r,n
L lnit I nrirrl lii l)eccnrbcr -1 l. ]t)l I riut! l.'rrit I i-rr'i,lt lrr i)cecutbci' .l I ]O-21.
Ilrt'lc insullatic'ns sltoll r)ccur'. ilr'rri rrr'lliis crlliisi,,n r"rrtr: ri'ill lrc irt:hiu:r'cil-
in corr.iuuctiou rvitlr I'aciliCorp's y'llarrnc,.l or,criritLtl selrcdule'ti'r tltcsc rrnrls
atrrl l)LtrsuflnI irr ir col'rstrrrcti()n ilr ollrcr perrrrit illDlicrrti()n tc' lrt suibrr:itferi
b1' f itciti('ot'p to AQI) tio lalur tliarr l)ccuntl-rcr-.] l. ft.) [:
Ilerlbrnrance b1, tlrc DII{)/AQD: lrr rcliurrcc rtlrort thc rclcrsc-<. iruicc!rclilr iir)(l
rdlt'c:scntiltic,rrs ()f'Paci ll(ior1l in thi-c SCtllLIucrlt r\:I'rcrIr(nt. :iritl t,,nrliti'\!le(l rri)(,1)
tlrc h.Q(''s apprr:lal ol llris Scttlcrncrrt ;\r$ccn)cr){ arrrl iti t(:n'l}s. tlie Di:(J ,\QI)
sltall d<, the liill,.ru inr:
(x)Nauglttrrn 1'lrc DEQ:r1qD slrrll. I)ur":iLlirnt io ati ttrderr 1r.,, th- ["()('
ill')l)rr)\ rrrg tlris Suttlcrrrsut :\src.crrrrrtt. irrclutlc itr tlrr'\\'-r'ott.rirr_r-l Rcgitrrral
l-lirzs SII) a slillelncrll explrtitting tlri.rt ll.rc r-oSt r)1-tlrc Nauglrton [.rrit -i
['lagl]ilr.rse is icasonal'rlc rr,hcrr crrrrsidclinr ull litctr.lrs i'clating to tlrc cr.istiny
Pi\'1 corrtrols irt iulclitiort tr-r tlrosc consi<lcrud rlru'in1t thc Il.{lt'l';urirlrsr.
(h) Brirlecr 1'he DIlt];r\QD slrrtll. pursilartl lo rttt orticr bi thc [:(")(
approvirru tlris Scltlerrc:l!1 ,'\glcunrrnt. tlr-rlctc (orttlitions l7 irrrtl IS lrrrur
thc^ Blirl{1cr LlAlt'l"Pcrntit ancl. in licrt oi ('ourliiirrrts ll rrttl lS. rldcr-l :llr
ra(luircrlcrlls ol'paliiBrlrl:;its.lluilrnrl itti ttrl tltir Scttlr:rrrer)t Artrcul)rrlrt
ljtt() llto \\".,'irrrtrrtlj l{ugtouul llt;:c Sll'ls P:rrt rrt.\\'r.,tniril'-. i-,,rtS-lt'r'rtt
Slrntctr. iirtrl rtt' Ileusottlrhle I)t'trurcss ( ioi:ls. irn,l
(ci ['lciiiL'r,r'lr'-r C'<rrttpliartcc rvitlr [-]r\11'l arrr-l l-l -s ]{cqLiircntcnts - ilic
l)Hq).,\(JD slrirll riot rccprir.-' lirrther l']\l or NOr r.ctluc'tiorrs ;rt Nruqlitol
Ltrrit l. ()l'l'c(lr.rilc lirrtlter NOx leductior)s ilt lJil(lg,i'r L-lnits I -l- {irr
I)url)osL-s o1t uructirt-U 13ARI'. L,onq--J t:rrrr Sltlrtcg_r, r'cclrriIcrrtcrrls iiil\l (]r'
i{citsirrrllrlc l)rotrcss (iouls iu thc \\'f ii111i11g Rcg,irinll Ilrrzc Sll' thr',,ir-itir
1023.
Corrdititirrs o['Sctrlcntcttt: 'l'hr: ['lrr'(ie:' ilrrtic.:. l'iglti. lirttl ohli,]l,rlioirs r,l thr:
Scl tlt'nrent ..\rr,t'r.'crlcttt itrc ('()lr(iili()lli'(l ul)irr..rr'ri lli; I'l:;'l i.'. slt:ili rri r:t,rrrl l;ritl
r:()()l)crill( L(i JclliL'\'(i. tlte lirllt,$ rrl-g:
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 3 of 17
1
i)
8.
(a) Tlrc EQC anci arry other required Wyorning governing ar.rtholitl' nrust
approve this Settlement Agrcemelt and its tcnns:
(b) PacifiCorp and the DEQ/AQD nrust file a joint stipulated motion with the
EQC recucsting dismissal of PaciflClorp's BART Pennit Appeal, arrd the
EQC must dismiss the BART Pcmrit Appcal orr approval of thc tcrms
contained hereiu subject only to EQC's continuing jurisdiction as
describecl in Section 7 belorv;
(c) The EQC nrust order thc Bridgc,r' BART Pcmrit be modiilcd as rcrluired
lierein; and
(di EPA ntust approve thosc portions ol'the Wyorling Regional Haze SIP that
are consistent rvith the tenrls of this Settleu'rent AEeernent. Proviiled.
horvever, that unless EPA aflnnatively clisapproves such pofiious ol thc
Wyorning Regional Haz.e SIP in a tjnal rulernaking. tlre parties slrall
continue to abide by the tenns of this Settlemcnt AgTeement.
Changed Circumstances: The Parties ag'cc that this Settlenrent Ag;r'e ement lnay
bc subject to rrodificati<ln if f'uture changes iu either:(i) federal or state
rcqr"riler-ucrrts trr (ii) tcclrntrlngv u'ould rnateriall_v alter thc eurissions controls and
rates that utherr.visc arc requircd hcrcundc'r. In that casc, cithcr Party rnay rcqLrcst
that []rc other Party enter iuto au anrendrnent to this Scttlement Agreement
c.onsistent with suclr changes. Thc Parties shall negotiate in good faith to arlcnd
the atfectecl Settlement AEeeruent. prr:r,ision(s) oonsistent with the c,hanged
fbderal or state requirements or technology and with the purposcs of this
Settlernent Agreeurent. If tlie Parties cirnnot agt'ee trn the ploposccl amenclurent,
then eiiircr Party rnay request the EQC to determine if'the proposecl ameuclnrent is
consistent with the chauged lederal or statc requirernents or tcchnologv aud u,itlr
thc pruposcs of'this Settleurent Agreement. lu that oase. the Parties anticipate that
the EQC dctcmrination rvill be incorporated intrr an EQC order that requires the
Parties to proceed in accrxdance rvith its ternrs, inclurding tlrepussibility o['
cntcrring into thc proposcd anrr:rrdrncnt. Tlrc Parries furlher antrcipatc that the EQC
u'ill retairr continuing jnrisdictit-rn over the BART Pernrit Appeal and tlris
Scttlement Agrcernent frir the foregoing i:urpiises only.
Rcscrvation of Rights: PaciliCorp rescrves the r-ight to uppeal or r,hallenge any
actions by AQD, EQC or EPA that are inconsistent u,ith this Settleinent
Agreernent. In addition. if the EQC takes any action u,hich is matcrially-
inconsisteut rvith or in any rvay materially alters this Settlement Aureerrent. thctr
this Set(lement Agreement shall he voidable at tlie optit-ru of the Parly mirteriallv
irtlcctcd bi' the IIQC's actions.
-flris Scttlcnrcnt Agxeerrcnt shall Lre admissible by cither Parly u,ithotrt objcctiou
1'rv the otltel Pan1, iu any subsequent action between lhese Partics to cntirrcc the
tclnts hcrcolor as otherrvise reqrrirecl her-ein.
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 4 ol 17
t0 n*either Party shallhave any clairn against the otl:er tbr attorrrcy fccs or othcr'
costs incurred rvith the issues resolved. Each Party shall bear its orvrr atlornev
f'ees and costs. iI'arry. incurred in conneclion witlr thc BART Psnnit Appcal ancl
tlris Settlenrent Agreement. Each Party assumes the risk of any liability arising
fiorn its orvu conduct. Neither Part_v agrees to insure. defend or indeurnify tlrc
()ther.
J'his Settlement Agrcement is bincling uporl PacifiCorp, its successors ancl
assigns, and up<lr the DEQ/AQD.
This Scttlcment Agreement may only be anrended in wliting, signed hy both
Parties.
Neither the DEQiAQD nor thc State of Wyoming nor any ol its Aucncics slrall be
lrcld as a part-v to arry contracts or agrcenrents entered into by PacitiCoqr to
irnpler.nerrt any conditior: of this Agrcement.
Nothing in this Agreement relieves PacifiCorp of its duty to comply with all
appticable requirenients u:der the Wyorning Environmental Quality Act
(WEQA), and rules, regulations. and standards adopted or penrrits issued
theieuncler. DEQ/AQD does not warrarlt or aver- that PacillCorp's cornpletion ol
any aspect of this Agreement will result ir: conrpliance rvith the WEQA and rules.
regulations and standards adopted or pennits issLred thereunder,
'I'he State of Wyoming and the DEQ/AQD do not rvaive sovereign imnrunity by
cntcring into this Settlemcut Agrccment, arrd specifrcally retain all innrunity ancl
all def'enses to thenr as sovereigns pursuant to Wyo. Stat. .s I -39- 104(a) arrd all
othcr state lau,.
The Partics do not intcnd tcl crcate in any other individual trr entity the status of
thircl part,v bcneficiitry. ancl this Agreenrent shall not becorrstruecl so as to creatc
such status. The rights. cluties and obligations contained in this Agreement shall
clperate only aruong 1l:e Parties to this Agreerrent.
Shoulcl ar'ly lrortiol.r olthis ,{greernent be judicially dctennined to bc illcgal or
unenfrrrceable, the'rernairrder ol'this Agreemeut shall coutinne in full force lucl
effcct, arrcl either Party nray renegotiate the temrs aff'ected by the severance.
The construction. interpretation and eutbrcerncnt nf this Agrecrncut shall bc
govemed by tlie larvs of thc State of Wyoming. Tlre Courts of the State of
Wl,orning shall have jurisdiction or,er this Agreement and the partics. ar:d tirc
venne shall lre the l:irst Judicial District, Laranrie County, Wyonring.
This Agreerndl'rt nray bc executerl in any ntrnrber o1'separate c()ul)tel'parls ilnr- one
ot'rr,hich ncercl not coutain tlre sigratures of nrore lhau one [)arty but all ot such
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 5 of 17
t4
il.
1"7
15.
r6.
18.
19.
20.
21.
countelparts together will constitute one Agreement. The separate counterparts
trray contairr original, plrotocopy- or thcsirnile transmissions of signatr.rres.
The persons sigring this Settlerr,ent Agreemeut certify that they are duly
authorized to bind their respective Party to this Scttlernent Agreenrcnt.
This agreemeut is not binding between the Parties until fully executed by each
Pafty,
/
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 6 of 17
Dc..* r'. Ra r cra^l
! rcF PResr orAr erni eeArzo..J
/ l- ? -7bt6
rirrc: l)t/cuA f
[)atc: //
I'I{[ \\'\ Otll\(; I)11P,\R'l'\Ili:N"f 0l:'
IiNY I RON\{ I..\'[.,\ t . Qt i \ t.t1'\',rt)tYtSrO\ 0F,\I R
Qt",Ar-t'r\
1'l{ li \\'\'()}l I NU D t'.P;\ Rl'i\ I ial(l- 0 t:
l:\\ I ll()\IIt'-\1'.\t- Qt .\LI'l \
Nar-t)i.
By:
N arrtc:
I'ir I u:
Da{.':
,,\p1'rror,crl \s 'l'o
Foritt
S\€,/EN A. AErXKlt
AQj - AArhrNrsrnAToR,
n-3- lo
Exhibit No. 3
Case No.lPC-E-13-16
T. Harvey, IPC
PageT of 17
aoat l, C,y<aA-
Novenrber l- 2010
Exhibit A
Paci ti C'orp's Emissions ltcr-luctions PIarr
In conncctit.rn r,vitl: its Best.A,i'ailablc Retrofit Tccirrrt,lt,$! (''BARl'") ,.lcterrriinations anll its
otlter regional haze plannirig acti\ritics. tlre Wyorrring Departmerrt o{'[:nviror]nlental QLrality. Air
Quality Divisit'rn ("AQD") asl<ed PacifiCorp to plovirle additional inft,nnatiorr about its ovcrall
elrission re(hlction plans thrriugh 202i. Thc purposc is trr rnore tirlly address the c()sts ()f
cornpliance on botlr a urrit arrd systenr-wide hasis. Paci tiC'orp is corlrr.:ittcci to rccluce clnissiolls
irr a reasonable, systcmatic. ccorrorrrrcally sustainable ancl environnrerrlally sound nranner whiic
rneeting applicable Icgal recluirenrents. Thcsc lesal rcquirernents inclucle cornplying u,ith thc
rcgiorral hazc rulcs rvl.riclt encompaiis a natit.rnal goal to uclriei'c rrirtr.rral visibilit,v- c(rllditir)ns in
C'lass I arcirs hv 206{
Sunrrn:rrY
Paci tiCorp orvtts itnd operatcs lt) clrnl-t1g1ed gerrclatirtu trnits in Litalt;ttrtl \\;yontiug. trd ttrvtts
l00o;b of Clrolla Unit 4, rvhiclt is a coal-flielecl generilting uuit located in Arizona. PaciiiC'orp is
in tlre process of irnplernenting art enrission recluctiorr l,roglanr tirat has reduced. and rvill
corrtinue to signilicarrtly reclr"rce enrissions at its cxisting coal-iirclcd gcrrcration units over thc
next several years. Irrom 2005 through 2010 PaciliC'or1l has spcrrt rlorc tlrau Iil.2 billion in
capital dollars. lt is anticipatccl that the total ctlsts tirr nll projects tlrat havc been conrrnittcd to
rvill excccd $2.7 billion by tlrc cncl o1.1022. Tlrc total costs (s'hich rrrcluclc uapital, 0&M and
otlrcr costs) that ri,ill have bccn incurrcrl bv customcrs to pay lbr these ptrllution cronfiol prcjccts
clurirrg tlrc periorl 200-5 through ?021, are expccterl to crceed S4.2 irillion. and by 20li the
annual eosts to customers [ilr these proiccts rvill have leaclred 53(r0 nrillion pgr ]/ear.
Eur,irertuncntal berrefits. irrclucling visibility improvcureuts rr,ilt t'lorv li'url thesc. planrred
ernissiou recluctions. PacitrC'ory: bclieves that the err.Iissiou rerluction projects and tlreir tinring
appropriately balance thc nccd lor emission rcductions orrer tinrc u,itlr the ct'rst trntl othcr
concerrls of our custonrcrs, olrr statc utilitl, rcgulaiory cornnrissions, and other stakeholdem.
PacifiCtiri: hclievcs this plan is conrplenrcnlary t() arrcl ctrnsistcnt \\,itl'r thc statc's lSAI{T and
regit.rual hazc pl:rnrring requrrcnrcuts. and that rt is a r',:asorrabler approaclr to achieving enrissior-r
reclrrctiorts irr Wy9111i11g artd otlicr surtcs.
l':rciliCorp's Lon g-'['crnr Iirnission I{crluction C]o tnnrittuent
Tahle I hclr.rr.,'idcnti{jes the crtrission rc(luctioll prr:jccts lnd rc'latetl construction scircdr.rles as
curreutly irtcludc.cl rrr Paci fiC'orp's rc(iur:tion L'rlan.
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 8 of 17
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i'acili('rrr'p in Utuh. \\'-r,ortrirrrt:ul(l i\llz()ilir'. lt is si{nrllurrrtt [() ltritu tltlt 1tt'ruittins hls [)L:u]t
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llcnniltcd entissir)lt r'rtc. In Ihrtsc cl-qcs \\'c|c tllc l[rit: (lo n()l hirvll ('r'nissirr!ls cr.tntrr)]s thc
csliltlatcis lrtrvc [-.cen lt.,rsrrtl rin prtrjcc:littns r]l'lhu tittt-lt'c i'rr1il 11s1.'l'11'. All Prtricctiolls Llsl.'rl trc fir)lrt
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l',:\':ji{ \,i I l: tli.r, ;1 1,',,r1
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.:r il( r- {,: r','ril-ltrt:lt'i i:ir:ilriris rr: (,,1,,r:r.:,,r;r,i
,'r rr lri. it l'.r.'ill( i,r:r tr ril irir'lr-lr:..,r(-',"rt(',-l .\r\i
\i',r!1.:,,:r ilri:l irf!.ill.1l!!i i, t!:ti. r:,rl ii.r-L
irt -'111;.1.111';' . (rtllf,r!.
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 9 of 17
Exhrhit A - Pac,iti('orp's Emissions Ileducticrn Plan
Novt:ruher l. 201 0
Page 3 o{'i0
120.W0
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t.i.000
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2005 - 2009 Actuul und 20 l0 - 2023 Projcctcd SO2 Emissions
PacifiCorp's Arir-onn, tjtah & \1:lorning Coal-l'ircd tinits
a-dale eftiisi0n! Iln
l0/lll2OlO to
r,rcl."t-da-r'l .t .r Fl
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2004- 2009.,\ctual nrrd 2010- 2023 Projectcd IOr [nrissious
PacifiCorp's Arizortn. l-!tlh & \\.vonring Coal-Fired L nits
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.c
c
Illr.tno
I i,l"ll(](]
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'I
( 10iO rrnsrxrnt havr bren.tlcslated !,ti!lt aqr,al yenr:io-ilaic amrs!sr, raie !l
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 10 of 17
W
iiriribit A - Pacifl('orp's Emissions Redttction Plan
Noi,cr-ubcr 2. 2010
Pagc 4 of' l0
Project Installation Schedule
Ernission reductiou proJccts ot'the nunrber and sizc clcscribcd abovc takc n'rany ysars to engineer,
plan and build. When cousidering a flcct tltc sizc ol" PacillCorp's, there is a practical linritatiorr
on available constrr.rcticlrr resources and labor. Tlrere is also a linrit cin tlre nurnbcr of units that
nray be takcn out of service at any given titne as rvell as the level of'construction activitics that
can hc suppoiled by the looal infi'astrlloturcs at ancl aroltnd these tacilitics, Such lirnitations
directly inrpact both the overalI timing of tltese projects as u,cll as their tirling in relation to eac]r
ottrcr. Adclitional cost ar)d construction tirning linritations include tlre loss of large generating
rcsources durirrg some parts of construction and thc associated impact on the reliability ot'
t'rciliCorp's clectrical system duririg thesc extendeti outages. [n othcr words. it is not practical.
and it is unduly expensive, to expect to build these ernission reduction projects alI al otrce or
even irr a compressed tirne period. 'llrc pressurc on cnrission rr'duction equipment ancl skilled
labor is likelv to bc exac:erbated hy'the sigrtificant eu'tission reductitxr rccluilcrnerrts nccessitated
by the Euvironursntal Protection Agcncy's Clcarr Air -lrausptirt Rulc rthiclt rccluircs enrirsitrn
reductions in Jl Easterr states iurd tlte Dr.striet o1'Columbia begiuning in l0l2 arrd 20l-t. Thc
Enr.ironu.lerrtal Protectiort Agency ltas incJicatcd tliat a sccond Transport Rule is likcll to be
issued irr 2t)ll. requinng adclitional reductions in the Eastem U.S. bcyorrrl tlrosc clleutivc in
2014. 't-he balancing,:l these conconls is rcllccted in tltc tinring r:l'PacitjCorp's crnissirin
rccl uct ion conr nr itt'nettts.
Priority of Emission Reductions
I,acifiCorp's initial focus has been on installing controls to reduce SO: ernissiuns ivlrich are ihc
rrrost sigSrificant contributors to regionul haze in thc rvcstcrn US. ln addition. PacitiC'orp
contiuucs to rely on tlre rapid inslalliltion ol'lo'"v NO. buniers to siqrtitluartllv rctluce NOx
eurissions. Also. the installation of trve SCRs (or sinrilar NOx'rcducing tcchnologrcs) rvrll be
cornplctcd by 2023 and reduce NOx eniissions even further. Paci fiCor1's comntitrneut also
includes thc installatiou of several bugitouses to control particulatc lllattcr curissions. For tlrosc
urrits *'hich utilize drv scrubbers. baghouses have the added benefit ol ir:rproving SO2 rcnroval.
Ba glrouses al so si gnifi cantly reduce rrlereurY eut issions.
ln addition to rcduciug clnissions at e.\isting ti:cilities, PacifiCoq: has rr.oit'lcd increasinq
cnrissions by adding rnore thau 1.400 megarvatts ol'retreu,able generation betrvecu 200(r untl
2010. tu tird,:r to meet growiug dcrlartd tbr clcctricity. PacitiCorp adclcd non-cnrittiriu rvind
gcneration to its porlfolicl at a cost olovcr S2 billion arrd has clismissed tr.rrlherconsiclclatit>n of'a
ncrv coal-{'Lrclccl unit.
E,nrission Rcductions nnd BAR't' Deacllines
As clcpictecl in lhe table iind charts at:ove. PacifiCt,rTr hcgau inrlllenrcllting its ertrissrtrrr rctlrrction
ctrrnnritrtrents in lt)05. This rvas rvcll altcacl of tltc eurission reductiou iinrclincs urrtli:r tlrc
rcgional haze rulcs u'hich recluirc B:\R'[ tu bs insl,alled rto liitcr than livc 1.'cars tollo*,ing
irpproval ol'thc applicable Regittnitl Haze SIl','firis also provides a graphic tlertrortstraliorr o['the
uoltstructior) sr:heclulc and othcr lintitatiorts dcscribed abovc. as PttcitlCorp n'as recluiled to bcqirr
installing ctltissir)n corrtrol prcl-iccls at sollre units carliel in orcler tt.r cornplclc pro.jccts irl otllcl'
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page11of17
Exhibit A - PaciiiCorp's En.lissious Reduction Plan
November 2, 2010
Page 5 of i0
units r.vithjrr thc llvc 1,cars a{ier SIP appror,al. The table above dcuroustrarcs tirat rnost of the
pro.jects io he built betri,ceu 2() lf) alrd 2014. likerrise, rvill be iustallcr-1 in advarrcc olthe recluiretl
co rn pl cti on rlate r-rnd er IIA RT rccl uirements.
Custorner Inrpacts
'l-lie tirllorving charts identity the tinring and magnitucle of the capital and O&N4 expenscs that
',r,iil bc incurrccl duc to tlie projecis identified in Tabte l. The c,harts identii\,:
I . Thc tiniing and magnitude of the capital costs.
2. "fhe O&\4 expcnses that rvill be incurrccl clue to these projects.
i. -l'hc cxpeuted annual costsl through 2023 that custourcrs will bc incur as a rcsurlt ot'these
sp'rcci fic 1:ollutiort control projects.
Cnpital Expenditurcs to Add Pollutiou Control Erluipnrcnt onPacifiCnrp's
Arizona_. Utah & \Y1'oming Conl-Iiirecl Units
\-1(X).1r{X)
s:00.000
s I (x).{t()0
r [,acifiCorp lras nrlcle evcry attcrnpt to llror.irte an accuratc estirlrirlc oltlre anticipatetl ioclcusr in rrnnual rc\.enuc
reriablcs suclr as interes( nrtes, irrllation lates, tliscoutrt ratrs. ciepruciation hr.cs. and [lnal crtrtstruclii:n crlsts arrtl
o|:e:r'tting arrcl nraintennncc c\pensL's thet rr,ill lrc considerccl a1 thc timc lhcsc plo-iccts acttiallv qo iultr ra(c hasc rrtd
'.i.ill irrllucncc the actual re\rcrruc rcquireruents lssof irtcd rriLh thesc'crrpital prrrjt'cts.
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 12 of 17
c
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====''l'lat .l a: aJ al al al .-l al al ct al al a, al rj al .l
\rcrr
Exhitlit A - PacifiCorp's Emissions Reduction Plarr
Novernber 2. 2010
Page (r of i0
s(n].()r{)
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lncrcascs In O&M Expenscs Due toAdditional Pollution Control liquipment
on Arizona, Utsh & W-vonring Coal-Fired Units
L
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Annunl Incrcnse to Customers Duc to Additional Pollution Control
Equipnren( on r\rizon0, Utuh & \Yl,oming Coal-Fircd Units
€F-'aJ=-al er
-==334rr tr al .r
crrSc-.,r-i
^t6laralalFr-lda{
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 13 of 17
I
/
/i:t;I'
i
ilrillliiiiiiIll
L:xlribit ;\ - l)iiciliCrrr"p's l:rrri.isirins Reducticrn l)larr
Nor curbcr l. lO l0
l)itgr' 7 ot' l()
,\s eln Irc sccrr iionr thc lrlcr,iot-ts e:har[s. Ihc lalc rrrcreascs ft,r PacillCor]r cr.rst()ln(:rs ilsil.()ciilirr4l
r.,illt l'lrcilr('r,rp-s c.nrissitrrt rcclucti(rn strittcgv alullc rvill bc signrl:carrt. In the irlcl'rt thlt
llircili(.'rrr'D is lr:qtrirutl l() iiucLllcriltc or adil lo tltc grlnrtrtcd L:l'rlis:i()rr rcduclirrrt Prir.ic'uLs" lltc uost
rnrl)uclri io oLrr t:usltrrl]cr',s clrr he tx|,:ctctl {o inuiuii-c.r irrcrcnrctrtirll\'. pilriiuulilt'l},a"- plarrt ()r.tli.tg,c
.chctlttlcs iu'ii rxlcrt(lt(l rtril tlrc itct:tl lirr skillcd l:tl'r,-,t'rit.iri ntirlerial ir)cr'.,.rr;*; irt lltu nr:iir tt:t'rr.
urclrrrqrrncrtt,'lltcsc ctr:;l irrr:rcil.'ccs tlo il,rl rrrirludc LrtlreI u(rsts e:il)cel((i t0 i.rc'rneurruil in tlru Irrture'
lrLil rrrrl linritr:tl l(r (jtL' ,\ltl.'hntcrii I I:
lttri)!r:lt,('illtrtitrri ol I t;tlt': l...r,ttil'l'crtl) )rlt'illctr lirt ttttt:titt!1 l-('uir!liill lt;t,,1 ttrtlt.rtt'cr'ttt't:l
.lLrlir',r, Ll;e l(r I :.-l'):-1 iit't.lcr lrlri,,il.
-i.
Il',u trrlrliti,irt r,1 Irlct c\.tfV c{.)rllril] L'(lLtillt-nunl uttrlr-'r' thu Ie(lt.lil'L'llrcltts trl tltr ili)c(,riliit'
nreiLri.rrv i\1,\('l- Ploi isions Prtcili('i,rli e.rtinli-t1r)s ilrrl S(rS nrillion irt .apiirrl n'ill lre
iucun'ctl lrr lttl5 rrtel irrrttral tipcralitrS rrxl)tnses rrrll irrclcri:;c lrr, \rlniillir,ri PCr'\'cilr Irr
c,rinpli,r.,iiir nrcrcLrt-\,r'ctlltr:iii.rir re(1trirc'lnr]nts. ln iirlr.litiort. rrntrcil.rllr.:il rt-'luliiliirtt Ir,
edtlress Ilr)n-ireieur'\, ltazrrrlorr:: lrir'pilllr-rt,rrrt (1"{.t,lts) cnris)i()lr-r nrr\ rcrllri!.e rigrtitiuurt
lttltliiirrrtirl rr'(lui:tions ol-SO.;. fls ir Irr:crlrsor lt, strllir|ic lclrl lrisl. iiortr r:ilri-i]..\li [' ririits
lhai ertrlcrtilr, tli) r"tcrt havc speciltc cr,rttrtrls t(r) rL'(tLrcL'S(-)- cnri.ssion:.
jlitigrrtrrr.g :rlrr! r-ritt[t,,1]iit. ( ()-" unrissi()ns. \\;lrilc Lonurcss ltrs nui )cl pirsstil
ri,rirPrt'l).'u-;ir c r'lrnt;itc ilrttti't' lcr:.r'lulitit:. in l,)cccrtihl'r l(t0tt. tlrc ..\rlrliriisinilor ol'tlir:
I 1,....,..., .., \ . .. .. ...., I l:...i:.. . ,l-.., ..-......1. ,.. :.. .i.r r,\ l \,rrlrrr rrl.l. I r"LLLtr\rtr -\I(lrL.\ lrr(lrl! it rlrl\,irl*: tll(tL LrLLrlll(rll.! .u,l:L\ lll trlr
ill]lrr'rr.llr(:ir'llir-i'rlc'ti llrt'irtrirlit lrc,.rltli lrr:tl'.'.i'llii|c \'r'i r'urrcrrl:ln(l lirl:rIi.''!ijrr(r'ir]i,,r'i:i.
liiivin_r t'nirrlu lht',ii-ullictl ''r:n,lur'lrenucrrt lintlirig." [:l).rr. r:surti thc iiir.rl ...r cerri',,)lrs! !.is
tailoring lLrlt'. til'[cctivr].l :ur.rrrv l. ll) Il. r',hielr .lt,ill rr:rluirc grccnll('r.rst lrirs (rrri\:iiins Il
bc ai-lclrcss.rd Lnrr-lcr PSD antJ -l-itlc V pcrmits'. l-ikcru isc. rnurrdatrir'_v lul)olling (li
-grccLrlir'rusc gls ullissi()r'ls lo lhc Ilrtvirontncrrtul Protctlit'n ,\[crrr:i' rrrl)rillr,'ri(:cr(i
hcgiiruiug irr .larrLr:rr'-v 2()l 0.
ln arjtlitiorr. tlrcrc,rrc ir nlnuhcr rr!'r'egiorrlil r'ogulirr\)r'\'rrritiltiros. inclu(l1n!l tht \\rcstci'n
(''lirrilrtt: Irritiirtirt' ilurl lrti.i\ irltitrtlrtcl'. irrrpi1.1 ["',it:ill('t,r'l-r's .'r,rrl-lirclu,l lrturittie:.
l':ltill( , rt'p \ :urruiirtr|tr.t. unltS lll'i": iltili,ac(l [ir :!'r'\'( uLt:;trll|l('r'i rti sil :tirtcs \\"\rii]iin..
l,lrilr',. [:1.1i1. \'r'11.sltur!ilor:. ()ietirrrt;utrl Clrlili:rniir. ('irliiirr'rri:r. \\'irslii:tll'r:r iri(] ()r(r.t()n irrLl
1'rrilt ie rIllts rri thc \\:L\tr't"rt (lirl:rtc Initrutit c. it c'\ntl)l'cltirtsirc ri:tlitrriul ulli,r't to futlucr.r
!'t'.:ctth,,tt:,c !iir( ettlssir!lt:r ir'' 15"',, heltrri li)(15 lcreis Lr. 2(lftt ii-it-oitllt il (illr-iili(l-irii(ir'
l'.)l.olfrilnl Llrilt iirultrtl,.:s thc cIcctricitl, 5s'.tn,' cuelt :llttu ltlr:i irnplcriteritetl st:.ltc-ltr cl
errrissir,rrs lucltrt lit,r'r Lrtrals. Citiilorniit. \\la.slrirrrllon an(l ()r'cll(rrr lriri e :rlsr'r rrr-lrrPietl
frccrrltOrtstr girs r]r'ni5sii)rrs pur'lirIi.nilncr: stJn(laItls li,r bltse loilrl clCttlrt'"il Lr\:nL'r'lLirill
l'L:s()Llrcc: r.!ri(lLlt'\'.ltic]r cririssitrns ur.r..I il(,1 L-t\c('c:(l l.lr)i] lli,tlli.ls,i{ (-()-,|r'r ri}r"L:i\',;t!t
l ltr' Lrr,. ifirnnlJr:l:l; l'tijl!. Ir,,rl
.,..1.:,,r r ,.: ir L, ',r,, ,,,r.i i
\!tLii.:\ lt::s ili)l \cl ilijl)ljrlr(J ll. ltr.'l',!i,.'il::trili;irtL, i!11'.\llirl
I : ii i :, ir:.tr. i-:i'(\
11{llli:lr5 li1 \l
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 14 of 17
Brhibit A - Paci tlC'or1:r's Enrissit-rns Reduction I'lan
November 2,2010
PageSofl0
hour. The emissions perfomrance standards ger:erally prohibit electrio utilities tiom
entering intcl long-temr financial cornmittnertts (e.g., rlew owl'lership investrnents.
rupg'ades, or uew or renerved contracts u'ith a tenrt of 5 or nrorc ),ears) unless the base
load generation supplied urder long-tenr finaucial cclmmitnrcuts conrply r.r,ith the
g:'eenhouse gas emissions perfonrance stanclards. While these requirements irave not
been irnplenrcuted in Wyorning, due to tlre treattnent of' PacitlCorp's generation on a
systenr-wide llasis (i.e.. electricity generated in lVyonring nray be deemed to be
consuurecl in Califbnria basecl on a rnulti-state protocol). PaciiiCorp's facilitics nray be
sublcct t<l ctut-oI'-state rcquirements.
5. RegLrlations associatu'c1 u'ith coal conrbustion tryproriucts. ln June 201 0, the
Environnrental Protection Agenc,v published a proposal to rcgulatc the disposal of coal
combustiou byproducts r"urder the l{esource Qonservation aud Recovery Act's Subtitlc C
or D. Unclcr-cithcr rcgr.rlalory sccnario, regulatcd cntities. inclucling PaciliColp, u,oulcl be
requirecl. at a urir.rirnuru; to retrofitiupgraclc or cliscontinuc utilization oIeristiug surface
iurpounclurents witllin live -\,ears atier the Envirorulental Protectiou Agency issues a tlnal
rule and state acloption of tl.re appropriate controlling regulaLions. [t is anticipatecl that tlre
requirenrents utrder the final rule rvill impose sig'nificant costs on PacitiCorp's coal-
fuelcd tncilities rvithjn the rtexl eight to tcn years.
6, l'he installatiou of signihcant atirounts of not generation. inclucling gas-fueled
generation atrcJ rcrtewablc resources.
'7. The addition of rnajor transnrission lines to sLll.rport the renewable resources and tlthcr'
aclrlecl generation.
8. Ir'rcreasirrg escalatior-r rates on tuel costs and other comnroclities
B.{.RT and Rcgional [Iaze Compliance
PacifiCorp finlly belicves tlrat tlre commitrnents descnt:eci above mcet the letter and intcrrt of thc
regional lraze rules. includiug the guidance provicled by the EPA knorvn as "Appendix Y." Tlre
regional haze program is a long-tcnl cffon u'ith long-tenn goals entling in 2064, It rnust be
approached flom that pcrspective. It rvas ne'u'er intended to require SCR on BART-eligible units
rvithin thc first five years of the prograrn. Rather, it calls 1''or a transition to lowel' emissiorrs
exactiy as PacifiCorp has implemented to date and as it has proposed going ftrnvirrd through
2023.
In its evaluationof emission reductions forregional haze purposes. thc'stateshould also consider
sevelal otlrer vurriables rvhich ivill significantly at'fect eurissions and costs over tlre next ten years.
'l"hese inclucle such thiugs as tltc det,clopment of neu' emission ctintrol tcchnology, anticipxted
rrcrv enrission l'ecluctiolr lcgislatiorr artd rules, the neri ozclne -stanclard, the onc hoLrr S()2 antl NOz
standarcJs. thc l;'M3.s slandar(i. ptrtcr.:tial CO3 r'egulation ancl costs, an adng 11eet. and chmgin-u
econontic ct:nclitious. All of tlicsc vtriables nratter"ancl rvill atlect the l<lng-tenn viLrbilirl,ot'eaclr
I)acrtiCorp coal unit anri rvill contribute to thc t'cduction of regional lrazc iu thc coursc ol'thr;
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 15 of 17
Exhibit A - PacillCorp's Emissions Rccluotion Plan
November 2,2010
Page 9 of l0
implementation of tliese programs. This, in tum, will affect the controls, costs and futtu'e
operational expectations associated with tlrese generating resources.
Conclusion
PacifiCorp has nradc a significant, loug-tenn comuritrnent to reducing enrissiorr.s firrnr its coal-
fuelcd facilities and requests that the AQD consider tlris conrrnitment as a reasonahle approach to
achicving ernission reductions in W,voming.
Exhibit No. 3
Case No. IPC-E-13-16
T. Harvey, IPC
Page 16 of 17
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Exhibit No. 3
Case No.lPC-E-13-16
T. Harvey, IPC
Page 17 of 17
@=ct .Y
SB
WYOMING STATB IMPLEMENTATION PLAN
RegionalHaze
Addressing Regional Haze Requirements for Wyoming Mandatory
Federal Class I Areas Under 40 CFR 51.309(g)
Grand Teton National Park
Yellowstone National Park
Bridger Wilderness
Fitzpatrick Wilderness
North Absaroka Wilderness
Teton Wilderness
Washakie Wilderness
January 7r20ll
Prepared By
The Wyoming Department of Environmental Quality
Air Quality Division
Herschler Building, 122 \Mest 25th Street
Cheyenne, Wyomin g 82002
Exhibit No. 4
Case No.|PC-E-13-16
T. Harvey, IPC
Page 1 of206
Chapter 1.
Chapter 2.
2.1
Table of Contents
Page
General Plan
Wyoming Class I Areas; Baseline, Natural and Current Visibility Conditions..3
Description of the Yellowstone Monitoring Site (YELL2) Class I Areas....................3
2.1.1 Grand Teton National Park........... ........3
2.1.2 TetonWilderness ...............5
2.1.3 Yellowstone National Park........... ........7
2.1.4 Monitoring Strategy and Location - YELL2 Monitoring Site.......................8
2.1.5 Assessment of Baseline, Natural and Current Conditions -YELL}
Class I Areas ....................10
Description of the North Absaroka Monitoring Site (NOABI) Class I Areas...........13
2.2.1 North Absaroka Wilderness. ...............13
2.2.2 Washakie Wilderness.............. ............15
2.2.3 Monitoring Strategy and Location - NOABI Monitoring Site....................16
2.2.4 Assessment of Baseline, Natural and Current Conditions - NOABI
Class I Areas ....................18
Description of the Bridger Monitoring Site (BRIDI) Class I Areas .......21
2.3.1 Bridger Wilderness............... ..............21
2.3.2 Fitzpatrick Wilderness ........................23
2.3.3 Monitoring Strategy and Location - BRIDI Monitoring Site......................24
2.3.4 Assessment of Baseline, Natural and Current Conditions - BRIDI
Class I Areas ....................26
2.2
2.3
Chapter 3. Pollutants Causing Visibility Impairment in Wyoming Class I Areas ...............29
Yellowstone National Park, Grand Teton National Park and Teton Wildemess. .......32
North Absaroka and Washakie Wildemess Areas ................35
Bridger and Fitzpatrick Wildemess Areas... ......37
Chapter 4. Statewide Emission Inventory .......................40
4.1 Introduction........... .......40
4.2 SO* Emission Inventory... ...............41
4.3 NO* Emission lnventory... ..............42
4.4 OC Emission Inventory... ................43
4.5 EC Emission Inventory... ................44
4.6 Fine PM Emission Inventory ..........45
4.7 Coarse PM Emission Inventory ......46
4.8 Ammonia Emission Inventory ........47
4.9 Inventories Utilized For Emissions Projections............... ........................47
4.10 PRP18b................ ......48
3.1
3.2
3.3
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 2 of 206
Chapter 5. Source Apportionment and Regional Haze Mode1ing............ ...........50
5.2
Overview... ...................50
5.1.1 Source Apportionment Analysis - PSAT and WEP... ...............50
5.1 .2 Regional Haze Modeling - CMAQ ........................51
Major Source Categories Contributing to Haze in Wyoming ..................53
5.2.1 PSAT Regional Contribution to Sulfate on20Yo Worst Days.....................54
5.2.2 PSAT Regional Contribution to Sulfate on20Yo Best Days........................57
5.2.3 PSAT Regional Contribution to Nitrate on20Yo Worst Days.....................61
5.2.4 PSAT Regional Contribution to Nitrate on20Yo Best Days........................64
5.2.5 WEP Potential Contribution to OC on20Yo Worst Days ............................67
5.2.6 WEP Potential Contribution to OC on20Yo Best Days ............70
5.2.7 WEP Potential Contribution to EC on20%o Worst Days.............................72
5.2.8 WEP Potential Contribution to EC on2lo/o Best Days.. ...........74
5.2.9 WEP Potential Contribution to Fine PM on 20% Worst Days....................76
5.2.10 WEP Potential Contribution to Fine PM on20Yo Best Days.....................78
5.2.11 WEP Potential Contribution to Coarse PM on 20% Worst Days..............80
5.2.12 WEP PotentialContribution to Coarse PM on 20YoBest Days.................82
CMAQ 2018 Projected Visibility Conditions................. ......84
5.3.1 CMAQ Modeling Breakdown by Pollutantfor20Yo Worst Days...............85
Best Available Retrofit Technology (BART) ...................89
5.3
Chapter 6.
Chapter 7.
6.1 Introduction.......... ........89
6.2 SOz: Regional SOz Milestone and Backstop Trading Program ..............90
6.3 Overview of Wyoming's BART Regulations .......................92
6.4 SIP BART Requirements From EPA's Regional Haze Rule.. .................92
6.5 Facility Analysis ..........99
6.5.1 FMC Wyoming Corp.- Granger Facility ..............99
6.5.2 FMC Wyoming Corp. - Green River - Westvaco Facility...........................99
6.5.3 GeneralChemical - Green River Works................. ................100
6.5.4 PacifiCorp - Jim Bridger Power Plant.......... .......102
6.5.5 PacifiCorp - Dave Johnston Power P|ant.......... ......................104
6.5.6 PacifiCorp - Naughton Power P1ant.......... ...........106
6.5.7 PacifiCorp - Wyodak Power P1ant.......... ............. 108
6.5.8 Basin Electric Power Cooperative - Laramie River Station......................109
7.1 Overview.............. ......1l3
7.2 Process for Establishing Reasonable Progress Goals .........114
7.3 Four Factor Analysis Performed for Wyoming Sources... .....................1 l5
7.3.1 Detailed Description of the Four Factors................. ...............I l6
7.3.2 Source Selection Process for Four Factor Analysis.... ............1l7
7.3.3 PacifiCorp Dave Johnston Electric Generating Station ..........1l8
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 3 of 206
7.4
7.5
7.6
7.3.4 Mountain Cement Company, Laramie Plant......... .................120
7.3.5 Oil and Gas Exploration and Production Field Operations ....123
309 SIP and 309(9) ....127
Setting Reasonable Progress Goa1s......... .........127
Demonstration That the RPGs for 20 Percent Best and Worst Days are
Reasonable .................128
Chapter 8.
8.1
8.1 .3
8.1.4
8.2 Required
8.2.t
Overview... .................132
8.1.1 Summary of all Anthropogenic Sources of Visibility Impairment
8.1.2
Considered in Developing the Long-Term Strategy..... ..........132
SummaryoflnterstateTransportandContribution.......... ......132
8.1.2.1 Other States' Class I Areas Affected by Wyoming Emissions...l32
8.1.2.2 Wyoming Class I Areas Affected by Other States, Nations
and Areas of the World........ ................135
Summary of Interstate Consultation................ ....138
Estimated Intemational and Global Contribution to Wyoming
Class I Areas .................138
Factors for the Long-Term Strategy..... ...............141
Emission Reductions Due to Ongoing Air Pollution Control Programs...l4l
8.2.1.1 New Source Review Program ...............141
8.2.1.1.1 Prevention of Significant Deterioration (PSD)
Program..... ..........141
8.2.1 .l .2 Minor Source BACT Program ..................142
8.2.1.2 Title V Operating Permit Program..... ....................-142
8.2.1.3 New Source Performance Standards (NSPS) ..........143
8.2.1.4 MACT - HAPs Program ....150
8.2.1.5 Phase I Visibility Rules - Wyoming Reasonably Attributable
Visibility Impairment Ru1es......... .........160
8.2.1.6 Ongoing Implementation of Federal Mobile SourceRegulations .....160
8.2.1.7 Ongoing Implementation of Programs to Meet PMro NAAQS..l6l
8.2.1.7.1 Nonattainment SIP (PMro) - City of Sheridan.............l6l
8.2.1.7.2 Natural and Uncontrollable Sources Program - Natural
Events Action P1an........... ......162
8.2.2 Measures to Mitigate the Impacts of Construction Activities ...................163
8.2.3 Emission Limitations and Schedules of Compliance ................................163
8.2.4 Source Retirement and Replacement Schedules.. ...................163
8.2.5 Agricultural and Forestry Smoke Management Techniques .....................164
8.2.6 EnforceabilityofWyoming'sMeasures................. ................165
8.3 AdditionalMeasures in the Long-Term Strategy ...............166
8.3.1 Future Federal Mobile Programs ......166
8.3.2 Efforts to Address Offshore Shipping.... ..............167
8.3.3 Long-Term Control Strategies for BART Facilities ...............168
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 4 of 206
lll
Chapter 9.
Chapter 10.
Chapter 11.
I l.t
tt.2
I 1.3
Chapter 12.
Chapter 13.
t 3.l
13.2
13.3
13.4
l3.s
8.3.4 Evaluation of Control Strategies for Sources Identified in the
Reasonable Progress - Four-Factor Analysis .......169
8.3.5 Oil and Gas ....................169
8.3.6 Projection of the Net Effect on Visibility ............170
OngoingMonitoringandEmissionlnventoryStrategy ..................178
Comprehensive Periodic Implementation Plan Revisions ...............................181
Wyoming Regional Haze SIP Development and Consultation Process..........182
State to State Consultation ..........182
State and Federal Land Manager Coordination .......... ......185
Tribal Consultation................ .....186
Determination of the Adequacy of the Existing Plan .......... .......... 187
Technical Information and Data Relied Upon in This PIan............................188
The WRAP and Technical Support.. ..............188
WRAP Committees and Work Groups ..........188
WRAP Forums...... ......................191
WRAP TSS........... ......................193
IMPROVE Monitoring ...............193
13.5.1 Background on IMPROVE Monitoring................. ...............193
Formula for Reconstructed Light Extinction.......... ..........194
Wyoming IMPROVE MonitoringNetwork .....................196
r 3.6
t3.7
List of Tables
Table 3-1. IMPROVE Monitor Aerosol Composition................. ...........30
Table 4.2-1. Wyoming SO* Emission Inventory - 2002 and 2018 .........41
Table 4.3- l . Wyoming NO* Emission Inventory - 2002 and 201 8 ................ ...........42
Table 4.4-1. Wyoming OC Emission Inventory -2002 and 2018 ..........43
Table 4.5-1. Wyoming EC Emission Inventory - 2002 and 2018 ..........44
Table 4.6-1. Wyoming Fine PM Emission lnventory -2002 and 2018........................................45
Table 4.7-1. Wyoming Coarse PM Emission Inventory -2002 and 2018.... .............46
Table 4.8-1. Wyoming Ammonia Emission Inventory -2002 and 2018.... ...............47
Table 4.9- l . Net Change From PRPI 8a to PRP l8b Emission lnventories ..............48
Table 5.3-1. CMAQ Modeling Results for 20Yo Worst Days and 20YoBest Days for
Wyoming Class I Areas ...............85
Table 5.3.1-1. Pollutant Breakdown on20%o Worst Days for Yellowstone NP, Grand
Teton NP, and Teton Wildemess Area.......... ..................86
Table 5.3.l-2. Pollutant Breakdown on20Yo Worst Days for North Absaroka and
Washakie Wilderness Area.......... .................87
lv Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 5 of 206
Table 5.3. I -3. Pollutant Breakdown on 20Yo Worst Days for Bridger and Fitzpatrick
Wildemess Areas .......................88
Table 6.2-1. Regional Sulfur Dioxide Emissions and Milestone Report Summary.....................90
Table 6.2-2. Visibility - Sulfate Extinction On1y........... ......91
Table 6.4-1. BART Determinations for Wyoming Sources ...................94
Table 7.2-1. 20% Best and Worst Days Baseline, Natural Conditions, and Uniform Rate
of Progress Goal for Wyoming Class I Areas......... .........1l5
Table 7.3.3-1. Estimated Costs of Potential Emission Control Devices for Two Boilers
attheDaveJohnstonElectricGenerationStation....... ......................1l9
Table 7.3.3-2. Estimated Energy and Non-Air Environmental Impacts of Potential
Emission Control Devices for Two Boilers at the Dave Johnston Electric
Generating Station ..................120
Table 7 .3 .4-l . Estimated Costs of Potential Emission Control Devices for One Cement
Kiln at the Mountain Cement Company, Laramie P1ant........... .......121
Table 7.3.4-2. Estimated Energy and Non-Air Environmental Impacts of Potential Emission
Control Devices for Kiln #2 atthe Mountain Cement Company, Laramie
P1ant.......... ...........123
Table 7.3.5-1. Estimated Costs for Oil and Gas Exploration and Production Equipment..........l26
Table 7.5-1. Reasonable Progress Goals for20Yo Worst Days and 20YoBest Days for
Wyoming Class I Areas ..............128
Table 8.1 .2.1-1. Nitrate Contribution to Haze in Baseline Years .........134
Table 8.1 .2.1-2. Sulfate Contribution to Haze in Baseline Years......... ...................135
Table 8.3.6-1. Class I Area Visibility Summary for YELL2 on 20Yo Worst Days .......... ..........171
Table 8.3.6-2. Class I Area Visibility Summary for NOABI on20Yo Worst Days .......... .........172
Table 8.3.6-3. Class I Area Visibility Summary for BRIDI on20%o Worst Days.....................173
Table 8.3.6-4. Class I Area Visibility Summary for YELL2 on20Yo Best Days ....174
Table 8.3.6-5. Class I Area Visibility Summary for NOABl on20Yo Best Days......................175
Table 8.3.6-6. Class I Area Visibility Summary for BRIDI on20Yo Best Days........................176
Table 9-1. The Wyoming IMPROVE Monitoring Network................. ...................179
Table 13.7-1. The Wyoming IMPROVE MonitoringNetwork.... ........196
List of Figures
Figure 2.1-1. NationalParks and Wildemess Areas in Wyoming (Class I Areas).........................3
Figure 2.1.1-1. Mormon Row........... ..................3
Figure 2.1.1-2. Grand Teton NP Class I Boundary. ...............4
Figure 2.1.2-1. Gravel Creek in 1996. Burned in giant Huck Fire of 1988 ................5
Figure 2.1.2-2. Pendergraft Peak l99l ...............5
Figure 2.1.2-3. Teton Wilderness Class I Boundary... ...........6
Figure 2.1.3-1. Hot Pool Near Red Cone Geyser................ .....................7
Figure 2.1.3-2. Yellowstone National Park 8oundary............. .................8
Figure 2.1.4-1. YELLZ Monitoring Site Location................ ....................9
Figure 2.1.4-2. Looking South Toward the YELL2 Monitor .................10
Figure 2.1.5-1. YELL2 Monitor - Baseline Best Days ........1I
Figure 2.1.5-2. YELLZ Monitor - Baseline Worst Days.......... ..............1I
Figure 2.1.5-3. YELLZ Monitor - Natural Best Days.. ........12
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 6 of206
Figure 2.1.5-4. YELLZ Monitor - Natural Worst Days.......... ................12
Figure 2.2.1-1. Pilot and Index Peaks ...............13
Figure 2.2.1-2. North Absaroka Wildemess Boundary .......14
Figure 2.2.2-1. Piney Creek With Part of Carter Mountain at Head of Canyon.. ......15
Figure 2.2.2-2. Washakie Wildemess Class I Area Boundary............. .....................16
Figure 2.2.3-1. NOABI Monitoring Site............ .................17
Figure 2.2.3-2. Looking South Toward the NOABI Monitor ................18
Figure 2.2.4-1. BRIDI Monitor - Baseline Best Days.. .......19
Figure 2.2.4-2. BRIDI Monitor - Baseline Worst Days.......... ...............19
Figure 2.2.4-3. BRIDI Monitor - Natural Best Days ..........20
Figure 2.2.44. BRIDI Monitor - Natural Worst Days.......... .................20
Figure 2.3.1-1. Slide Lake........... ......................21
Figure 2.3.1-2. Bridger Wilderness Monitoring Site and Partial Boundary.. ............22
Figure 2.3.1-3. Bridger Wilderness Boundary... ..................22
Figure 2.3.2-1. The Wind Rivers From the Wind River Indian Reservation .............23
Figure 2.3.2-2. Fitzpatrick Wilderness Class I Boundary... ....................24
Figure 2.3.3-1. BRIDI Monitoring Site............ ...................25
Figure 2.3.3-2. Looking North Toward BRIDI Monitor..... ...................25
Figure 2.3.4-1. BRIDI Monitor - Baseline Best Days.. .......27
Figure 2.3.4-2. BRIDI Monitor - Baseline Worst Days.......... ...............27
Figure 2.3.4-3. BRIDI Monitor - Natural Best Days ..........28
Figure 2.3.4-4. BRIDI Monitor - Natural Worst Days.......... .................28
Figure 3-1. Light Extinction by Pollutant Species for Wyoming Class I Areas ZUo/oBest
Days (2000-2004) .......31
Figure 3-2. Light Extinction by Pollutant Species for Wyoming Class I Areas 20% Worst
Days (2000-2004) .......32
Figure 3.1-1. Yellowstone IMPROVE Site - Average Pollutant Species Contribution to
20%oBest and 20o/o Worst Days Baseline (2000-2004) ............. ..........33
Yellowstone IMPROVE Site - Monthly Average Pollutant Species Variation
for All Days Sampled During the Baseline Period (2000-2004)............................33
Yellowstone IMPROVE Site - Pollutant Species Variation for All Days
Sampled in2004 ......34
Yellowstone IMPROVE Site - Baseline Worst Day Aerosol Composition
Compared to Visibility Improvement Needed by 2018 &2064.............................34
North Absaroka IMPROVE Site - Average Pollutant Species Contribution to
20YoBest and20Yo Worst Days Baseline (2000-2004) ............. ..........35
North Absaroka IMPROVE Site - Monthly Average Pollutant Species
Variation for All Days Sampled During the Baseline Period (2000-2004)............36
North Absaroka IMPROVE Site - Pollutant Species Variation for All Days
Sampled in2004 ......36
North Absaroka IMPROVE Site - Baseline Worst Day Aerosol Composition
Compared to Visibility Improvement Needed by 2018 &2064.............................37
Bridger IMPROVE Site - Average Pollutant Species Contributionto20Yo
Best and 20% Worst Days Baseline (2000-2004)............. ...................38
Bridger IMPROVE Site - Monthly Average Pollutant Species Variation for
All Days Sampled During the Baseline Period (2000-2004)..................................38
Figure 3.1-2.
Figure 3.1-3.
Figure 3.1-4.
Figure 3.2-1.
Figure 3.2-2.
Figure 3.2-3.
Figure 3.2-4.
Figure 3.3-1.
Figure 3.3-2.
vt Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 7 of 206
Figure 3.3-3. Bridger IMPROVE Site - Pollutant Species Variation for All Days Sampledin2004 .....................39
Figure 3.3-4. Bridger IMPROVE Site - Baseline Worst Day Aerosol Composition
ComparedtoVisibilitylmprovementNeededby20lS &2064.............................39
Figure 5.2.1-1. PSAT Sulfate Contribution at Yellowstone NP, Grand Teton NP, and Teton
Wilderness on2|Yo Worst Visibility Days.......... ...........55
Figure 5.2.1-2. PSAT Sulfate Contribution at North Absaroka Wilderness and Washakie
Wilderness Areas on20o/o Worst Visibility Days.......... ....................56
Figure 5.2.1-3. PSAT Sulfate Contribution at Bridger Wilderness and Fitzpatrick Wildemess
Areas on2Uo/o Worst Visibility Days.......... ....................57
Figure 5.2.2-1. PSAT Sulfate Contribution at Yellowstone NP, Grand Teton NP, and Teton
Wilderness Area on 20%oBest Visibility Days.......... ........................59
Figure 5.2.2-2. PSAT Sulfate Contribution at North Absaroka Wilderness and Washakie
Wilderness Areas on20Yo Best Visibility Days .............60
Figure 5.2.2-3. PSAT Sulfate Contribution at Bridger Wildemess and Fitzpatrick Wilderness
Areas on20Yo Best Visibility Days .............61
Figure 5.2.3-1. PSAT Nitrate Contribution at Yellowstone NP, Grand Teton NP, and Teton
Wildemess Area on 20% Worst Visibility Days.......... .....................62
Figure 5.2.3-2. PSAT Nitrate Contribution at North Absaroka Wilderness and Washakie
Wilderness Areas on20Yo Worst Visibility Days.......... ....................63
Figure 5.2.3-3. PSAT Nitrate Contribution at Bridger Wilderness and Fitzpatrick Wildemess
Areas on2UYo Worst Visibility Days.......... ....................64
Figure 5.2.4-1. PSAT Nitrate Contribution at Yellowstone NP, Grand Teton NP, and Teton
Wilderness Area on 20o/oBest Visibility Days.......... ........................65
PSAT Nitrate Contribution at North Absaroka Wilderness and Washakie
Wilderness Areas on20Yo Best Visibility Days .............66
PSAT Nitrate Contribution at Bridger Wildemess and Fitzpatrick Wilderness
Areas onZUYo Best Visibility Days .............67
WEP Potential Contribution to OC at Yellowstone NP, Grand Teton NP, and
Teton Wildemess Area on 20% Worst Visibility Days.......... ..........68
WEP Potential Contribution to OC at North Absaroka Wildemess and
Washakie Wilderness Areas on20o/o Worst Visibility Days...............................69
WEP Potential Contribution to OC at Bridger Wilderness and Fitzpatrick
Wilderness Areas on20Yo Worst Visibility Days.......... ...................69
WEP Potential Contribution to OC at Yellowstone NP, Grand Teton NP, and
Teton Wilderness Area on 20YoBest Visibility Days.......... .............70
WEP Potential Contribution to OC at North Absaroka Wilderness and
Washakie Wilderness Areas on20Yo Best Visibility Days..... ..........71
WEP Potential Contribution to OC at Bridger Wildemess and Fitzpatrick
Wildemess Areas onZ0Yo Best Visibility Days ............71
WEP PotentialContribution to EC at Yellowstone NP, Grand Teton NP, and
Teton Wildemess Area on 20% Worst Visibility Days.......... ..........72
WEP Potential Contribution to EC at Nonh Absaroka Wilderness and
Washakie Wilderness Areas on20Yo Worst Visibility Days...............................73
WEP Potential Contribution to EC at Bridger Wilderness and Fitzpatrick
Wilderness Areas on20Yo Worst Visibility Days.......... ...................73
Figure 5.2.4-2.
Figure 5.2.4-3.
Figure 5.2.5-1.
Figure 5.2.5-2.
Figure 5.2.5-3.
Figure 5.2.6-1.
Figure 5.2.6-2.
Figure 5.2.6-3.
Figure 5.2.7-l .
Figure 5.2.7-2.
Figure 5.2,7-3.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 8 of 206
vll
Figure 5.2.10-2.
Figure 5.2.10-3.
Figure 5.2.1t-1.
Figure 5.2.11-2.
Figure 5.2.11-3.
Figure 5.2.8-1. WEP Potential Contribution to EC at Yellowstone NP, Grand Teton NP, and
Teton Wilderness Area on 20YoBest Visibility Days.......... .............74
Figure 5.2.8-2. WEP Potential Contribution to EC at North Absaroka Wilderness and
Washakie Wildemess Areas on20Yo Best Visibility Days..... ..........75
Figure 5.2.8-3. WEP Potential Contribution to EC at Bridger Wildemess and Fitzpatrick
Wilderness Areas on20Yo Best Visibility Days ............75
Figure 5.2.9-1. WEP Potential Contribution to Fine PM at Yellowstone NP, Grand Teton
NP, and Teton Wilderness Area on 20% Worst Visibility Days.........................76
Figure 5.2.9-2. WEP Potential Contribution to Fine PM at North Absaroka Wilderness and
Washakie Wilderness Areas on20Yo Worst Visibility Days...............................77
Figure 5.2.9-3. WEP Potential Contribution to Fine PM at Bridger Wilderness and
Fitzpatrick Wilderness Areas on20o/o Worst visibility Days..............................77
Figure 5.2.10-1. WEP Potential Contribution to Fine PM at Yellowstone NP, Grand Teton
NP, and Teton Wildemess Area on 20% Best Visibility Days..........................78
WEP Potential Contribution to Fine PM at North Absaroka Wilderness and
Washakie Wilderness Areas on2\Yo Best Visibility Days..... ........79
WEP PotentialContribution to Fine PM at Bridger Wilderness and
Fitzpatrick Wilderness Areas on20Yo Best Visibility Days ...........79
WEP Potential Contribution to Coarse PM at Yellowstone NP, Grand Teton
NP, and Teton Wildemess Area on 20% Worst Visibility Days.......................80
WEP Potential Contribution to Coarse PM at North Absaroka Wildemess
and Washakie Wildemess Areas on 20Yo Worst Visibility Days ......................8 I
WEP Potential Contribution to Coarse PM at Bridger Wildemess and
Fitzpatrick Wildemess Areas on20Yo Worst Visibility Days...........................81
Figure 5.2.12-1. WEP Potential Contribution to Coarse PM at Yellowstone NP, Grand Teton
NP, and Teton Wildemess Area on 20% Best Visibility Days..........................82
Figure 5.2.12-2. WEP Potential Contribution to Coarse PM at North Absaroka Wildemess
and Washakie Wildemess Areas on20Yo Best Visibility Days.........................83
Figure 5.2.12-3. WEP Potential Contribution to Coarse PM at Bridger Wildemess and
Fitzpatrick Wilderness Areas on20Yo Best Visibility Days ...........84
Figure 5.3.1-1. Glide Slope by Pollutant on2Uo/o Worst Days for Yellowstone NP,
Grand Teton NP, and Teton Wilderness Area.......... ........................86
Figure 5.3.1-2. Glide Slope by Pollutant on20Yo Worst Days for North Absaroka and
Washakie Wilderness Areas .......................87
Figure 5.3. I -3. Glide Slope by Pollutant on 20Yo Worst Days for Bridger and Fitzpatrick
Wilderness Areas .....................88
Figure 6.5.8-1. Additional Cumulative NO* Reductions From Wyoming BART Sources........l l2
Figure 7 .6-l . Time Series Plot by Pollutant on 20Yo Worst Days for Yellowstone NP,
Grand Teton NP, and Teton Wildemess Area.......... ......130
Figure 7.6-2. Time Series Plot by Pollutant on20Yo Worst Days for North Absaroka
Wilderness and Washakie Wilderness Areas..... .............131
Figure 7.6-3. Time Series Plot by Pollutant on20Yo Worst Days for Bridger and Fitzpatrick
Wilderness Areas ......................131
Figure 8. I .2. I - L Wyoming, South Dakota, Montana, Idaho, Utah, Colorado and North
Dakota Class I Areas......... .....................133
Figure 8.3.6-7. Additional Cumulative NO* Reductions From Wyoming Sources....................177
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 9 of 206
vlll
Figure 9-1. Links to Site Locations and Monitors............... .................179
Figure I l.l-1. Regional Planning Organizations............... ...................185
Figure 13.5.1-1. Schematic of the IMPROVE Sampler Showing the Four Modules
With Separate Inlets and Pumps ..............194
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 10 of206
lx
CHAPTER I
GENERAL PLAI\ PROVISIONS
Section l694 of the Clean Air Act establishes a national goal for protecting visibility in
Federally-protected scenic areas. These Class I areas include national parks and wilderness
areas. Regional haze is a type of visibility impairment caused by air pollutants emitted by
numerous sources across a broad region. On July 1,1999, the Environmental Protection Agency
(EPA) issued regional haze rules to comply with requirements of the Clean Air Act. Under 40
CFR 51.308, the rule requires the State of Wyoming to develop State Implementation Plans
(SIPs) which include visibility progress goals for each of the seven Class I areas in Wyoming, as
well as emission reduction strategies and other measures to meet these goals. Under 40 CFR
51.309, the rule also provided an optional approach to Wyoming and eight other westem states to
incorporate emission reduction strategies issued by the Grand Canyon Visibility Transport
Commission (GCVTC) designed primarily to improve visibility in l6 Class I areas on the
Colorado Plateau.
On December 29,2003, the State of Wyoming submitted a visibility SIP to meet the
requirements of 40 CFR 51.309. The 2003 309 SIP and subsequent revisions to the 309 SIP
address the first phase of requirements, with an emphasis on stationary source SOz emission
reductions and a focus on improving visibility on the Colorado Plateau. In the 2003 submittal,
Wyoming committed to addressing the next phase of visibility requirements and additional
visibility improvement in Wyoming's seven Class I areas by means of a State Implementation
Plan meeting the requirements in 309(9).
Since the 2003 submittal of the 309 SIP, EPA has revised both 40 CFR 51.308 and 309 in
response to numerous judicial challenges. As a result of revisions to the Federal rules, the State
of Wyoming submitted revisions to the December 29, 2003, 309 SIP under separate cover, on
November 21,2008.
This 309(9) SIP submission serves as a supplement to the 309 SIP submittal. Pursuant to the
requirements of 51.309(g), the State of Wyoming submits this Plan with: a demonstration of
expected visibility conditions for the most impaired and least impaired days at the additional
mandatory Class I areas; provisions for establishing reasonable progress goals for Wyoming's
seven Class I areas complying with 51.308(dXl)-(4); long-term strategies that build upon
emission reduction strategies developed in the first 309 SIP submittal; and finally provisions to
address long-term strategies and Best Available Retrofit Technology (BART) requirements for
stationary source Particulate Matter (PM) and Nitrogen Oxide (NOJ emissions pursuant to
51.308(e).
The State of Wyoming commits to participate in a Regional Planning Process with Alaska,
Arizona, California, Colorado, Idaho, Montana, New Mexico, North Dakota, Oregon, South
Dakota, Utah, and Washington, and commits to continue participation through future SIPs. The
Regional Planning Process describes the process, goals, objectives, management and decision
making structure, deadlines for completing significant technical analyses and developing
emission management strategies and a regulation implementing the recommendations of the
regional group. All Western Regional Air Partnership (WRAP) Work Plans and the WRAP
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page l't of 206
2008-2012 Strategic Plan, which document the Regional Planning Process, are contained in
Chapter I of the Wyoming Technical Support Document (TSD).
Pursuant to the Tribal Authority Rule, any Tribe whose lands are surrounded by the State of
Wyoming have the option to develop a regional haze TIP for their lands to assure reasonable
progress in the seven Class I areas in Wyoming. As such, no provisions of this Implementation
Plan shall be construed as being applicable to Indian Country.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 12 ot 206
CHAPTER 2
WYOMING CLASS I AREAS; BASELINE, NATIJRAL AIID
CURRENT VISIBILITY CONDITIONS
2.1 Description of the Yellowstone Monitoring Site (YELL2) Class I Areas
The monitoring site designated as "YELL2" is the representative regional haze monitoring
station for three Wyoming Class I areas (Grand Teton National Park, Yellowstone National Park
and Teton Wildemess). Each of these Class I areas are described below.
Figure 2.1-1. National Parks and Wilderness Areas in Wyoming (Class I Areas)
(ttttp:Zwww.cona.*i.ea
2.1.1 Grand Teton National Park
Figure 2.1.1-1. Mormon Row (Courtesy of National Park Service)
Exhibit No. 4
Case No.IPC-E-13-16
T. Harvey, IPC
Page 13 of206
Grand Teton National Park occupies 309,995 acres along the Teton Range and adjacent Jackson
Lake. The Teton Range borders the west side of the National Park, with elevations exceeding
12,000 feet, and 13,770 feet at the summit of the Grand Teton. The Teton Range, a 4O-mile-long
mountain front, was formed from earthquakes that occurred over the past 13 million years along
a fault line. The eastern half of the Park consists of Jackson Lake and valley of the upper Snake
River. Where the Snake River exits the Park at the south boundary, the elevation is the lowest at
6,800 feet. The Park is adjacent to the Teton Wildemess to the northeast and is 6 miles south of
Yellowstone National Park and the headwaters of the Snake River (Figure2.l-l\. Seven glacial
lakes lie at the base of the range, while over 100 alpine lakes can be found in the backcountry.
Elk, moose, mule deer, bison, pronghorn and black bears can be found in the Park. Grizzlies can
also be found, but are located in more remote areas. Over 300 species of birds, including bald
eagles, peregrine falcons and trumpeter swans can be observed in the Park.
Logcnd
'- - Classl Eotndary
r ll0ntah Peaks
H tekos erd RiYBrs
Ecvdon
lrGr3
ffi sae- r,zsz
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Figure 2.1.1-2. Grand Teton NP Class I Boundary
(hup://www.coha.dri.edu/images/clipart/wy_20km_terrain_grandteton jpg)
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey,lPC
Page 14 of 206
2.1.2 Teton Wilderness
Figure 2.1.2-1. Gravel Creek in 1996. Burned in giant Huck Fire of 198E. (Courtesy of Ralph Maughan)
(.htto://www. forwolves.orgy'ral oh/wpages/tetonwld. htm)
Figure 2.1.2-2. Pendergraft Peak l99l (Courtesy of U.S. Forest Service)
fttto:/ wvw.fsvisimages )
The Teton Wilderness encompasses 585,468 acres which straddle the Continental Divide in
western Wyoming. It is bordered by Yellowstone National Park to the north, Grand Teton
National Park to the west, and the Washakie Wilderness to the east (Figure 2.1-l). Elevations
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 15 of 206
range from 7,500 to 9,675 feetwest of the Continental Divide, while east of the Continental
Divide elevations are generally higher with the summit of Younts Peak reaching 12,165 feet. At
Two Ocean Pass, Two Ocean Creek straddles the Continental Divide, sending waters to both the
Atlantic and the Pacific Oceans. As with Grand Teton National Park, elk, moose, mule deer,
bison, pronghorn and black bears can be found in the Teton Wildemess. Bighorn sheep,
mountain lions, wolves, grizzlies and at least 75 other mammal species are also found here, as
well as over 300 species of birds and 30 species of fish.
Lcgcnd
qassl Boundily
4 ilq.mlalnPealG
m lrkes erd RlYsrs
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Exhibit No.4
Case No. IPGE-13-16
T. Harvey, IPC
Page 16 of206
Figure 2.1.2-3. Teton \Yilderness Class I Boundary
(nttp:llwww.cona.*i.eaU
2.1.3 Yellowstone National Park
(http://www.nps.gov/archive/yell/slidefile/thermalfeatures/hotsprinssteffaces/others/Images/06202 j oe)
Yellowstone National Park became the world's first national park on March l, 1872, and
occupies 2,221,766 acres in northwestern Wyoming, overlapping into Montana and Idaho
(Figure 2.1-l). The highest elevation is I1,358 feet at the summit of Eagle Peak on the
southeastern Park boundary, while the lowest elevations (5,314 feet) are found where the
Yellowstone River exits the Park on the north boundary. Yellowstone Lake is the largest high-
altitude lake in North America and is centered over the Yellowstone Caldera, the largest
supervolcano on the continent. The caldera, considered an active volcano, has erupted several
times in the last two million years. Fifty percent of the world's geothermal features are in
Yellowstone, fueled by this ongoing volcanic activity. Wildlife abounds in the Park, with the
more common species being elk, bison, grizzlies and wolves . [n2007, approximately 3,151,373
people visited Yellowstone National Park, bringing the total number of visitors to over
142,681,000 since the park opened in 1872.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 17 of206
Figure 2.1.3-1. Hot Pool Near Red Cone Geyser (Courtesy National Park Service)
f1_*'f-i1"- O
kdtu krt,u
'66ffib6 q|ft#EB.*drfrM- @ffidB@tuL+.b d6rryGEddibrr*tub rr-@btutEtffidE* ibhdlilht.S-F rdrftd*
Figure 2.1.3-2. Yellowstone National Park Boundary (Courtesy of National Park Service)
(http ://www. nps. gov/carto/PDFA(ELLmap2.pdO
2.1.4 Monitoring Strategy and Location - YELL2 Monitoring Site
The TMPROVE site designated as the monitor representing Grand Teton National Park, Teton
Wilderness and Yellowstone National Park is YELL2. The Wyoming Department of
Environmental Quality, Air Quality Division (the Division), considers the YELL2 site as
adequate for assessing reasonable progress goals of the three above-mentioned Class I areas and
no additional monitoring sites or equipment are necessary at this time.
The Air Quality Division routinely participates in the IMPROVE monitoring program by
attending Westem States Air Resources Council (WESTAR) and Western Regional Air
Partnership (WRAP) meetings and maintaining memberships in both organizations.
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 18 of206
YELL? is located in central Yellowstone National Park near the north shore of Yellowstone
Lake. It is 37 miles north of Grand Teton National Park, across the Continental headwaters
divide between the Yellowstone River and Snake River watersheds. YELL2 is 30 miles north
and west of the nearest Teton Wildemess boundary. The YELL2 site elevation is 7,954 feet,
which is 220 feet above Yellowstone Lake.
The nearest metropolitan area to the YELL2 monitor, Billings, Montana (over 149,650
population), is situated approximately 124 miles northeast of the monitor. The metropolitan area
of Boise, Idaho (over 635,450 population) lies approximately 295 miles to the southwest of the
monitor and the metropolitan area of Salt Lake City, Utah (over 1,099,000) is located
approximately 273 miles to the southwest.
Lcgcnd
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Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey,IPC
Page 19 of206
Figure 2.1.4-1. YELL2 Monitoring Site Location
Figure 2.1.4-2. Looking South Toward the YELL2 Monitor
(http://vista.cira.colostate.edu/viewsAileb/SiteBrowser/SiteBrowser.aspx)
2.1.5 Assessment of Baseline, Natural and Current Conditions - YELL2 Class I Areas
Natural visibility represents the visibility condition that would be experienced in the absence of
human-caused impairment. Based on EPA guidance, Grand Teton National Park, Teton
Wilderness and Yellowstone National Park Class I areas have an established natural visibility of
0.43 deciviews for the 20 percent best days and 6.44 deciviews for the 20 percent worst days.
This is based on on-site data at the YELL2 IMPROVE monitoring site.
Baseline visibility is determined from the YELL2 monitoring site (located in central Yellowstone
Park) for the 20 percent best and 20 percent worst days for the years 2000 through 2004 as
specified in the Regional Haze regulations under 40 CFR 51.308(dx2)(i). The baseline visibility
for Grand Teton National Park, Teton Wilderness and Yellowstone National Park Class I areas is
2.58 deciviews for the 20 percent best days and 1 1.76 deciviews for the 20 percent worst days,
which, for this first SIP submittal, is also the same as the current visibilitv. These best and worst
20 percent conditions are also calculated based on EPA guidance. This technical information
was obtained from the "Haze Planning" section ofthe Westem Regional Air Partnership
(WRAP) Technical Support System (TSS) by choosing the "Monitoring" section followed by the
"Deciview Glide Slope" information at http://vista.cira.colostate.edu/tss/. Further description of
this technical information can be found in Chapter 13.
Photographs representing similar visibility conditions on best and worst days for baseline and
natural conditions are included in Figures 2.1.5-l through 2.1.5-4.
Exhibit No. 4
Case No.IPC-E-13-16
T. Harvey, IPC
Page 20 of 206
l0
Figure 2.1.5-1. YELL2 Monitor - Baseline Best Days
htto://vista.cira.colostate.edu./Datawarehouse/IMPROVE/Data/PhotoVYELL/start.htm
t!(tl"*'
Baseline Best Days
Msta Reference: Avalanche Peak
(Yellowstone National Park)
Photo Taken at 9:00 AM
Haze lndex (Ht1= 3 Deciviews
B"rt = 14 Mm-l
Msual Range = 280 kml174 mi
Baseline Worst Days
Vista Reference: Avalanche Peak
(Yellowstone National Park)
Photo Taken at 9:00 AM
Haze lndex (Ht; = 12 Deciviews
B"x = 33 Mm-1
Visual Range = 12O km/75 mi
Figure 2.1.5-2. YELL2 Monitor - Baseline Worst Days
htto://vista.cira.colostate.edu./Datawarehouse/IMPROVE/Data/Photos/YELL/start.htm
ll Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 21 ot 206
Figure 2.1.5-3. YELL? Monitor - Natural Best Diys
htto://vista.cira.colostate.edu/DatawarehouseAMPROVE/Data/PhotoVYEll/start.htm
Natural Best Days
Msta Reference: Avalanche Peak
(Yellowstone National Park)
Photo Taken at 9:00 AM
Haze lndex (Ht1= 0 Deciview
B"*t = 10 Mm-1
Msual Range = 390 kml242mi
Natural Worst Days
Vista Reference: Avalanche Peak
(Yellowstone National Park)
Photo Taken at 9:00 AM
Haze lndex (Ht; = 6 Deciviews
B"n = 18 Mm-1
Msual Range = 220 km/137 mi
Figure 2.1.5-4. YELL2 Monitor - Natural Worst Days
http://vista.cira.colostate.edu/Datawarehouse/IMPROVE/Data/Photos/YEll/start.htm
Exhibit No. 4
Case No.|PC-E-13-16
T. Harvey,lPC
Page22ot20f5
t2
2.2 Description of the North Absaroka Monitoring Site (NOABI) Class I Areas
The monitoring site designated as'NOABl" is the representative regional haze monitoring
station for two Wyoming Class I areas (North Absaroka Wilderness and Washakie Wilderness).
Each of these Class I areas are described below.
2.2.1 North Absaroka Wilderness
-lt---
Flgure 2.2.1-1. Pilot and Index Peaks (Courtesy of Wikipedia and National Park Service)
(http ://commons.wikimedia.org/wikifu ser:MONGO/Public DomairLlmages)
The North Absaroka Wilderness is part of the Greater Yellowstone Area of northwestern
Wyoming, located along the northeastern boundary of Yellowstone National Park, east of the
Continental Divide, and occupies 350,488 acres (Figure 2.1-l). Elevations range from
approximately 7,200 feet to more than 10,000 feet on several summits, with the highest elevation
being 12, 216 feet on Dead Indian Peak. The terrain is very rugged and mountainous and
dissected by numerous creeks. Only a few lakes exist, but the streams contain cutthroat, brown,
brook, and rainbow trout. The wilderness is home to grizzly bears, and big-game hunters come
by the hundreds for bighorn sheep, elk, and moose. Marmots and pikas dominate many of the
talus slopes.
Exhibit No. 4
Case No. IPC-E-1&'16
T. Harvey,lPC
Page 23 of 206
l3
Figure 2.2.1-2. North Absaroka Wilderness Boundary
http://www.publiclands.org/explore/quadrant map.php?id:1560&site-name:North%o20Absaroka%o20Wilderness&
quad:WY_O2&PHPSE S SID:23 cfebTc9
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 24 ol 206
t4
2.2.2 W ashakie Wilderness
Figure 2.2.2-1. Piney Creek With Part of Carter Mountain at Head of Canyon (Courtesy
of Ralph Maughan)
(htto ://www.forwolves.or8/ralph/wpaees/washakie.htm)
The Washakie Wilderness Area encompassos704,529 acres around the headwaters of the South
Fork of the Shoshone River in northwestern Wyoming. It is bordered on the west by the Teton
Wilderness and Yellowstone National Park, and the North Absaroka Wilderness Area lies to the
north across the North Fork of the Shoshone River (Figure 2.1-l). Elevations range from
approximately 6,000 feet to 13,153 feet (Francs Peak) on the eastem boundary. Terrain is
rugged and difficult to maneuver in many areas of this wilderness. Wildlife is bountiful, with
mule deer, white-tailed deer, moose, elk, grizzly and black bear, pronghorns and bighorn sheep
being some of the more common species. This area has fewer lakes than some of the other areas,
so fishing opportunities are more limited. However, there are several streams and rivers which
do support trout.
l5 Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey,lPC
Page 25 of 206
Lcgcnd
qass 1 BoLndary
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Figure 2.2,2-2. Washakie Wilderness Class I Area Boundary(trtto:llwww.cona.Ari.eUlm )
2.2.3 Monitoring Strategy and Location - NOABI Monitoring Site
The IMPROVE site designated as the monitor representing the North Absaroka and Washakie
Wilderness Areas is NOABI. Collection of data at the NOABI monitoring site is subsidized by
the Wyoming Department of Environmental Quality. The Division considers the NOABI site as
adequate for assessing reasonable progress goals of the two above-mentioned Class I areas and
no additional monitoring sites or equipment are necessary at this time.
The Air Quality Division routinely participates in the IMPROVE monitoring program by
attending Western States Air Resources Council (WESTAR) and Western Regional Air
Partnership (WRAP) meetings and maintaining memberships in both organizations.
NOABI is located in Dead Indian Pass, approximately 25 miles northwest of Cody, Wyoming
and about 3 miles northeast of the closest North Absaroka Wilderness Area boundary. It is 25
miles north of the Washakie Wildemess boundary. The NOABI monitoring site elevation is
8,134 feet, which is 538 feet below the summit of Dead Indian Hill to the northeast and 66 feet
above Dead Indian Pass and State Highway SR 296.
The nearest metropolitan area to the NOABI monitor, Billings, Montana (over 149,650
population), is situated approximately 83 miles northeast ofthe monitor. The metropolitan area
of Boise, Idaho (over 635,450 population) lies approximately 348 miles to the southwest ofthe
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 26 of 206
l6
monitor and the metropolitan area of Salt Lake City, Utah (over 1,099,000) is located
approximately 301 miles to the southwest.
Lcgcnd
(-i tMPRo\rE sire
[ 2ok, brffrr around site
Chss I boundary
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Lakes and rivers
Bavation
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20 Kilonrls
Figure 2.2.3-1. NOABI Monitoring Site
htto://rwrv.coha.dri.edu/imases/cliparthvy 20km-terrain-northabsarokajpq
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page27 ot206
t7
Figure 2.2.3-2. Looking South Toward the NOABI Monitor
(http ://vista.ci ra.colostate.edr.r/viewsAMeb/S iteBrowser/SiteB rowser.aspx)
2.2.4 Assessment of Baseline, Natural and Current Conditions - NOAB1 Class I Areas
Natural visibility represents the visibility condition that would be experienced in the absence of
human-caused impairment. Based on EPA guidance, the North Absaroka Wilderness and
Washakie Wilderness Class I areas have an established natural visibility of 0.58 deciviews for
the 20 percent best days and 6.83 deciviews for the 20 percent worst days. This is based on on-
site data at the NOABI IMPROVE monitoring site.
Baseline visibility is determined from the NOABI monitoring site (located in Dead Indian Pass,
about 25 miles northwest of Cody, Wyoming) for the 20 percent best and 20 percent worst days
for the years2002 through 2004 as specified in the Regional Haze regulations under 40 CFR
51.308(dx2)(i). The baseline visibility for the North Absaroka and Washakie Wildemess Class I
areas is 2.02 deciviews for the 20 percent best days and I 1.45 deciviews for the 20 percent worst
days, which, for this first SIP submittal, is also the same as the current visibility. These best and
worst 20 percent conditions are also calculated based on EPA guidance. This technical
information was obtained from the "Haze Planning" section of the Western Regional Air
Partnership (WRAP) Technical Support System (TSS) by choosing the "Monitoring" section
followed by the "Deciview Glide Slope" information at http://vista.cira.colostate.edu/tss/.
Further description of this technical information can be found in Chapter 13.
The historic visibility photo record is limited and does not include the North Absaroka or
Washakie Wilderness areas. Photos depicting similar visibitity scenarios from the Bridger
Wildemess (Mt. Bonneville) have been substituted as Figures 2.2.4-l through 2.2.4-4 for the
baseline and natural conditions on the best and worst days.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 28 of 206
18
Baseline Best Days
Vista Reference: Mt. Bonneville
(Bridger Wildemess)
Photo Taken at 9:00 AM
Haze lndex (Ht1= 2 Deciviews
B"rn = 12 Mm-1
Msual Range = 330 km/205 mi
Figure 2.2.4-1. BRIDI Monitor - Baseline Best Dayc
http://vista.cira.colostate.edu/Datawarehouse/IMPROVE/Data/Photos/BRlD/start.htm
Baseline Worst Days
Msta Reference: Mt. Bonneville
(Bridger Wilderness)
Photo Taken at 9:00 AM
Haze lndex (Ht1 = 11 Deciviews
B"'t = 30 Mm-1
Msual Range = 130 km/81 mi
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey,IPC
Page 29 of 206
Figure 2.2.4-2. BRIDI Monitor - Baseline Worst
t9
Figure 2.2.4-3. BRIDI Monitor - Natural Best Days
http://vista.cira.colostate.edu/Datatarehouse/IMPROVE/Data/PhotoVBRlD/start.htm
Natural Best Days
Msta Reference: Mt. Bonneville
(Bridger Wilderness)
Photo Taken at 9:00 AM
Haze lndex (Ht; = 1 Deciview
B"'t = 11 Mm-1
Msual Range = 350 kml217 mi
Natural Worst Days
Msta Reference: Mt. Bonneville
(Bridger Wilderness)
Photo Taken at 9:00 AM
Haze lndex (Ht1 = 7 Deciviews
B"rt = 20 Mm'1
Msual Range = 200 kml124 mi
Figure 2.2.44. BRIDI Monitor - Natural Worst Days
http://vista.cira.colostate.edu/Datawarehouse/IMPRoVE/Data/Photos/BRlD/start.htm
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 30 of 206
20
2.3 Description of the Bridger Monitoring Site @RIDI) Class I Areas
The monitoring site designated as "BRlDl" is the representative regional haze monitoring station
for two Wyoming Class I areas @ridger Wilderness and Fitzpatrick Wilderness). Each of these
Class I areas are described below.
2.3.1 Bridger Wilderness
The Bridger Wilderness, consisting of 428,169 acres, is situated on the west slope of the Wind
River Range in Wyoming and extends approximately 80 miles along the western slope of the
Continental Divide. The wilderness lies south ofthe other six Class I areas and is on the west
border of the Fitzpatrick Wilderness (Figure 2.1-l). The Bridger Wilderness is a combination of
jagged granite rock, alpine forest and open alpine meadows and is the headwaters for the Green
River. This wilderness forms a triple divide for three major watersheds: the Columbia River, the
Colorado River, and the Missouri River. The Wind River Range contains numerous peaks, some
exceeding 13,000 feet, the highest of which is Gannett Peak (13,804 feet) located on the
boundary between the Bridger Wilderness and the adjacent Fitzpatrick Wilderness to the east.
This wilderness contains seven of the ten largest glaciers in the U.S. (lower 48). Some of the
more common species found in the Bridger Wildemess are mule deer, moose, elk, bighorn sheep,
gray wolf, and both grizzly and black bear.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 31 of206
Figure 2.3.1-1. Slide Lake (Photo Courtesy of Ralph Maughan)
Lcgcnd
O lmprove Site
Class I boundary
! zot, bufier around sie
ffi Lakes and dvers
Ecvtlon
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Figure 2.3.1-2. Bridger Wilderness Monitoring Site and Partial Boundary
http://www.coha.dri.edu/imagesiclipart/wy_20km_terrain bridger.iog
htto://www.publiclands.or8y'explore/quadrant_map.php?id:1742&site name=Bridger%20Wilderness&quad:WY O!
Exhibit No. 4
Case No.|PC-E-13-16
T. Harvey,lPC
Page 32 of 206
re 2.3.1-3. Bridger Wilderness Boundary
22
2.3.2 Fitzpatrick Wilderness
Figure 2.3.2-1. The Wind Rivers From the Wind River Indian Reservation (Courtesy of Ralph Maughan)
http ://www. forwolves.ore/raloh/rvpages/graph ics/fi tzpatrick I j pg
The Fitzpatrick Wildemess Area (191,103 acres) is located on the east slope of the northern
Wind River Range in Wyoming along the Continental Divide, which makes up its westem
border. It shares its western border with the Bridger Wildemess Area, while its eastern border is
shared with the Wind River Indian Reservation. Elevations range from approximately 5,575 feet
at the western side of the upper Wind River Basin at river level to east slope elevations of 8,200
feet. Gannett Peak claims the highest elevation (13,804 feet) and is on the Divide boundary
between the Fitzpatrick Wilderness and the adjacent Bridger Wilderness to the east. Precipitous
canyons formed by glaciers from granite and limestone rock are found throughout the area.
Alpine meadows, stands of timber and rocky plateaus are also common sights. There are more
than 60 lakes and at least 75 miles of streams which tout excellent trout fishing. Abundant
wildlife includes elk, mule deer, moose, bighorn sheep, black bear, bobcats and coyotes.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 33 of 206
23
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lzTis-zpsI zpm-sp:
ltpu-t7zt
7-lt2;a-t*.t
N
A
0 5 10 20 lcmdc
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 34 of 206
Figure 2.3.2-2. Fitzpatrick Wilderness Class I Boundary
http ://www.coha.dri.edu/i mages/cl iparUwv_20km_terrain-fi tzpatrick j pe
2.3.3 Monitoring Strategy and Location - BRIDI Monitoring Site
The IMPROVE site designated as the monitor representing the Bridger and Fitzpatrick
Wilderness Areas is BRIDI. The Division considers the BRIDI site as adequate for assessing
reasonable progress goals ofthe two above-mentioned Class t areas and no additional monitoring
sites or equipment are necessary at this time.
The Air Quality Division routinely participates in the IMPROVE monitoring program by
attending Western States Air Resources Council (WESTAR) and Western Regional Air
Partnership (WRAP) meetings and maintaining memberships in both organizations.
BRIDI is located at the White Pine Ski Area, l0 miles northeast of Pinedale, Wyoming and
approximately 2 miles outside of the southwestem Bridger Wilderness boundary. The
monitoring site sits on a small hilltop in a high basin on the west slope of the Wind River Range
at an elevation of 8,553 feet. The site is approximately 1,148 feet above Fremont Lake which
lies slightly over I mile to the west, and about the same distance below the elevation of the
nearest Bridger Wilderness boundary to the northeast. BRIDI is approximately 1,378 feet higher
than the upper Green River Basin town of Pinedale.
The nearest metropolitan area to the BRIDI monitor, Salt Lake City, Utah (over 1,099,000), is
located approximately 187 miles to the southwest. The metropolitan area of Billings, Montana
(over 149,650 population), lies approximately 203 miles to the northeast of the monitor and the
24
metropolitan area of Boise, Idaho (over 635,450 population), is situated approximately 329 miles
southwest of the monitor.
Legend
(-r lmprove Sile
Class I boundary
J-l zot* buffer around site
Lakes and ravers
El evation
MctGrs
f-loza- z,zso
f--f z.tso -z,too
I z,+oo - z,sso
! z,sso-z,zoo
Ft 3 z,zoo-:,aso
! z,aso-s,ooo
!:,ooo-:,rso!:,rso -:,:oo
f--l:,:oo-e,nso
[--l:,aso -:,aoo
/i
Figure 2.3.3-1, BRIDI Monitoring Site
htto://www.coha.dri.edu/images/cl ipart/wy_20km_terrain-brid gerj pe
htto://vista.cira.colostate.edu/lmages/Photos/IMPROVEiBRIDI/BRIDI 2005-N-lN.JPC
20 Kiloneie€
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 35 of 206
Figure 2.3.3-2. Looking North Toward BRIDI Monitor
25
2.3.4 Assessment of Baseline, Natural and Current Conditions - BRIDI Class I Areas
Natural visibility represents the visibility condition that would be experienced in the absence of
human-caused impairment. Based on EPA guidance, the Bridger and Fitzpatrick Wilderness
Class I areas have an established natural visibility of 0.28 deciviews for the 20 percent best days
and 6.45 deciviews for the 20 percent worst days. This is based on on-site data at the BRIDI
IMPROVE monitoring site.
Baseline visibility is determined from the BRIDI monitoring site (located at the White Pine Ski
Area, l0 miles northeast of Pinedale, Wyoming) for the 20 percent best and 20 percent worst
days for the years 2000 through 2004 as specified in the Regional Haze regulations under 40
CFR 51.308(dx2)(i). The baseline visibility for the Bridger and Fitzpatrick Wilderness Class I
areas is 2.1 deciviews for the 20 percent best days and I l.l2 deciviews for the 20 percent worst
days, which, for this first SIP submittal, is also the same as the current visibility. These best and
worst 20 percent conditions are also calculated based on EPA guidance. This technical
information was obtained from the "Haze Planning" section of the Westem Regional Air
Partnership (WRAP) Technical Support System (TSS) by choosing the "Monitoring" section
followed by the 'oDeciview Glide Slope" information at http://vista.cira.colostate.edu/tss/.
Further description of this technical information can be found in Chapter 13.
Photographs representing similar visibility conditions on best and worst days for baseline and
natural conditions are included in Figures 2.3.4-l through 2.3.4-4.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 36 of 206
26
Figure 2.3.4-1. BRID1 Monitor - Baseline Bert Days
htto://vista.cira.colostate.edu/Datawarehouse/IMPROVE/Data/Photos/BRlD/start.htm
Baseline Best Days
Msta Reference: ffi. Bonneville
(Bridger Wilderness)
Photo Taken at 9:00 AM
Haze lndex (Ht) = 2 Deciviews
B"rt = 12 Mm-l
Visual Range = 330 km/205 mi
Baseline Worst Days
Msta Reference: Mt. Bonneville
(Bridger Wilderness)
Photo Taken at 9:00 AM
Haze lndex (Ht; = 11 Deciviews
B"x = 30 Mm-1
Msual Range = 130 km/81 mi
Figure 2.3.4-2. BRIDI Monitor - Baseline Worst Days
htto://vista.cira.colostate.edu/Datawarehouse/IMPROVE/Data/PhotoVBRlD/start.htm
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 37 of 206
27
Figure 2.3.4-3. BRIDI Monitor - Natural Best Days
http://vista.cira.colostate.edu/Datawarehouse/IMPROVE/Data/Photos/BRlD/start.htm
Natural Best Days
Msta Reference: Mt. Bonneville
(Bridger Wilderness)
Photo Taken at 9:00 AM
Haze lndex (Ht) = 1 Deciview
B"'t = 1'1 Mm-1
Visual Range = 350 kml217 mi
Natural Worst Days
Msta Reference: Mt. Bonneville
(Bridger Wilderness)
Photo Taken at 3:00 PM
Haze lndex (Ht; = 6 Deciviews
B"'t = 18 Mm-1
Msual Range = 220 km/137 mi
Figure 2.3.44. BRIDI Monitor - Natural Worst Days
http://vista.cira.colostate.edu/Datawarehouse/IMPROVE/Data./Photos/BRID/start.htm
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 38 of 206
28
CHAPTER 3
POLLUTAIITS CAUSING VISIBILITY IMPAIRMENT
IN WYOMING CLASS I AREAS
This chapter provides a summary of regional haze monitoring data from the IMPROVE
monitoring sites in Wyoming, and the pollutants that affbct visibility impairment in each of
Wyoming's Class I areas. A summary of the visibility improvement needed from baseline
(2000-2004) to the 2018 uniform rate of progress (URP) milestone, and to the2064 natural
condition goal is also provided. Depictions of Wyoming IMPROVE monitoring sites are
provided in Chapter 2.
The haze index (.F11) in deciview (dv) units, as discussed in EPA's 2003 Guidance for Tracking
Progress Under the RegionalHaze Rule, is a visibility metric based on the light-extinction
coefficient that expresses incremental changes in perceived visibility. A change in the 111of one
dv is approximately equal to a lUYo change in extinction coefficient. The haze index is defined
by:
I{f = l0ln(b," /10)
The value of the haze index is approximately zero dv for a pristine atmosphere. This value
increases as visibility degrades.
EPA's 2003 guidance for calculating light extinction is based on the original protocol defined by
the IMPROVE program in 1988. In December 2005, the IMPROVE Steering Committee voted
to adopt a revised algorithm for use by IMPROVE as an alternative to the original approach.
The revised algorithm for estimating light extinction is calculated as recommended for use by the
IMPROVE steering committee using the following equations:
b",,= 2.2 x GGH) x [Small Amm. Sulfate] + 4.8 x fL(RH) x [Large Amm. Sulfate]
+ 2.4 x qGD x [Small Amm. Nitrate] + 5.1 x fLGH) x [Large Amm. Nitrate]
+ 2.8 x [SmallPOM] + 6.1 x [Large POM]
+ l0 x [EC]
+ I x [Soil]
+ 1.7 x f,,(RH) x [Sea Salt]
+ 0.6 x [CM]
+ 0.33 x [Noz(ppb)]
+ Rayleigh Scattering (Site Specific)
The revised algorithm splits ammonium sulfate, ammonium nitrate, and POM concentrations
into small and large size fractions as follows:
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 39 of 206
29
[tr-s"1=Sp*[rot t]
ror[roat]< 2oplmsi
[[s."rt= [rour]-[rffs.]
ror [roat] > 2oFgor, [rrsE] = [roat]
Chapter l3 provides additional information on light extinction.
The following table identifies the different pollutant species that contribute to haze, and their
abbreviations, as they appear in the frgures in this section. References to sulfate and nitrate in
this section are intended to reflect ammonium sulfate and ammonium nitrate, respectively.
Table 3-1. IMPROVE Monitor Aerosol
The figures which follow in this chapter provide information for each Class t area (based on
representative TMPROVE monitoring site) for the ZUo/obest and20o/o worst days during the
baseline period, monthly averages of all monitored days, and the improvement needed by 2018
and2064.
Figures 3-l and 3-2 summarize the distribution of pollutant species in Wyoming's Class I areas,
for the current (2000-2004 baseline) 2D%obest and 20o/o worst days.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 40 of 206
IMPROVE Abbreviation
OMC (Organic Mass Carbon)
CM (Coarse Mass)
Soil (Fine Soil)
30
Figure 3-1. Light Extinction by Pollutant Species for Wyoming Class I Areas 20oh Best
2004
E
=3Eo
oCtFxlrJ
YELL2
Yellowstone NP
Grand Teton NP
Teton Wilderness
NOABl
North Absaroka Wilderness
Washakie Wilderness
BRIDl
Bridger Wilderness
Fitzpatrick Wilderness
Amm.Sulfate rAmm.Nitrate rOMC r EC r Soil fi CM l Sea Salt
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 4't of 206
3l
Davs (2000-2004)
EE
Eo
otr
xUI
28
26
24
22
20
18
16
t4
1.2
10
8
5
4
2
0
YELL2
Yellowstone NP
Grand Teton NP
Teton Wilderness
NOABl
North Absaroka Wilderness
Washakie Wilderness
BRIDl
Bridger Wilderness
Fitzpatrick Wilderness
Amm.Sulfate I Amm. Nitrate r OMC r EC r Soil ms CM r Sea Salt
Figure 3-2. Light Extinction by Pollutant Species for Wyoming Class I Areas 207o Worst
As the above figures indicate, Wyoming's Class I areas are dominated by sulfate and organic
carbon on the 20Yobest days, and organic carbon and sulfate on the 20% worst days. On the
20Yobest days, sulfate is significant in all of the Class I areas. The majority of this can be
affributed to point sources. On the 207o worst days, organic carbon is the most significant
species in all of the Class I areas, with natural fire having the largest contribution.
The following sections provide an additional breakdown of the pollutant species that contribute
to each Class I area. The first figure in each section shows a simple pie chart of the Z0Yobest
and}0Yo worst days, similar to the bar chart figures above. The second figure in each section
shows the pollutant species based on monthly averages for all days (including best or worst)
during the baseline period, as an example of the seasonal variation in Class I areas. The third
figure in each section presents a closer look at the daily variation during a given year--in this
case 2004. The fourth figure in each section shows the improvement needed (shown in reduction
in deciview) for each Class I area, from the baseline year to the 2018 milestone, and to 2064
natural conditions.
3.1 Yellowstone National Par\ Grand Teton National Park and Teton Wilderness
As depicted in the following figures, on the best20Yo days sulfate is the dominant species, but
organic carbon is the largest contributor on the worst 20olo days. Both sulfate and nitrate
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 42 of 206
32
pollutant species fluctuate during the year. Significant spikes of organic carbon, however, are
evident especially in the warmer months, most likely due to wildfire activity. Figure 3.1-4,
indicates a I .3 deciview reduction would be needed to meet a 2018 URP, and a 5.4 deciview
reduction would be needed to meet a2064 URP. While 51.308(d)(lXi)(B) requires that the State
disclose the incremental change required to meet a URP goal, there is no requirement to meet a
URP goal. This is discussed in more detail in Chapter 7.
Figure 3.1-1. Yellowstone IMPROVE Site - Average Pollutant Species Contribution to
20oh Best and 20oh lyo$ lgy!_Bry9lt_njggq9-29qQ
YELLz 2000-2004
o",o*oYf='9}"*"
Daily rmge = 15.1 to 140.7 Mml
Iammno3t-bexl- anrrnso4l-bext
i icn-betr
Ied bexl
!omcl-bexlf] seasat-bert
Isoilr-bcxl
(http://vista.cira.colostate.edu/dev/web/AnnualSummaryDev/Composition.aspx)
Figure 3.1-2. Yellowstone IMPROVE Site - Monthly Average Pollutant Species Variation
(WRAP TS S - htto ://v i sta. cira. co lostate.edu/tss/)
Ee$ 2m5
Aarrcdbcxt = 4 ivtn-1
Daily rangp . I .7lo 6.7 Mnl
3.89'6
0.08%
2.56%
o.26%
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 43 of 206
for AII Days Sampled During the Baseline Period (2000-2004)
Monitoring Data for All IMPROIE $ampled Days
Class I ffeas - Grand Teton NP, WY: Red Rock Lakes l.ll{RVY, MT:Teton W, YYY:Yellowslone NP, VYY
l
- lseasal Extirction
ffictvt Extin*ion
lsoitExtinaion
Iec extnaion
lomexin*im
luolenlraion
,SilEninaion
70.0
60.0
20.0
100
0.0 ooooooNNSlNNNooo{9(})0)$tst\ttrtooo oooooooo oooBoeo oooooooo ooooooo oooooooo ooooooo ooo60000 000(]N N ff N N N N N N N C{ N fl N N f{ N CI N N N N N C{ N N O{ N N N
nrn,crN-r##@ o p I n q * o P E N t c, o P s .. t E s P I * t @, p I
50.0
T
E 100
3U.0
33
Figure 3.1-3. Yellowstone IMPROVE Site - Pollutant Species Variation for All Days
(WRAP TS S - http ://vista.cira.colostate.edu/tss4
Figure 3.1-4. Yellowstone IMPROVE Site - Baseline Worst Day Aerosol Composition
Sampled in 2004
Monitoring Data for All IMPROIE Sampled Days
Qlass I ffeas - Orand Teton NP, WY: Rsd Rock Lekss itrT: Teton trtf, l ff: Yellorst0ne NP, WY
[SeaS*brttdion
EcNrxm*nn
Isoexmion
Iec rxtrcion
lmrtraim
Ilpeexn*on
i-lsorrff'ais,
s2.0
2nt
a3
- m.0
5 ro.o
12.{1
8.0
4.0
0.t]
HHHHHHHHHHHHHHHHHHHHHHHHHHHHHHPNHITEft $f TEE8ifi fl fi TIETfl E$ETIEEfr- #; N N O o $ !r E o o r\ o o o o d Ei r i ; l!- .{
Compared to Visibilitv Improvement Needed bv 2018 & 2064
Yellowstone NR Grand Teton NP and Teton Wilderness Area
YELL2 IMPROVE Site (New IMPROVE Algorithm)
t;Ezs
=CO ztJEoc,I)x
IrJ
r Sea Salt
reCM
r Soil
IEC
rOMC
I Amm. Nitrate
Amm. Sulfate
10
2000-2004 Baseline
Conditions
2018 Uniform Rate of
Progress Target
2064 Natural Conditions
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 44 of 206
34
3.2 North Absaroka and Washakie Wilderness Areas
As depicted in the following figures, on the best20Yo days sulfate is the dominant species, but
organic carbon is the largest contributor on the worst 20% days. Both sulfate and nitrate
pollutant species fluctuate during the year. Like the Yellowstone IMPROVE site, the North
Absaroka IMPROVE site shows significant spikes of organic carbon, especially in the warmer
months most likely due to wildfire activity. Figure 3.2-4, indicates a l.l deciview reduction
would be needed to meet a 2018 URP, and a 4.7 deciview reduction would be needed to meet a
2064 URP. While 5l .308(dXlXiXB) requires that the State disclose the incremental change
required to meet a URP goal, there is no requirement to meet a URP goal. This is discussed in
more detail in Chapter 7.
Figure 3.2-1. North Absaroka IMPROVE Site - Average Pollutant Species Contribution to
20Yo Best and 20o/o Worst Baseline (2000-2004
NOAB{ 2002-2004
Bc$ A]96
Asosd bcxt = 3.3lttht-l
Daily rmga = 1 .1 to s.tl Mt-l
\tr&rsi 20%
Aerosd b€xt ' 23.7 ttrl-l
D.Iy ranqE = 145 to 68.2 l*Fl
3.01%
0.60%
't2.05%3.37%
0.04%
!annno3f-bcxt
i. lammso4r-bext
i-lcm-let
Iccl-ba
!orncl-ba*
il"l saasalt-baxt
Isorl-ba{
L(http://vista.cira.colostate.edu/dev/web/AnnualSummaryDev/Composition.aspx)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 45 of 206
35
Figure 3.2-2. North Absaroka IMPROVE Site - Monthly Average Pollutant Species
Variation for All Days Sampled During the Baseline Period (2000-2004)
- - lr^-i+^,;^ n-+- t ruf frt,lMonitoring Data for All IMPROVE Sampled Days
Class ltueas - Norfi Absaroka W, VfY: VYashakie W, VYY
6oooooflNNN0lNo$ooootrtrtlltrfo o o o oo o o o o o o o o oo tr o o o o o o o oo o o o oooooooooooooooooooooooooooooooNNNNNNNNNNNNNNNNNNNNNNNNNNNNNN
tun*prse-,#t+ o o P F N t @ o p F,\ t o m p s * s s o p N $r rf o s P I
(WRAP TS S - http ://v ista. c ira. co lostate.edu/tssO
Figure 3.2-3. North Absaroka IMPROVE Site - Pollutant Species Variation for All Days
Monitoring Data for All IMPR0VE Sampled Days
Class I Areas - Norlh Absaroka W, WY: Washakie W, YVY
L" r SeaSall Extfrthn
ffi cu Extinaion
lsot rxtinaion
t rc rxtinction
Iouc e*inaion
! Noa rxtinciion
SO4 Eilindion
89888888889888886600000000000000flN{Nqfl{{flqqturyryq6NOoho(,!o$F: erss9QrNd(tlttlUdtdltn
urnApIEs"roar,{ffi N N $ o rt v $ 6 6
HHHHHHHHHHHHHHss$$$$s$$$s$s$fldltdlQEt:(ultttOOOOC,CiT--NN
I
I
(WRAP TSS - http://vista.cira.colostate.edu/tss/)
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 46 of 206
36
Figure 3.2-4. North Absaroka IMPROVE Site - Baseline Worst Day Aerosol Composition
Compared to Visibilitv Improvement Needed bv 2018 & 2064
North Absaroka and Washakie Wilderness Areas
NOABI IMPROVE Site (New IMPROVE Algorithm)
r Sea Salt
ICM
r Soil
IEC
I oMc
I Amm. Nitrate
Amm.Sulfate
2018 Uniform Rate of
Progress Target
2064 Natural Conditions
3.3 Bridger and Fitzpatrick Wilderness Areas
As with all other Wyoming Class I areas, on the best 20%o days sulfate is the dominant species,
but organic carbon is the largest contributor on the worst 20% days. Both sulfate and nitrate
pollutant species fluctuate during the year. Like the other Class I sites, the Bridger IMPROVE
site shows significant spikes of organic carbon, especially in the warmer months most likely due
to wildfire activity. Figure 3.34, indicates a l.l deciview reduction would be needed to meet a
20 I 8 URP, and a 4.6 deciview reduction would be needed to meet a 2064 URP. While
51.308(dXlXD(B) requires that the State disclose the incremental change required to meet a URP
goal, there is no requirement to meet a URP goal. This is discussed in more detail in Chapter 7.
tiEzs
=co2UEuE
9 J.Jxlrl
10
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page47 o|.206
37
Figure 3.3-1. Bridger IMPROVE Site - Average Pollutant Species Contributionto 20oh
Best and 207o Worst Days Baseline-2004
Bcst 20%
ABrosol bcxt = 3.4 iin-1
oaily rmge . 0,9 to 5.9 lum-l
BRID{ 2000-2004
\ hrd 20%
Aerosd bcxt = 22.6 llo-1
Daly rmge ' 13.41o 1otl.6l'/t{n-l
lammno3f-bext
i rahhso4f-hcxl
i lcm-bcf
Iect-rext
f omcl-bext
l-,.i soasalt-bext
Isoill-bext
(http://vista.cira.colostate.edu/dev/web/AnnualSummaryDev/Composition.aspx)
Figure 3.3-2. Bridger IMPROVE Site - Monthly Average Pollutant Species Variation for
All Days Sampled During the Baseline Period (2000-2004)
Monitoring Data for All IMPR0VE Sampled Days
Class I Areas - Eridger V,/, WY: tl4atickW, WY
28.0
24.0
20.0
: 16.0EE
120
l.: SeaSat frAiUion
ffi cN Extinction
!SoilExtinction
I rc rxtinaion
Iorcexi"raim
tuosr*naion
SOl EfinaionB.t)
4.0
0.0
OOO OOOTFFFT FNNNNNN Ooom$$tt Strttoooootrootrooo(100sooooooooooooooooo oooooooo ooooooo ooootrooo ooooNNN NNNNNNN N NNNNNNN NNC{NNNNN NNNN
wn^rme-rdi,dE E P I * $ t o P g N t " P l * t D 6 P I N t o o P P
(WRAP TS S - http ://vi sta.ci ra.colostate. edu/tss/)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 48 of 206
38
Monitoring Dah forAll IMPRO\E $ampled Days
Class I Areas -W, WY:F@atickW,lif/
nSeaSAA*nmn
flcur*mon
Isole+iulsr
lecr*rom
Imruruim
luorennmon
ilsoteuurn
36.0
32.0
2q.0
?1.0
.; E.oEE ts.o
t?.0
8.0
{.0
0.0
HHHHHHHEHHHHHHHHHHHHHHHHHEHi TEft $[EEE$iEEf IiETfl f TE3[ Ei ENNoo rlr p GG F' oo ooEE-a:s$MNAT IES.
t!f88s(ON
-i-*B.M8
Figure 3.3-3. Bridger IMPROVE Site - Pollutant Species Variation for All Days Sampled
in 2004
(WRAP T S S - http ://vi sta. c ira. co lo state. edu/tss/)
Figure 3.3-4. Bridger IMPROVE Site - Baseline Worst Day Aerosol Composition
Co to Visibility I tNeededbv2018 &2064
Bridger and Fitzpatrick Wilderness Areas
BRID1 IMPROVE Site (New IMPROVE Algorithm)
r Sea Salt
llCM
r Soil
rEC
I oMc
r Amm. Nitrate
Amm. Sulfate
2000-2004 Baseline
Conditions
2018 Uniform Rate of 2064 NaturalConditions
Progress Target
35
30
Rcduction
Nccdcd =
1,1 q,v
I5Ezs
=520
UE,H I)xIU
10
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 49 of 206
39
CHAPTER 4
STATEWIDE EMISSION INVENTORY
4.1 Introduction
The process for inventorying sources is similar for all species of interest. The number and types
of sources is identified by various methods. For example, major stationary sources report actual
annual emission rates to the EPA national emissions database. Wyoming collects annual
emission data from both major and minor sources and this information is used as input into the
emissions inventory. In other cases, such as mobile sources, an EPA mobile source emissions
model is used to develop emission projections. Population, employment and household data are
used in other parts of the emissions modeling to characterize emissions from area sources such as
home heating. Thus, for each source type, emissions are calculated based on an emission rate
and the amount of time the source is operating. Emission rates can be based on actual
measurements from the source, or EPA emission factors based on data from tests of similar types
of emission sources. In essence all sources go through the same process. The number of sources
is identified, emission rates are determined by measurements of those types of sources and the
time of operation is determined. By multiplying the emission rate times the hours of operation in
a day, a daily emission rate can be calculated. A second inventory is created to predict emissions
in 201 8 based on expected controls, growth, or other factors. Additional inventories are created
for future years to simulate the impact of different control strategies. While the Division
attempts to make sound estimates of all sources of emissions in the State, they are only estimates
at one point in time. Oil and gas emission estimates are some of the more complicated emission
inventories that the Division collects, and the Division is working hard to improve those
estimates.
The following presents the Wyoming emissions from the WRAP TSS.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 50 of 206
40
4.2 SO* Emission Inventory
able 4.2-1.Emission lnventory - 2OOZ and 2O1E
Wyoming Planning and Preliminary Reasonable Progress
Emission lnventories
Source Cateoorv
Statewide SO,
Plan 02d
(tov)
PRP18b
(tov)
Net Change
From Plan 02d
to PRP18b
(Percent)
>oint 119.717 96.80S -1S
Area 16.68S 23,09:38
f,n-Road Mobile oEc 81 -92
f,ff-Road Mobile 5.86(6r -9€
3il & Gas 15C -9t
Road Dust C (C
=uqitive Dust C (c
//indblown Dust C (c
Anthro Fire 173 10s -37
\atural Fire 2.28e 2.28t c
liooenic c (c
Iotal 145,84C 122.44e -1t
Sulfur oxides (SO*) are compounds of sulfur and oxygen molecules. Sulfur dioxide (SO2) is the
predominant form found in the lower atmosphere. Sulfur dioxide emissions produce sulfate
particles in the atmosphere. Ammonium sulfate particles have a significantly greater impact on
visibility than other pollutants like dust from unpaved roads due to the physical characteristics
causing greater light scattering from the particles. Sulfur dioxide emissions come primarily from
coal combustion at electrical generation facilities, but smaller amounts come from natural gas
combustion, mobile sources and even wood combustion. There are natural sources of sulfur
dioxide such as volcanoes. A 16% statewide reduction in SO* emissions is expected by 2018
due to planned controls on existing sources, even with a growth consideration in generating
capacity for the State. Similar reductions are expected from other states as BART or other
planned controls take effect by 2018.
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4t
4.3 NO* Emission Inventory
able 4.3-1.Emission Inventorv - 2OO2 and 2018
Wyoming Planning and Preliminary Reasonable Progress
Emission lnventories
Source Cateoorv
Plan02d
(tov)
PRP18b
(tov)
Net Change
From Plan02d
to PRP18b
(Percent)
Point 1'17.806 110.109 -7
Area 15.192 19.663 29
On-Road Mobile 38.535 9.728 -75
Off-Road Mobile 76.637 49.677 -35
Oil & Gas 14.725 34.142 132
Road Dust 0 0 0
Fuoitive Dust 0 0 0
Windblown Dust 0 0 0
Anthro Fire 782 484 -38
Natural Fire 8.372 8.372 0
Biooenic 15,925 15,925 0
Total 287.974 248.100 -14
Nitrogen oxides (NO.) are generated during any combustion process where nitrogen and oxygen
from the atmosphere combine together under high temperature to form nitric oxide, and to a
lesser degree nitrogen dioxide, and in much smaller amounts other odd oxides of nitrogen.
Nitrogen oxides react in the atmosphere to form nitrate particles. Nitrogen oxide emissions in
Wyoming are expected to decrease by 2018, primarily due to significant improvements in mobile
sources. It is projected that off-road and on-road vehicles emissions will decline by more than
55,760 tons per year from the Plan02d emissions total of l15,l72 tons per year. Point sources
are also projected to decrease statewide emissions by about 7,700 tons per year. A power plant
would be a typical example of a point source. Oil and gas development is expected to increase
statewide emissions from 2002 to 2018 by about 19,400 tons per year. With population
increases and more construction, fugitive dust emissions will also increase.
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4.4 OC Emission Inventory
Organic carbon particles emitted directly from the combustion of organic materials are called
primary organic aerosols. A wide variety of sources contribute to this classification including
byproducts from wood and agricultural burning with emissions from natural fires as the largest
contributor to organic carbon emissions. Since it is impossible to predict future emissions from
natural fires, this category was held constant and organic carbon emissions from all sources are
expected to show a 3% decline.
-2OO2 and 2018
Net Change
From Plan02d
to PRP18b
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4.5 EC Emission Inventory
Table 4-5-1.
Source Cateqorv
Plan02d
(tov)
PRP18b
(tov)
Net Change
From Plan02d
to PRP18b
(Percent)
Point 104 180 73
Area 304 335 10
On-Road Mobile [phone]
Off-Road Mobile 1.986 1.161 -42
Oil& Gas 0 0 0
Road Dust 2 2 0
Fuoitive Dust 7 I 29
Windblown Dust 0 0 0
Anthro Fire 298 153 -49
Natural Fire 4.922 4.922 0
Biooenic 0 0 0
Total 8.066 6.848 -15
Elemental carbon is the carbon black, or soot, a byproduct of incomplete combustion. It is the
partner to primary organic aerosols and represents the more complete combustion of fuel
producing carbon particulate matter as the end product. A carbon particle has a sixteen times
greater impact on visibility than that of a coarse particle of granite. Reductions in manmade
emissions in elemental carbon are largely due to mobile sources and expected new Federal
emission standards for mobile sources, especially for diesel engines. Fleet replacement will also
play a part in the reduction. Elemental carbon emissions are predicted to decrease approximately
l5%by 2018. As with organic carbon, however, the overwhelming source for elemental carbon
is from wildfires which the Division cannot control or predict future emissions.
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4.6 Fine PM Emission Inventory
Table 4.&1. Wyoming Fine PM Emission lnventory - 2002 and
2018
Source Cateoorv -Plan02d
(tov)
PRP18b
(tov)
Net Change
From
Plan02d to
PRP18b
(Percent)
Point 11.37s 15.709 38
Area 1.601 1.756 10
On-Road Mobile 0 0 0
Off-Road Mobile 0 0 0
Oil & Gas 0 0 0
Road Dust 160 206 29
Fuqitive Dust 2,082 2,882 38
Windblown Dust 5,838 5,838 0
Anthro Fire 242 129 -47
NaturalFire 1.535 1,535 0
Biooenic 0 0 0
Total 22.833 28.055 23
Fine soil emissions are largely related to agricultural and mining activities, windblown dust from
construction areas and emissions from unpaved and paved roads. A particle of fine dust has a
relative impact on visibility one tenth as great as a particle of elemental carbon. On any given
visibility event where poor visual air quality is present in a scene, the impact of dust can vary
widely. Agricultural activities, dust from unpaved roads and construction are prevalent in this
source category and changes in emissions are tied to population and vehicle miles haveled.
Since soil emissions are not directly from the tailpipe of the vehicle, the category of mobile
sources does not show any emissions and all vehicle related emissions from paved and unpaved
roads show up in the fugitive dust and road dust categories.
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4.7 Coarse PM Emission Inventory
Table 4.7-1. Wyoming Goarse PM Emission lnventory -2002
and 2018
Source Cateoory
Plan02d
(tov)
PRP18b
(tov)
Net Change
From Plan02d
to PRP18b
(Percent)
Point 24.751 30.619 24
Area 409 653 60
On-Road Mobile [phone]
Off-Road Mobile 0 0 0
Oil& Gas 0 0 0
Road Dust 1.125 1.449 29
Fuoitive Dust 18.030 25.144 39
Windblown Dust 52.546 52.546 0
Anthro Fire 259 109 -58
Natural Fire 5.369 5.369 0
Biooenic 0 0 0
Tota!102.660 116.054 13
Coarse mass particles emissions are closely related to the same sources as fine soil emissions but
other activities like rock crushing and processing, material transfer, open pit mining and unpaved
road emissions can be prominent sources. Coarse mass particles travel shorter distances in the
atmosphere than some other smaller particles but can remain in the atmosphere sufficiently long
enough to play a role in regional haze. Coarse mass particulate maffer has the smallest direct
impact on regional haze on a particle-by-particle basis where one particle of coarse mass has a
relative visibility weight of 0.6 compared to a carbon particle having a weight of 10. lncreases in
coarse mass are seen in the fugitive and road dust categories, as well as point and area source
categories. These increases are largely attributable to population growth, vehicle miles traveled
and employment data.
Exhibit No. 4
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46
4.8 Ammonia Emission Inventory
Table 4.8-1. Wyoming Ammonia Emission !nventory - 2002
and 2018
Wloming Planning and Preliminary Reasonable Progress
Emission lnventories
Source Cateqorv
Plan02d
(tov)
PRP18b
(tov)
Net Change
From
Plan02d to
PRP18b
(Percent)
Point 685 '1.398 104
Area 29.776 29.901 0
On-Road Mobile [phone]
Off-Road Mobile 41 57 39
Oil & Gas 0 0 0
Road Dust 0 0 0
Fuoitive Dust 0 0 0
Windblown Dust 0 0 0
Anthro Fire 218 119 -45
Natural Fire 1,775 1.775 0
Bioqenic 0 0 0
Total 33.033 33,974 3
Ammonia emissions come from a variety of sources including wastewater treatment facilities,
livestock operations, and fertilizer application and to a small extent, mobile and point sources.
Increases in ammonia emissions are correlated to population statistics and increased vehicular
traffic. Ammonia is directly linked to the production of ammonium nitrate and ammonium
sulfate particles in the atmosphere when sulfur dioxide and nitrogen oxides eventually convert
over to these forms of particles. Mobile source emissions are expected to rise due to increases in
vehicle miles traveled. Future point source emissions are also expected to increase by 2018,
however, little to no overall increases in ammonia are predicted for 2018.
4.9 Inventories Utilized For Emissions Projections
The WRAP Regional Modeling Center (RMC) developed multiple annualemissions inventories
for a2002 actual emissions base case, a planning case to represent the 2000-04 regional haze
baseline period using averages for key emissions categories, and a 2018 base case of projected
emissions determined using factors known at the end of 2005. All emission inventories were
developed using the Sparse Matrix Operator Kernel Emissions (SMOKE) modeling system.
These inventories have undergone a number of revisions throughout the development process to
arrive at the final versions used in CMAQ and CAMx air quality modeling.
represents the actual conditions in calendar year 2002 with respect to ambient air quality
and the associated sources of criteria and particulate matter air pollutants. The BaseO2
emissions inventories are used to validate the air quality model and associated databases
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47
and to demonstrate acceptable model performance with respect to replicating observed
particulate matter air quality.
The 2000-04 baseline period planning case emissions scenario is referred to as "PlanO2",
and represents baseline emission pattems based on average, or't5pical", conditions.
This inventory provides a basis for comparison with the future year 2018 projected
emissions, as well as to gauge reasonable progress with respect to future year visibility.
Plan 02d, used by the State of Wyoming in these inventories, was last revised in October,
2008.
The 201 8 future-year base case emissions scenario, referred to as "201 8 Base Case" or
"Base [ 8", represents conditions in future year 2018 with respect to sources of criteria and
particulate matter air pollutants, taking into consideration growth and controls. Modeling
results based on this emission inventory are used to define the future year ambient air
quality and visibility metrics.
2018 Preliminary Reasonable Progress refers to a WRAP emissions or modeling scenario
based on the preliminary reasonable progress emissions inventories, generated in early
2007. This scenario includes corrections, refinements and additions to the 2018 Base
Case, as well as estimates of controlling SOz and some NO* from BART sources. The
PRPl Sb analysis series, used by the State of Wyoming in these inventories, was last
revised in August, 2009.
The CMAQ and CAMx air quality models are explained in more detail in Chapter 5.
4.10 PRPl8b
A "base case" emissions projection inventory was compiled by the WRAP in January of 2006.
In June 2007, a revision to this inventory named 2018 Preliminary Reasonable Progress version
"a" (PRPlSa) updated the first set (base case) of projections. The most recent projections, 2018
Preliminary Reasonable Progress version "b" (PRPl Sb), provides a more current assessment of
the reasonable progress toward visibility goals by the WRAP. Table 4.9-l below depicts the net
change from the PRPl Sa NO* emission inventories to the PRPl Sb emission inventories.
Table 4.9-1. Net Chanse From PRP18a to PRPl8b Emission I tories
The off-road mobile category showed a l6oh decrease in NO* emissions, 89% of which was
attributable to locomotives. The remaining I l% was aftributable to off-road equipment. A
Exhibit No. 4
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nYen
Source
Category
PRP18a NO,
Emission
Inventory
(tnv)
PRPl8b NO.
Emission
Inventory
(tnv)
Net Change
From PRP18a
to PRP18b
(tnv)
Net Change
From PRPl8a
to PRPl8b
(o/"1
Point 133.216 I 10,109 -23.107 -t7%
Area (includes
Oil & Gas)53,806 53,805 No Change No Change
On-Road Mobile 9,728 9,728 No Chanee No Chanee
Off-Road Mobile 59,378 49,676 -9,702 -t6%
48
decrease of lTYo in point source NO* emissions was achieved, with 89% of the decrease due to
BART. Area and on-road source categories remained virtually unchanged.
Three ERG Technical Memorandums, documenting PRPlSa and PRPlSb emission inventories,
can be found in Chapter 4 of the Wyoming TSD.
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49
CHAPTER 5
SOI JRCE APPORTIONMENT AND REGION AL IJAZE. MODELING
5.1 Overview
Visibility impairment occurs when pollutants emitted into the atmosphere scatter and absorb
light, thereby creating haze. These pollutants can remain suspended in the atmosphere for long
periods and be transported long distances, thereby contributing to regional-scale impacts on
visibility in Class I areas. Air quality models offer the opportunity to better understand how
these impacts occur, by identiffing the sources that contribute to haze, and helping to select the
most effective emissions reduction strategies to improve visibility.
Wyoming Class I area visibility is affected by a combination of local and regional transport of air
pollutants. Chapter 4 provided information on emission inventories, as the first step in
identifying significant source categories causing visibility impairment. This chapter describes
the results of (l) source apportionment analysis showing the in-state and regional contribution of
haze sources, for the 20oZ worst and best visibility days, and (2) regional modeling projections of
visibility conditions by the 2018 benchmark or milestone, based on application of the regional
haze strategies outlined in this Plan, including BART. The source apportionment information
and regional modeling results are the basis for the demonstration of reasonable progress for the
20% worst and best days, described in Chapter 7.
Additional explanation of the source apportionment and modeling methodology can be found in
the WRAP Air Quality Modeling methods document in Chapter 5 of the Wyoming TSD.
5.1.1 Source Apportionment Analysis - PSAT and WEP
In order to determine the significant sources contributing to haze in Wyoming's Class I areas, the
Division has relied upon source apportionment analysis techniques provided by the WRAP for
this RegionalHaze Plan. This information can be found on the WRAP TSS website at
http://vista.cira.colostate.edu/TSS/Results/FlazePlanning.aspx. There were two techniques used
for source apportionment of regional haze. One was the Particulate Matter Source
Apportionment Technology (PSAT) tool, used for the attribution of sulfate and nitrate sources
only. The second was the Weighted Emissions Potential $fEP) tool, used for attribution of
sources of sulfate, nitrate, organic carbon, elemental carbon, fine PM, and coarse PM.
PSAT uses the CAMx air quality modelto show nitrate-sulfate-ammonia chemistry and applies
this chemistry to a system of tracers or "tags" to track the chemical transformations, transport
and removal of NO* and SOz. Emission scenarios used for the PSAT analyses were the Plan02c
and Basel8b. PSAT results were not regenerated for use in this document using the more
recently updated PlanO2d and PRPl8b emissions scenarios because of the time and resources
that would have been required. No significant changes were anticipated with additional
modeling runs. These two pollutants are important because they tend to originate from
anthropogenic (human-caused) sources. Therefore, the results from this analysis can be useful in
determining contributing sources that may be controllable, both in-state and in neighboring
states.
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WEP is a screening tool that helps to identiff source regions that have the potential to contribute
to haze formation at specific Class I areas. Unlike PSAT, this method does not account for
chemistry or deposition. The WEP combines emissions inventories, wind patterns, and residence
time of air mass over each area where emissions occur, to estimate the percent contribution of
different pollutants. Like PSAT, the WEP tool compares baseline (2000-2004) to 2018, to show
the improvement expected by the 2018 URP, for sulfate, nitrate, organic carbon, elemental
carbon, fine PM, and coarse PM.
As described in Section 5.2 below, the Division believes PSAT is a better tool than WEP for
identifuing the contribution of sulfates and nitrates to Wyoming Class I areas, because PSAT
does account for chemistry and deposition, and is better at identi$ing regional contribution of
sources from outside the WRAP region (see discussion in 5.2 below). For these reasons, the
Division has relied upon the PSAT results as the primary source apportionment tool for sulfates
and nitrates, and thus the better tool for identifying anthropogenic sources. The results from the
WEP analysis were used by the Division primarily to identifu the pollutants more commonly
associated with non-anthropogenic (natural) sources. Even though these sources are mostly
uncontrollable, it is still important to consider their relative contribution to haze.
The review of PSAT results in this chapter (discussed in 5.2 below) focus on the contribution on
sulfates and nitrates, while the WEP results focus on the contribution of organic carbon,
elemental carbon, fine PM, and coarse PM.
5.1.2 Regional Haze Modeling - CMAQ
The primary tool utilized by the Division for modeling regional haze improvements by 2018, and
for determining Wyoming's Reasonable Progress Goals (see Chapter 7), was the Community
Multi-Scale Air Quality (CMAQ) model. The CMAQ model was used to estimate 2018
visibility conditions in Wyoming and all Westem Class I areas, based on application of the
regional haze strategies presented in this Plan, including assumed controls on BART sources. A
more in depth description ofthe CMAQ model used to project 2018 visibility conditions can be
found in the WRAP Air Quality Modeling document referenced in Chapter 5 of the Wyoming
TSD.
The modeling was conducted by the RegionalModeling Center (RMC) at the University of
California Riverside, under the oversight of the WRAP Modeling Forum. Results can be found
on the WRAP TSS website at http://vista.cira.colostate.edu/tss/Results/FlazePlanning.aspx.
The CMAQ model was designed as a ooone atmosphere" modeling system to encompass
modeling of multiple pollutants and issues, including ozone, PM, visibility, and air toxics. This
is in contrast to many earlier air quality models that focused on single pollutants. CMAQ takes
into account emissions, advection and dispersion, photochemical transformation, aerosol
thermodynamics and phase transfer, aqueous chemistry, and wet and dry deposition of trace
species. The model requires inputs ofthree-dimensional gridded wind, temperature, humidity,
cloud/precipitation, and boundary layer parameters. The current version of CMAQ can only
utilize output fields from the MM5 meteorological model. MM5 is a state-of-the-science
Exhibit No. 4
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5l
atmosphere model that has proven useful for air quality applications and has been used
extensively in past local, state, regional, and national modeling efforts. MM5 has undergone
extensive peer review, with all of its components continually undergoing development and
scrutiny by the modeling community.
The RMC developed air quality modeling inputs including annual meteorology and emissions
inventories for a2002 actual emissions base case, a planning case to represent the 2000-2004
regional haze baseline period using averages for key emissions categories, and a2018 base case
of projected emissions determined using factors known at the end of 2005. All emission
inventories were prepared for CMAQ using the Sparse Matrix Operator Kemel Emissions
(SMOKE) modeling system. Each of these inventories underwent a number of revisions
throughout the development process to arrive at the final versions used in CMAQ modeling. The
development of each of these emission scenarios is documented under the emissions inventory
sections of the TSS.
The 2018 visibility projections were made using the PlanO2d and PRPlSb CMAQ 36-km
modeling results. Projections were made using relative response factors (RRFs) for each species:
RRF: [2018 Modeled SpecieslBaseline Modeled Species]
Projected Species Mass: Baseline IMPROVE Species x RRF
Projected Species Extinction: Conversion via IMPROVE Algorithm of Projected
Species Mass
There are three RRF calculation methods. These methods differ in how the days for the
calculation are selected. The Specific Days (EPA) method is the EPA default method, and single
species' RRFs are calculated across observed (IMPROVE) worst or best days in the base model
year. The Specific Days (EPA) method was the method utilized by the State of Wyoming. The
second method is the Quarterly Weighted method, whereby four quarterly species' RRFs are
calculated from the 20% worst or best days in each quarter, in spite of how those days compare
to the overall annualworst and best days. The third method is the Monthly Weighted method,
whereby twelve monthly species' RRF are calculated from the 2lo/obest or worst days in each
month, regardless of how those days compare to the overall annual worst and best days.
More information on how to use the visibility tool in connection with RRF factors can be found
at http://vista.cira.colostate.edMss/help/GettingStarted.aspx#MP, and specific information regarding how
RRF factors are calculated can be found in Section 6.4 of the 2007 EPA document "Guidance on the Use
of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for Ozone, PM2 5, and
Regional Haze" at http://www.epa.gov/scram00l/guidance/guide/final-03-pm-rh-guidance.pdf.
This EPA guidance was followed for setting up the "EPA Specific Days" option and other inputs
on the WRAP TSS Visibility Projections Tool, so all Class I areas in the WRAP region used
their TMPROVE site-specific monitoring and modeling data to derive the RRFs.
Generally, emissions inputs were prepared by individual states and tribes for point, area, and
most dust emissions categories. The following WRAP Forums were relied upon to summarize
this data and provide it to the RMC:
l)
2)
3)
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Point Source emissions were obtained from projects commissioned by the Stationary
Sources Joint Forum and the Emissions Forum.
Area Source emissions were obtained from projects commissioned by the Stationary
Sources Joint Forum and the Emissions Forum.
Mobile Source emissions were from projects commissioned by the Emissions Forum.
Fire (natural and anthropoeenic) emissions were from projects commissioned by the Fire
Emissions Joint Forum.
Ammonia. Dust. and Biogenic emissions were from projects commissioned by the Dust
Emissions Joint Forum and the Modeling Forum.
Emissions from Pacific offshore shipping were from a project conducted by the RMC.I
Other emissions from North America were from projects commissioned by the Emissions
Forum and the Modeling Forum. The Mexico emissions are from 1999, and were held
constant for 201 8. Canada emissions are from 2000 and were held constant for 2018.
Boundary conditions reaching North America from the rest of the world were from a
project commissioned by the VISTAS Regional Planning Organization, on behalf of the
five regional planning organizations working on regional haze.
The results from the CMAQ regional modeling analysis are discussed later in this section.
Because some WRAP states are still going through the difficult case-by-case BART
determinations for each EGU, the WRAP was not able to model all of the emission reductions
from BART and State long-term strategies in the most recent modeling effort. Therefore, the
modeling results and all graphics associated with the modeling results do not include BART and
long-term strategy reductions proposed in this SIP or any other WRAP SIPs that were not
available at the time WRAP modeled. The WRAP was only able to include enforceable
reductions that were on the books at the time of the last model run.
5.2 Major Source Categories Contributing to Haze in Wyoming
Figures in this section show profiles of the relative contribution of in-state vs. out-of-state
sources contributing to emissions in Wyoming's Class I areas, for the 20% worst and best days,
for the baseline (2000-2004) and future year (2018) scenarios, using the PSAT and WEP
techniques. The Wyoming Class I areas are grouped by general location (based on
representative IMPROVE monitoring sites).
As previously described, there are several differences between the PSAT and WEP techniques.
PSAT focuses on sulfate and nitrate contribution only, taking into account chemistry and
deposition. PSAT also estimates the contribution from all regions--the WRAP states, CENRAP
states2, Canada, Mexico, Pacific offshore (shipping), and "outside the domain" (global
transport). The WEP does not address sulfate and nitrate chemistry and deposition, and while it
I See WRAP TSS website under "Resources", "Emissions", and "Offshore Emissions" for summary, or go to
http://vista.cira.colostate.edr:/docs/wrap/emissions/Ot-fshoreEmissions.doc.
' CENRAP is a regional planning organization similar to the WRAP that is comprised of Nebraska, Kansas,
Oklahoma, Texas. Minnesota, Iowa, Missouri, Arkansas, and Louisiana.
*
*
*
*
a
*
*
*
Exhibit No. 4
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does estimate the contribution from Canada and Pacific offshore regions, it does not include
other regional contributions.
Based on these differences, the figures provided below focus on PSAT results for identifuing the
contribution of sulfates and nitrates (the primary anthropogenic source pollutants) and WEP
results for identiffing the contribution of organic carbon, elemental carbon, fine PM, and coarse
PM (commonly associated with non-anthropogenic sources).
Sections 5.2.1 through5.2.4 below show 20% worst- and best-day PSAT profiles on the
contribution of sulfate and nitrate at each IMPROVE monitoring site representing the Class I
areas in Wyoming. The pie charts display relative regional contributions to total annual modeled
sulfate and nitrate mass at the respective sites. The WRAP contribution is separated from the
rest of the pie for easy identification. The remaining pie slices are outside the Western United
States, for the regions described above.
The PSAT bar charts below the pie charts display source region and source category
contributions of sulfate and nitrate mass. There are five source categories listed--point, area,
mobile, anthropogenic fires (controlled burning), and natural and biogenic sources (mostly
wildfire and windblown dust). Estimated contributions outside the modeling domain (Outside
Domain) are also shown, and include Mexico, Canad4 and Pacific offshore emissions.
Sections 5.2.5 through 5.2.12 present WEP profiles for organic carbon, elemental carbon, fine
PM, and coarse PM, at Class I areas in Wyoming.
Unlike the PSAT figures, the WEP figures are bar charts only and summarize weighted
emissions by state and region for 12 source categories. These categories are windblown dust,
fugitive dust, road dust, off-road mobile, on-road mobile, off-shore, WRAP area oil and gas,
area, biogenic, natural fire, anthropogenic fire, and point. This analysis used more source
categories than the PSAT analysis to account for the additional pollutant Epes, and the more
natural origins contributing to these pollutants, including dust and fire sources.
5.2.1 PSAT Regional Contribution to Sulfate on 20oh Worst Days
Figures 5.2.1-l through 5.2.1-3 in this section illustrate the state and regional contribution of
sulfate to the 20oh worst days in Wyoming Class I areas for 2002 and 2018, based on PSAT
profiles for each IMPROVE monitoring site representing the nearest Class I areas. The figures
below consist of a pie chart that shows the estimated contribution of the major regions (WRAP
states, Pacific Offshore, CENRAP, Eastern U.S., Canada, Mexico, and Outside Domain
(global)). The bar chart is the WRAP source region portion, depicting Wyoming and other
westem states.
Note that in all the figures in this section, the majority of sulfate emissions originate outside the
WRAP region. However, the nitrate contribution, discussed in Sections 5.2.3 and 5.2.4, is much
higher within the WRAP region. The WRAP contribution is about one-third of the total, with the
exception of the Bridger site, where the contribution is more than one-half. The largest
contributor is outside the domain, or "global". Among the other regions (not including the
Exhibit No. 4
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54
WRAP region), Canada, followed by Pacific Offshore and Mexico are the next sizable
contributors.
Also indicated in these figures, the largest contributor of sulfate is generally from point sources.
The variation in sulfate contribution is based on the location of the Class I area monitoring site in
the State. For example, the contribution of sulfate from Canada and Montana are the highest in
the northernmost Class I area monitoring site, the North Absaroka Wilderness area. Similarly,
the sulfate contribution from Mexico is highest in the southernmost Class I area monitoring site,
the Bridger Wilderness area.
In terms of comparison of 2002 and 2018, it can be seen that the WRAP portion of the pie chart
remains nearly unchanged, with only slight increases in 2018. The source category that accounts
for this slight increase is primarily point.
Figure 5.2.1-1. PSAT Sulfate Contribution at Yellowstone NP, Grand Teton NP, and Teton
Wilderness on 20oh Worst
Regional Contributions to Sulfate 0n Worst 20% Visibility Days
Class I Areas - Grand Telon NP,lftft': Red Rock Lakes NWRW, MT: Teton W
UfY:Yellowstone NP, WY
:lAiRAP
fl Pacilic Oifshore
r lcerunep
Eastern U.S.
!Canda
i -lttexlco
[]outsitte oomt*n
2002
Sulfate 0.5 ug/m3
WRAF TSE - IIII'EIUIIE
201 I
Sulfate 0.5 ug/m3
WRAP Source Regionffype Contributions to Sulfate 0n Worst 20% Visibility Days
Class I Arsas - Grand Teton NP, VVf: Red Rock Lekes MT:Teton W. WY:Yellowstone NP. WY0.21
A 0.2{
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Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 65 of 206
Figure 5.2.1-2. PSAT Sulfate Contribution at North Absaroka Wilderness and Washakie
It is interesting to note that for the20Yo worst days at Yellowstone, the point source sulfate
contribution is approximately the same from Idaho as from Wyoming, most likely due to the
proximity of industrial sources and wind direction. There is also a noticeable contribution from
point sources in Canada, and a sizeable contribution from Mexico. Area and mobile sources
from Wyoming and Idaho are much less. Close to half of the sulfate comes from the area outside
the domain.
Wilderness Areas on 20oh Worst Visibil
Regional Contributions to Sulfate on Worst 20% Visibilily Days
Class lAreas - North Absaroka VY, WY:Washakie W, WY
I
k*ffihW
201 B
Sulfate 0.5 ug/m3
WRAP Source Region/Type Contributions to Sulfate on Worst 2D% Visibilrty Days
Class lAreas - North Absaroka W,l rY:Washakie W, Wf
(WRAP TS S - http ://v i sta. cira. co lostate.edu/tss0
It should be noted that for the 20o/o worst days at North Absaroka, point source sulfate
contribution is higher from Canada and Montana than from Wyoming, most likely due to the
proximity of industrial sources and wind direction. There is a much larger sulfate contribution
from Canada at the North Absaroka monitoring site than the other two monitoring sites
(Yellowstone and Bridger). Area and mobile sources are very minimal contributors to sulfate in
Wyoming. Approximately one half of the sulfate source is generated from the area outside the
domain.
@.
2002
Sulfate 0.5 ug/m3
IAIEAI TSE - II!'E,AIE
1A,RAP
ffi Pacific Offshore
, ,iCfrunnP
Eastern U.S.
ffi canada
rMexico
I .iodside Dqnaln
!eoint
flArea
Itvtotle
lednro. rircs
|*lna. rires a ao.
-----*****___1
i
I,IEAP TSS. IM&'IIE
zzoo3B?il
F@
fla
: E E E =>= E E 3 5 E E 3HiHHHHHHHfiHE*u3
3PEE
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 66 of 206
56
Figure 5.2.1-3. PSAT Sulfate Contribution at Bridger Wilderness and Fitzpatrick
Wilderness Areas 9n 207o*Worst VisibiliU Days
Regional Contributions to Sulfate on Worst 20% Visibility Days
Class lAreas - BridgerW,lA/'f: FitpahickW, WY
ffi
2gi2
Sulfate 0.6 ug/m3
WRAP Source Region/Type Contributions to Sulfate on Worst 20% Visibilify Days
___ Class lAreas - Ejidgerw U{Y: Fiupalrickw, WY _ I---lir0t :ctEots r- fJ--t i
-il
201 I
Sulfate 0.6 ugiml
usafroo lU
lARAP
[]lPacilic olfshore
CENRAP
Eastern U.S.
ffi canada
' Mexico
loutside Domain
I Oriside Domain
Ipoint
IArea
INorie
IAnthro. Fires
i' ltrtd. ries e ao.
zE E E 5 g E 3
PPEEPegERRRFREFR
?gEE=egEHff
oo
o
(WRAP TS S - http ://v ista. cira. co I ostate. edu/tss/)
For the 20oZ worst days at the Bridger monitoring site, overall sulfate levels are slightly higher
compared to the Yellowstone and North Absaroka monitoring sites. The majority of the sulfate
originates from point sources in Wyoming, Idaho, and Utah. There are also considerable
contributions from Canada and Mexico. Area and mobile sources, again, contribute a small
amount of sulfate in Wyoming. Approximately one-third of the sulfate is generated from the
area outside the domain.
5.2.2 PSAT Regional Contribution to Sulfate on20oh Best Days
Figures 5.2.2-l through 5.2.2-3 in this section illustrate the state and regional contribution of
sulfate to the 20oh best days in Wyoming Class I areas for 2002 and 201 8, based on PSAT
profiles for each IMPROVE monitoring site representing the nearest Class I areas. The figures
below consist of a pie chart that shows the estimated contribution of the major regions (WRAP
states, Pacific Offshore, CENRAP, Eastern U.S., Canada, Mexico, and Outside Domain
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 67 of 206
57
(global)). The bar chart is the WRAP source region portion, depicting Wyoming and other
western states.
Note that in all the figures in this section, the majority of sulfate emissions originate outside the
WRAP region. However, the nitrate contribution, discussed in Sections 5.2.3 and 5.2.4, is much
higher within the WRAP region. The WRAP contribution is about one-third to just less than
one-half ofthe total. The largest contributor is outside the domain, or "global". Among the
other regions (not including the WRAP region), Canada, followed by Pacific Offshore are the
next sizable contributors.
Also indicated in these figures, the largest contributor of sulfate is generally from point sources.
The variation in sulfate contribution is based on the location of the Class I area monitoring site in
the State. For example, the contribution of sulfate from Canada is the highest in the
northernmost Class I area monitoring site, the North Absaroka Wilderness area. Similarly, the
sulfate contribution from Idaho is highest in the southernmost Class I area monitoring site, the
Bridger Wilderness area.
In terms of comparison of 2002 and 2018, it can be seen that the WRAP portion of the pie chart
increases only slightly in 2018. The source category that accounts for this slight increase is
primarily point.
Exhibit No. 4
Case No.IPC-E-13-16
T. Harvey, IPC
Page 68 of 206
58
Figure 5.2.2-1. PSAT Sulfate Contribution at Yellowstone NP, Grand Teton NP, and Teton
Wilderness Area on 20%o Best Da
Regional Contributions to Sulfate on Best 20% Visibility Days
Class lAreas - Grand Teton NP, trtfY: Red Rock Lakes |'{WRW, MT:Teton W
WY:Yellowstone NP, WY
'l mAP
lPacifb Offshre
i--icerunap
Ecstan U.S.
!canaoa
l --iNexico
l]oddde oomain
Sulfate 0.4 ug/m3 Sulfate 0.4 ugfm3
Region/Type ConEibutions to Sulfate on Best 20% Visibility Days
h
201 I
Class I Areas - Grcnd Telon NP. WY: Red Rock Lalcs |{YYRV{, ICT: Teton W, WY: Yellorvsfrne NP, WY
zz<Uoo
60
b
2EO2
o.a
p o.raa9 o.rs
.e
f; o.rz
Bo*(J
$o*Ro o.o3
0.m
Ipoi*
!Arca
Ivoum
Irrto.rim
Eiht. riesa ao.
U qr:I!??+qqq?+iqHEe*HEHEfiEEEHHE
(WRAP TS S - http ://vi sta. cira. colostate.edu/tss/)
It is interesting to note that for the 20Yobest days at Yellowstone, the point source sulfate
contribution is approximately four times greater from Idaho and more than twice as much from
Canada as from Wyoming, most likely due to the proximity of industrial sources and wind
direction. There are also noticeable contributions from point sources in Utah, Montana, Nevada,
Washington and Oregon. The largest area and mobile source contribution comes from Idaho,
followed by Pacific Offshore and Canada. About half of the sulfate comes from the area outside
the domain.
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 69 of 206
59
Figure 5.2.2-2. PSAT Sulfate Contribution at North Absaroka Wilderness and Washakie
WRAP Source Regionffype ConEibutions to Sulfate on Best 20% Visibilrty Days
class lAreas - Noffi Absaroka W. YYY: trlashakiB W. WY
3 E T f;: s ! ? l+ q q ? T + i q
EEHgH*HfiEHEHHHHHE
4.2{
fi.021
!0.,t
E orst
E 0.12
.$o*oE 0.06t o.*
0.m
Wilderness Areas on 20o/" Best Visib
Regional Contributions to Sulfate on Best 20% Visibility Bays
Class lAreas - North Absaroka W, WY:Washakie W, ${Y
,_lwnnp
IPacifrc Ollshre
Icennnp
East$n U.S.
Icanaoa
L.J tuexico
ilor*iaeoormacn
2BE2
Sulfate 0.5 ug/mS
2018
Sulfate 0.5 ug/m3
I'IIEAF TSE-
'T'III:89
(WRAP TS S - http ://vi sta.cira.col ostate.edu/tssO
It should be noted that for the 20Yo best days at North Absaroka, point source sulfate contribution
is severaltimes higher from Canada and Idaho than from Wyoming, most likely due to the
proximity of industrial sources and wind direction. There is a much larger sulfate contribution
from Canada at the North Absaroka monitoring site than the other two monitoring sites
(Yellowstone and Bridger). Area and mobile sources are very minimal contributors to sulfate in
Wyoming. Approximately one half of the sulfate source is generated from the area outside the
domain.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 70 of 206
60
Regional Contributions to Sulfate on Best 20% Visibility Days
Class lAreas - BridgerW LafY: FitrpatrickW,1/\l/
,VWIAP
EPacitic otfshore
I r cemnnp
Eastern U.S.
!carnaa
[--lrcxlco
ilortrsideDonHn
- .. - Sulfate 0.3 ug/m3
UIISAT TSS. "II4IIE i
0.18o
Eo.r.
fi o.rz
EI ons
6(.,o OlE
E!(/, 0.m
0.00
Figure 5.2.2-3. PSAT Sulfate Contribution at Bridger Wilderness and Fitzpatrick
Wilderness Areas on 20Yo Best Visi
\4/RAP Source Region/Type Conributions to Visibility Days
WY: FlEratrlckW,WY
f]orrsua oonrir
Ip*,t
6*cc
IN*in
larlrro. rircs
nlg. rres a aio.
{;Efl
WNAP IES -
'.UMIID(WRAP TS S - http ://vi sta. cira. colostate.edu/tss/)
For the 20Yobest days at the Bridger monitoring site, overall sulfate levels are approximately the
same as Yellowstone and slightly lower than the North Absaroka monitoring site. The majority
of the sulfate originates from point sources in ldaho, with much smaller amounts from Wyoming,
Utah, and Nevada, respectively. Area and mobile sources, again, contribute a small amount of
sulfate in Wyoming. Well over one-half of the sulfate is generated from the area outside the
domain.
5.2.3 PSAT Regional Contribution to Nitrate on 20o/o Worst Days
Figures 5.2.3-l through 5.2.3-3 in this section illustrate the state and regional contribution of
nitrate to the 20olo worst days in Wyoming Class I areas for 2002 and 2018, based on PSAT
profiles for each IMPROVE monitoring site representing the nearest Class I areas.
In all the figures in this section, most of the nitrate originates from within the WRAP region, as
opposed to the sulfate contribution, which is mostly derived from outside the WRAP. The
WRAP contribution ranges from approximately one-half to nearly three-quarters of the total.
q fl: s E ? 44 q q q ? { i ?E=EgffiHEfHEEffHEo
o
zz<uoo
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 71 of206
6l
Other sizeable contributions of nitrate are generated from outside the domain, and to a much
lesser extent, Canada and Pacific offshore. Contributions from other regions are negligible.
These figures indicate that overall, the majority of nitrate stems from mobile sources. In all but
one of the Class I area monitors (Bridger), contributions from other states and Canada are much
larger than contributions from inside Wyoming.
In terms of comparison of 2002 and 2018, these figures indicate that the WRAP portion of the
pie chart has a significant decrease in nitrate by 2018. Most of this decrease can be attributed to
the numerous Federal and state "on-the-books" requirements for mobile sources (see Chapter 8,
Long-Term Strategy).
Figure 5.2.3-1. PSAT Nitrate Contribution at Yellowstone NP, Grand Teton NP, and Teton
Wilderness Area on 207o Worst Visibilitv Da
Regional Contributions to Nitrate on Worst 200/o Visibility Days
Class lAreas - Grand Teton NP, WY: Red Rock Lakes MVRW, MT:Teton W
WY: Yellowstone NP, VTr'
,VI,EAP
lPacific Oflshore
L_j ceNnsp
Eastern U.S.
!Carnaa
,- ltr,texico
lJoriside Domain
2002
Nitrate 0.3 ug/m3uJFArrsa-ffim I
201 I
Nitrate 0.2 ug/m3
WRAP Source Regionffype Contributons to Nitrate on Worst 2D% Visibility Days
0.tB Class I Areas - Grand Teton NP, WY: Red Rock Lakes NWRW, MT: Telon W, Vfy:Yellowstone NP, WY
0.tEe
$ onz
E006o
E o.ostI o.o+Eoo 0.03g
E ooa2
I
I
F
il
rl
li
llo,rgoc oonair
Ipunt
Slnrea
Itrtooite
I*ttro. rles
[]tgt. Fk?s I Bo,
u3;;.. F a
triRAt rsa - loEm l
3 E q H: E E ? ++ q + q i f E q
HHH;HgHHHfiHHHHHHH
(WRAP TS S - http ://v i sta.cira.co lostate.edu/tssA
For the 20oZ worst days at Yellowstone, significant nitrate contributions can be seen from Idaho,
Washington, and to a lesser extent, Oregon, Utah and Wyoming. Mobile sources make up the
majority of the overall contributions. However, the projected 201 8 area source contributions for
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 72 of 206
62
Idaho and Wyoming exceed the mobile source contribution. In most cases, nitrate contributions
are projected to decline significantly by 2018, with the exception of a small increase within
Wyoming.
Figure 5.2.3-2. PSAT Nitrate Contribution at North Absaroka Wilderness and Washakie
Wilderness Areas on20oh Worst Visibi
Class lAreas - Norh Absarol€ W.llY:Washakie W. V{Y
[]orsueomrt*r
Ipoi*I*."
lmoue
IErttro. rircs
f]r*. rrc a Eo.
(WRAP TS S - htto ://vista. cira. colostate.edu/tss/)
For the 20Yo worst days, significant nitrate contributions for North Absaroka can be seen from
Idaho, Montana, and Canada. The extent of contribution from Montana and Canada is greater at
this monitoring site due to their close proximity. The extent of ldaho's contribution is less at this
site compared to the Yellowstone site, also due to proximity. Smaller contributions of nitrate
originate from Wyoming, Washington, Utah, and Oregon. Mobile sources appear to be the
dominant contributor overall; however, point sources in Montana are a large factor.
0.10
o
5o*Ep
E o.m
oI
E 001
otlom
0m E!?{+qJ9gEE9EERFEF
2ZOoO33?d;;9
=6oER.FI
us
9EFE
T??+iqEHEEEE
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 73 of 206
Regional Contributions to Nitrate 0n Worst 20% Visibility Days
Class I Areas - North Absaroka UY, tP{Y: Washakie W, lta.ff
, .--, ",1
.,'l,l
2EO2
,VYR,AP
IPacific Offshore
l"-"lcerunpp
Eastern U.S.
Icrnoa
lj[,lcxbo
florlsiue oonr*n
-:= -.-:l{irate 0.3 ug/m3Tss-tErE/E i
WRAP Source Regionllype Contibutions to Nifate on Worst 20% Visibility Drys
63
Figure 5.2.3-3. PSAT Nitrate Contribution at Bridger Wilderness and Fitzpatrick
Regional Contributions to Nitrate on Worst 20% Visibility Days
Class lAreas - BridgerW, WY: FiEpatrickW, WY
, jl4RAP
f Pacific Oflshore
il.lcerunm
Eastem U.S.
Icanada
_-ituexico
[Jo,isioe oorruin
.- Nitrate 0,2 ug/m3rrun*lrse-u re i
0.04
o
Eo*
c.et
E 0.m0,Io(J
a,t 0.01
,,
0.m
Wilderness Areas on 20"/" Worst Visibil
W,VtY: Fi@etrickW,UVY
flo.lsue ounain
Ipoi,t
!*o
Iuoone
!err*o.rires
DNd. Frcs & EIo.
Oo==.-*.-.,--!!-."H E EuRArr-iffi d ff
(WRAP TS S - http ://v ista. cira. colostate.edu/tssA
Unlike Yellowstone and North Absaroka, for the 20oZ worst days the largest nitrate contribution
for Bridger originates within Wyoming. Point sources in 2002 and projected area and point
sources in 2018 appear to be the largest contributors within Wyoming. The next highest
contribution comes from Utah, followed by Idaho. It is interesting to note that contributions
from California (mostly mobile source) in2002 were greater than contributions from Canada or
Montana.
5.2.4 PSAT Regional Contribution to Nitrate on2Ooh Best Days
Figures 5.2.4-l through 5.2.4-3 in this section illustrate the state and regional contribution of
nitrate tothe20Yo best days in Wyoming Class I areas for 2002 and 2018, based on PSAT
profiles for each IMPROVE monitoring site representing the nearest Class I areas.
In all the figures in this section, most of the nitrate originates from within the WRAP region, as
opposed to the sulfate contribution, which is mostly derived from outside the WRAP. The
EB5$E3
HEHHHT
q $: I I ? 44HgH;EHHE
Exhibit No. 4
Case No. IPC-E-13-',l6
T. Harvey, IPC
Page74 ol 206
WRAP Source Region/Iype Contributions to NitraE on Worst 20% Visibility Days
64
WRAP contribution ranges from approximately one-half to nearly three-quarters of the total.
Other sizeable contributions of nitrate are generated from outside the domain, and to a much
lesser extent, Canada and Pacific offshore. Contributions from other regions are negligible.
These figures indicate that overall, the majority of nitrate stems from mobile sources. Point and
area sources are the next largest categories of nitrate contribution, especially at the Bridger
monitoring site, where Wyoming's area and point source contribution is the most sizeable. In all
but one of the Class I area monitors (Bridger), contributions from other states and Canada are
much larger than contributions from inside Wyoming.
In terms of comparison of 2002 and 2018, these figures indicate that the WRAP portion of the
pie chart has a significant decrease in nitrate by 201 8. Most of this decrease can be attributed to
the numerous Federal and state "on-the-books" requirements for mobile sources (see Chapter 8,
Long-Term Strategy).
Figure 5.2.4-1. PSAT Nitrate Contribution at Yellowstone NP, Grand Teton NP, and Teton
Wilderness Area on 20o/o Best Visibili
WRAP Source Region/Type Contributions to Nisate on Best 2090 Visibility
Class I Areas - Grand Telon NP, \ ,Y: Red Rock Lakes IWYFW, MT: Teton W, WY: Yellowstone NP, WY
i. .,Otisije Domah
!pont
Elnrea
Iuooite
Ie*uo. rircs
l'-lu*. rres a ao.
f.l!_il]".
0.18
0.166'
fr o.r+
E 0.12
.9
E o.1ot
Eoffioo 0.(D0
E o.or
0.02
0.00 a5IE3
ffEHHH
>Eozor
8RF
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 75 of 206
Regional Contributions t0 Nitrate on Best 20% Visibility Days
Class lAreas - Grand Teton NP, V\rY: Red Rock Lakes NWRW, MT: Telon W
14ff: Yellowstone NP, WY
V\ftAP
ffi Pacific Olfshore
CENRAP
Eas'tern U.S.
Slcanada
. Mexico
i ]o*siae oomain
For the 20Yobest days at Yellowstone, significant nitrate contributions can be seen from Idaho,
Utah, California and Washington, and to a lesser extent, Canada, Montana, Oregon and
Wyoming. Mobile sources make up the majority of the overall contributions. Nitrate
contributions are projected to decline significantly by 2018.
Figure 5.2.4-2. PSAT Nitrate Contribution at North Absaroka Wilderness and Washakie
Wilderness Areas on 20oh Best Vis
Class I &eas - Nor& Ahsaroke W WY: Washakis W, WY
[]o,rsitom*
Ipont
&nro
Ixotic
Iartho. Ftrcs
f:lNat. Fles s Bio,
zz<UUO
018
E o.rsf
f; o.rz
E o-*
ot o.m
E2 o.B
0.m u3
8E
oU
R
fu
a
: E r ? ++ T q q ? q i ?H=fiHHHHffHHEHfi
(WRAP TS S - http ://vi sta.cira.colostate.edu/tssA
For the 20Yobest days, significant nitrate contributions for North Absaroka can be seen from
Idaho, Canada, Utah, California and Montana. The extent of contribution from these states and
Canada is due in part to wind direction and proximity. The extent of ldaho's contribution is less
at this site compared to the Yellowstone site, due mostly to proximity. Smaller contributions of
nitrate originate from Washington, Nevada, Oregon, Wyoming and North Dakota. Mobile
sources appear to be the dominant contributor overall; however, point sources in Utah and
Califomia and area sources in Idaho and Canada are a large factor.
Exhibit No. 4
Case No. IPC-E-13-'16
T. Harvey, IPC
Page 76 of 206
Regional Contributions to Nitrate on Best 20% Visibility Days
Class lAreas - North Absaroka W, WY: Washakle W, WY
\AIRAP
EPacific Olfshore
i lcerump
Eas'tern U.S.
!Canada
i ,ldexbo
[-]orrsiae oomain
WRAP Source Region/Iype Contributions to Nifate on Best 20% Visibility Days
66
Figure 5.2.4-3. PSAT Nitrate Contribution at Bridger Wilderness and Fitzpatrick
Wilderness Areas on 20oh Best Visi
Regional Contributions to Nitrate on Best 2070 Visibility Days
Class lAreas - BridgerW, WY: FitrpatrickW WY
,l mAP
IPacific ollshse
[-lcerunm
Eastern U.S.
!carnaa
I it*texico
L-l o*side oomatn
2002
:i._,:-_-:-..: , Nitrate 0.8 ug/m3
201 E
Nifate 0.5 ug/m3
018
fiors
[.,,
Eo*
?omtio*
0.m
WRAP IEA- UII{TID
WRA,P Source to NiraE on Best 20% Visibility
llurstseDdo*l
Ip**Iar-
Iuoue
Inr*no.nes
Eru. r.o a aio.
{froo
(WRAP TS S - http ://vista.c ira.colostate.edu/tssA
For the 20Yobest days the largest nitrate contribution for Bridger originates within Utah. Mobile
and point sources appear to be the largest contributors within Utah. The next highest
contribution comes from ldaho, followed by Wyoming and Califomia. It is interesting to note
that contributions from California (mostly mobile source) were greater than contributions from
Canada or Montana.
5.2.5 WEP Potential Contribution to OC on20oh Worst Days
Figures 5.2.5-l through 5.2.5-3 in this section represent the contribution of organic carbon to the
20oZ worst days in Wyoming Class I areas for 2002 and 2018, based on the WEP profile for each
IMPROVE monitoring site representing the nearest Class I areas.
In general, the figures below primarily reflect the contribution of fire sources - mostly natural
fire (wildfire) and to a lesser degree, anthropogenic or controlled burning (forestry, agricultural,
and residential burning). Area source organic carbon is from woodstoves and other urban related
us
66
--_-F_ E
IEE. "D'IID
EHis!?++qqqT{i?Hg-EHEEHffEfiEHHE
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page77 of206
Class lAraas - Brld0erV{, WY: Fi@atrlck w, ytlY
67
sources. Area source contributions of organic carbon are the lowest at the Yellowstone Class I
area monitoring site due to its location, which is not near any urban areas.
When comparing 2002 and 2018, the figures show a slight reduction in future years, mainly due
to a projected drop in anthropogenic fires. Most other sources remain fairly constant.
The WRAP TSS website states that the Primary Organic Aerosol parameter represents organic
carbon compounds emitted directly as particulates, but not secondary organics which condense
from a gaseous state after being emitted.
Figure 5.2.5-1. WEP Potential Contribution to OC at Yellowstone NP, Grand Teton NP,
and Teton Wilderness Area on 207o Worst
Aerosol on Worst
200&0il BasBllnB & 2018 PRPb
Class I Areas - Grand Teton NP. WY: Rsd Rock Lakes VVY: Yellorristone NP. WY
70.00
60.m
50.(n
t 4o.m
EId ilr.m
20.00
(WRAP TS S - http ://v i sta.cira. colostate.edu/tssO
For the 200lo worst visibility days at Yellowstone, the most sizeable organic carbon contribution
is from Wyoming natural fire sources, and to a minimal extent, anthropogenic fire followed by
area sources. A much smaller contribution from these sources in Idaho can be seen.
luane
EFultivc Dud
f nmoouc
Iot.Ro*trrotitc
Ion-noqa uoola
Mott-stsc
funaplraoao
@ar*
llaoqmic
l- itewerrs
f arr*o rno
Iportl0.m
0.00
naeE+!ioaotatEeoaoo60606060606060606
EEEqEqFqEqFIFqHqEqz2rri?55sPaa5sgfll
+D!!AACDr4rn30?r?n
EEEECEAEFEEEEEFEHE
,*r**_;fur s s 3 E E E g a H H o o E E = r
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 78 of 206
68
Potential Sources and Areas of Primary Organic
Class I Areas - North Abs WY:Washahe W, wY
It^ouig
ElFuqtivc Dusl
lnoao ousl
l_ lor-aou uoutc
!on-noaauobte
fflott-strorc
luneetcaoeo
Eerca
,,-l aogpric
lldurd Fla
I*ttro rir"
Ipoirt
I
I
44.(n
40.m
38.00
32.00
28.m
E ze.moI zo.m
I 6IXl
12.fi
8.m
4.00
0.00 3838383638t638388888t83t36383t383838
HEHETEEEHEHEHEEEHE HEHEHEHEHEHEHEHEE*
*ou*.,#,i t A
=
ge e ri g n a a f u * * ii**t - i i d d da = 1i * * i
200G04 BaselinE & 201 I PRPb
i-.E
ilLf.
l
'.-T.---
I--
Ir ,,-._
i=r
ll rt
-1
--++-
--l@;
Figure 5,2.5-2. WEP Potential Contribution to OC at North Absaroka Wilderness and
Washakie Wilderness Areas on}0o/o Worst VisibiliW Days
urces and Areas of errmary Org Days
(WRAP TS S - http ://vi sta.c ira.co lostate. edu/tss/)
For the 20o/o worst visibility days at North Absaroka, the most sizeable organic carbon
contribution is from Wyoming natural fire sources, and to a minimal extent, anthropogenic fire
followed by area sources. However, a large contribution from these sources also comes from
Idaho, followed by Montana, and to a lesser extent, Oregon.
Figure 5.2.5-3. WEP Potential Contribution to OC at Bridger Wilderness and Fitzpatrick
Wilderness Areas on 20o/o Worst Visibil
Potential Sources and Areas anrc on Worst 20% Visibility Days
200tr04 Baseline & 201 I PRPb
60.(I)
50.m
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For the 20Yo worst visibility days at Bridger, the most sizeable organic carbon contribution is
from Wyoming natural fire sources, and to a minimal extent, area sources, followed by
6q€q6
hE*HE5f*lt
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 79 of 206
anthropogenic fire. Idaho, Oregon, Utah and Califomia are the next largest contributors,
respectively.
5.2.6 WEP Potential Contribution to OC on 20o/" Best Days
Figures 5.2.6-l through 5.2.6-3 in this section represent the contribution of organic carbon to the
2}Yobest days in Wyoming Class I areas for 2002 and 2018, based on the WEP profile for each
IMPROVE monitoring site representing the nearest Class I areas.
In general, the figures below primarily reflect the contribution of fire sources - mostly natural
fire (wildfire) and to a lesser degree, anthropogenic or controlled burning (forestry, agricultural,
and residential burning). Area source organic carbon is from woodstoves and other urban related
sources. Area source contributions of organic carbon are the lowest at the Yellowstone Class I
area monitoring site due to its location, which is not near any urban areas.
When comparing 2002 and 2018, the figures show a slight reduction in future years, mainly due
to a projected drop in anthropogenic fires. Most other sources remain fairly constant.
The WRAP TSS website states that the Primary Organic Aerosol parameter represents organic
carbon compounds emitted directly as particulates, but not secondary organics which condense
from a gaseous state after being emitted.
Figure 5.2.6-1. WEP Potential Contribution to OC at Yellowstone NP, Grand Teton NP,
and Teton Wilderness Area on 20oh Best Visibiti
Potential Sources and Areas of Primary Organic Aerosol Emissions on Best 20% Msibility Dale
Class I Areas - Grand Teton NP. WY: Red Rock Lakss MT: TBton W. WY: Ysllolvstone NP. WY
Iuau:*
ElFuctlve Dusi
lnoaa oust
llott-Roau uoorc
Ior-noaoxootc
ffiott-gwc
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ffiera"
llaosaic; :NeurdFta
l.qffroRrc
Ipoit
(WRAP TS S - http ://vi sta. cira.colostate.edu/tss/)
For the 20%obest visibility days at Yellowstone, the most sizeable organic carbon contribution is
from Wyoming natural fire sources, and to a minimal extent, anthropogenic fire followed by area
sources. A much smaller contribution from these sources in Idaho can be seen.
80.m
70.8
60.00
883838r888t8888888 3888383888t8383838
EEREHEHEHEEEHEgTHE AEEE*EHEEE$E$EEENN
,fui s s 3 3 g E 8 8 H H o o E $ = E e 2ez* t 5 5 P R a I s s f * I I
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 80 of 206
2000-04 BesEllnE & 201 I PRPb
50.m
E**e
30.00
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t0.m
0.fit
70
Class lAreas - North Absaroka W, YYY: lflashakis W, WY
-'F
Potential Sources and Areas of Primary Organic Aerosol Emissions on Best 20% Visibility Days
2000-04 Baseline & 201 I PRPb
Iuaorst
fl ruqrtive Dud
IRoad Dust
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lon-noaa uooita
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**,*,# J * f f e E B s * n a a E E i * dd**t * d d d d d a i = * * i *
Figure 5.2.6-2. WEP Potential Contribution to OC at North Absaroka Wilderness and
Washakie Wilderness Areas on?0o/o ne$JllQtltty llys _
(WRAP TSS - http://vista.cira.colostate.edu/tss/)
For the 20o/obest visibility days at North Absaroka, the most sizeable organic carbon
contribution is from Wyoming natural fire sources, and to a minimal extent, anthropogenic fire
followed by area sources. However, a contribution from these sources nearly equal in size
comes from ldaho. Oregon, Montana and California, respectively, are the next largest
contributors.
Figure 5.2.6-3. WEP Potential Contribution to OC at Bridger Wilderness and Fitzpatrick
Wilderness Areas on20oh Best Visibili
Iuooust
[-] Fugtive Dust
Inmo oust
l Olf-Rod ilobib
lon-Road Mobil;
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Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 81 of 206
71
For the 20%obest visibility days at Bridger, the most sizeable organic carbon contribution is from
Wyoming natural fire sources, and to a minimal extent, area and anthropogenic fire sources.
Idaho, Oregon, California and Utah are the next largest contributors, respectively.
5.2.7 WEP Potential Contribution to EC on 20o/o Worst Days
Figures 5.2.7-l through 5.2.7-3 in this section represent the contribution of elemental carbon to
the 20o/o worst days in Wyoming Class I areas for 2002 and 2018, based on the WEP profile for
each IMPROVE monitoring site representing the nearest Class I areas.
In general, the figures below primarily reflect the contribution of fire sources - mostly natural
fire (wildfire) and to a much lesser degree, off-road mobile and anthropogenic or controlled
burning (forestry, agricultural, and residential burning). Off-road mobile elemental carbon
contributions are minimalto none at Yellowstone compared to North Absaroka and Bridger.
When comparing 2002 and 201 8, the figures show a reduction in future years, mainly due to a
projected drop in off-road mobile and anthropogenic fire emissions. Most other sources remain
fairly constant.
Figure 5.2.7-1. WEP Potential Contribution to EC at Yellowstone NP, Grand Teton NP,
and Teton Wilderness Area on 207o Worst
Potential Sources and Areas of Elemental Carbon Emissions on Worst 20% Visibility Days
Class I Arsas - Grand Telon NP. WY: Red Rock Lakes l{T: T8ton W. WY: Yellowsbne NP. WY
60.@
50.(n
E 40.m
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HONE
(WRAP TS S - http ://vi sta. cira.co lostate.edu/tssD
For the 20% worst visibility days at Yellowstone, the most sizeable elemental carbon
contribution is from Wyoming natural fire sources, and to a minimal extent, anthropogenic fire.
A much smaller contribution from these sources, except for off-road mobile, can be seen in
Idaho.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 82 of 206
200tr04 Baseline & 201 S PRPb
72
l--*- Potentd-sources and Arias oi eiemental Carbon emissions on Worit iO% Visinitity Oays
I 2000-04 Baseline & 201 g PRPb
| ,0.*
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iEEEHEHEEEHEHEEE
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n Fudive Dust
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Figure 5.2.7-2. WEP Potential Contribution to EC at North Absaroka Wilderness and
Washakie Wilderness Areas on2Ooh Worst Visibility Days
(WRAP TS S - http ://vista.c ira. co lostate. edu/tssA
At North Absaroka for the 20o/o worst visibility days, natural fire sources from Wyoming is the
largest contributor to elemental carbon, followed by anthropogenic fire and off-road mobile, and
to a much lesser extent, area sources and on-road mobile. Idaho contributes a significant amount
of these sources, followed by Montana and to a lesser extent, Oregon. California, Washington
and Utah, respectively, also show some measurable contributions from these sources.
Figure 5.2.7-3. WEP Potential Contribution to EC at Bridger Wilderness and Fitzpatrick
Wilderness Areas onl0o/o Worst Visibilitv Davs
Potential Sources and Areas of Elemental Carbon Emissions on Worst 20% Visibility Days
45.00
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Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 83 of 206
200G04 BasBlino & 201 I PRPb
Class I Areas - BridoBrW. WY:
(WRAP TS S - http ://vi sta.c i ra.colostate.edu/tssl)
For the 20oZ worst visibility days at Bridger, Wyoming is the largest contributor. Natural fire is
the largest component of contribution followed by off-road mobile, anthropogenic fire, area and
on-road mobile, respectively. ldaho, Utah, Oregon and California, respectively, have the next
sizeable contributions from these sources at this site.
5.2.8 WEP Potential Contribution to EC on20o/o Best Days
Figures 5.2.8-l through 5.2.8-3 in this section represent the contribution of elemental carbon to
the 20%o best days in Wyoming Class I areas for 2002 and 2018, based on the WEP profile for
each IMPROVE monitoring site representing the nearest Class I areas.
In general, the figures below primarily reflect the contribution of fire sources - mostly natural
fire (wildfire) and to a much lesser degree, off-road mobile and anthropogenic or controlled
burning (forestry, agricultural, and residential burning). Off-road mobile elemental carbon
contributions are smaller at Yellowstone compared to North Absaroka and Bridger.
When comparing 2002 and 201 8, the figures show a reduction in future years, mainly due to a
projected drop in off-road mobile and anthropogenic fire emissions. Most other sources remain
fairly constant.
Figure 5.2.8-1. WEP Potential Contribution to EC at Yellowstone NP, Grand Teton NP,
and Teton Wilderness Area on 20Yo Best Visibi
Potential Sources and Areas of Elemental Carbon Emissions on Best 20% Visibility Days
Class I ArBas - Grand Teton NP, WY: RBd Rock Lakes MT:Teton W, UVY:Yellowstone NP, WY
60.m
50.00
E 4o.m
86L 3o.m
20.m
Itma,*
ElFuqlive trud
Inmo oua
i-lot-no*uotita
I on-Roaa Mobic
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lunepnraoao
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l" iaogeric
. NdurdFre
Ianronre
lporr10.m
0.00 3838383838t838t8t8
qqqEEqEqEqEtEqqqFq
E?r= = = U 5I P I a 5 5I $ E I
HE
=E
8888r8r838r8r838
HEHEHEHEEEEEFEHE
,^Tjs$3EEE88HHonEE
(WRAP TS S - http ://v i sta.cira. colostate.edu/tss/)
For the 20Yobest visibility days at Yellowstone, the most sizeable elemental carbon contribution
is from Wyoming natural fire sources, and to a minimal extent, anthropogenic fire followed by
off-road mobile. A smaller contribution from these sources, except for off-road mobile, can be
seen in Idaho.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 84 of 206
200G04 Basslins & 201 I PRPb
74
33.(I)
30.00
27.00
24.(xt
21 ,00
I ro.oo6
& rs.m
12.@
9.00
6.00
3.m
0.m
Figure 5.2.8-2. WEP Potential Contribution to EC at North Absaroka Wilderness and
Washakie Wilderness Areas on 20o/o Best Visibility Days
t--Potential Sources and Areas of Elemental Carbon Emissions on Best 2070 Visibility Days
2000-04 Bassline & 201 I PRPb
Class lffeas - Norlh Absaroka W. WY: lryashakie W, l.iY
Iuoost
U Fugiuve Dust
Inoao oust
Ollffod trlot le
lon-noau t'looltc
L-lott-strae
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El,c.*
lAogEnie
NduralFire
Ila*orire
IPort
(WRAP TS S - http ://vi sta.c ira.co lostate.edu/tss,)
At North Absaroka for the 20Yobest visibility days, natural fire sources from Wyoming, Idaho,
Oregon and Montana are the largest contributors to elemental carbon. The next largest source is
off-road mobile, mainly originating in Idaho and Utah. Anthropogenic fire, area sources and on-
road mobile contribute to a much smaller degree in comparison to natural fire and off-road
mobile. Idaho contributes the most significant amount of elemental carbon overall, followed by
Wyoming, Oregon, Montana, Utah and California, respectively.
Figure 5.2.8-3. WEP Potential Contribution to EC at Bridger Wilderness and Fitzpatrick
Wilderness Areas on 20o/o Best Visibi
Potential Sources and Areas of Elemental Carbon Emissions on Best 20% Visibility Days
200t}o4 Easeline & 201 B PRPb
Class I Areas - Bridger W, nrY: FiEpatrick W, V\ff
r83838383636t8383888383838383t383t38
HEEEE ggEHEEEEEEEEE N*EEATHEEEHEHEHEEE
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Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 85 of 206
75
For the 20%obest visibility days at Bridger, Wyoming is the largest contributor. Natural fire is
the largest component of contribution followed by off-road mobile, anthropogenic fire, area and
on-road mobile, respectively. Idaho, Utah, Oregon and Califomia, respectively, have the next
sizeable contributions from these sources at this site.
5.2.9 WEP Potential Contribution to Fine PM on 207o Worst Days
Figures 5.2.9-l through 5.2.9-3 in this section illustrate the contribution of fine PM to the 20Yo
worst days in Wyoming Class I areas for 2002 and 2018, based on the WEP profile for each
IMPROVE monitoring site representing the nearest Class I areas.
In general, the figures below represent contributions which consist predominantly of dust sources
(mining, construction, unpaved roads and agriculture), with smaller contributions from area
sources (woodstoves, etc.) and point sources, followed by natural fire and anthropogenic fire.
Note that the largest contribution from natural fire in all three figures originates in Wyoming,
with the most sizeable contribution affecting the Yellowstone monitoring site.
When comparing 2002 and 2018, these figures indicate a consistent increase in most cases in fine
PM emissions, primarily from dust sources. However, at the Bridger site, a small increase in
point source contribution is noted.
Figure 5.2.9-1. WEP Potential Contribution to Fine PM at Yellowstone NP, Grand Teton
NP, and Teton Wilderness Area on 207o Worst Visibi
Potential Sources and Areas of Fine PM Emissions on Worst 20% Visibility Days
?0tlt}o4 easslins & 201 I PRPb
Class I Areas - Grand Teton NP. WY; Red Rock Lakss I{WRW. HT:Tsbn W. UUf:Ysllowstone NP. WY
r
r
-E
li
I
li
E6rffi tA
tlrlnr
(WRAP TS S - http ://v i sta.cira.colostate. edu/tss/)
The20Yo worst visibility days at Yellowstone are dominated by fine PM contributions from dust
sources in Idaho and Montana. Idaho also contributes a sizeable amount of fine PM area source
emissions. Wyoming's fine PM contributions are slightly higher than Montana's, but originate
mainly from natural fire sources, followed by dust sources. Less significant PM contributions
from dust sources are noted in Washington, Oregon, Canada, and Utah, respectively.
30.m
27.N
2tt.00
Iuaurs
ErraftueOuC
Inoaa oust
l]ornoaa mouc
lon-Rodilobtc
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Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 86 of 206
76
Potential Sources and Areas of Fine PM Emissions on Worst 20% Visibility Days
2000-04 gaselins & 201 I PRPb
Itae orrst
nFugfov? Dud
IRoad DustI ;oll-Roao Mobila
!OnnoaU uoUe
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Figure 5.2.9-2. WEP Potential Contributions to Fine PM at North Absaroka Wilderness
and Washakie Wilderness Areas on20o/o Wg1gqVE D!!!y !ry1__
(WRAP TS S - http ://vi sta. cira. co I ostate.edu/tssl)
Dust sources in Montana are the overwhelming fine PM contributor for the 20oh worst visibility
days at North Absaroka, mainly due to the proximity of the monitoring site. The next largest
contributor is ldaho, followed closely by Wyoming and Canada. The second largest source in
Wyoming is natural fire, and in ldaho and Montana it is area sources. Dust sources in
Washington and Oregon contribute to fine PM at North Absaroka, but to a much lesser degree.
Figure 5.2.9-3. WEP Potential Contribution to Fine PM at Bridger Wilderness and
Fitznatrick Wilderness Areas on20oh Worst Visibili
on Worst 20% Visibility
+
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(WRAP TS S - http ://vi sta. c i ra.co lostate.edu/tssl)
Exhibit No. 4
Case No.lPC-E-'13-16
T. Harvey, IPC
Page 87 of 206
2000-04 Basoline & 201 I PRPb
33.00
30 00
27.N
24.m
21.00
$ re.oo
S rs.oo
12.m
9.m
6.m
3.00
0.00
77
For the 20olo worst visibility days at Bridger, Wyoming is the dominant contributor to fine PM.
Contributions are split fairly evenly between dust sources, point sources and natural fire, with
dust sources being slightly more predominant. Idaho has quite sizeable contributions consisting
of dust sources, followed by area sources. Utah is the next largest contributor with dust sources
followed by point sources making up the majority of the components. Montana, Oregon,
Washington, California and Canada, respectively, all have sizeable contributions of fine PM as
well.
5.2.10 WEP Potential Contribution to Fine PM on 20%o Best Days
Figures 5.2.10-l through 5.2.10-3 in this section illustrate the contribution of fine PM to the20Yo
best days in Wyoming Class I areas for 2002 and 2018, based on the WEP profile for each
IMPROVE monitoring site representing the nearest Class I areas.
In general, the figures below represent contributions which consist predominantly of dust sources
(mining, construction, unpaved roads and agriculture), with smaller contributions from area
sources (woodstoves, etc.) and point sources, followed by natural fire and anthropogenic fire.
Note that the largest contribution from natural fire in all three figures originates in Wyoming,
with the most sizeable contribution affecting the Yellowstone monitoring site.
When comparing 2002 and 201 8, these figures indicate a consistent increase in most cases in fine
PM emissions, primarily from dust sources. However, in all three figures, a small increase in
point source contribution is noted.
NP, and Teton Wilderness Area on 207o Best Visib
es and Areas of Fine 0n
2000-04 Besslins & 201 I PRPb
$m
30.@
27fi
24.m
am
$ ro.m
X rs.oo
12.fi'
9.(I,
6.m
3.00
0.m
Iuaousl
SfrafivcPuu
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ulotao*xootc
!or-Roxobtc
Eot-snore
lr,RAPAr6aoEoIar-
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Ijnewe rrc
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lpoit
eE=acDeDrrcola€orasa?rro=oln?Dro*arD
EEEEEEFEEEEEHEEEHE EEHEEEEEEEEEHEEEEE
**u*-,i** i d d
=
e g e 8 g g i a q E * * d d * * t * i i d d d I E + I I * E
(WRAP TS S - http ://vista.cira.colostate. edu/tss/)
The20Yo best visibility days at Yellowstone are dominated by fine PM contributions from dust
sources in Idaho, Wyoming and Montana. Idaho also contributes a sizeable amount of fine PM
area source emissions. Wyoming's fine PM contributions originate mainly from natural fire
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 88 of 206
Figure 5.2.10-1. WEP Potential Contribution to Fine PM at Yellowstone NP, Grand Teton
Class I Arsae - orand Tston NP, V\rY: Rsd Rock Lakes IWYRW, Mf: Tsbn W, Viff:YEllovrrstono NP, WY
78
sources, followed by dust sources. Significant PM contributions from dust sources are also noted
in Utah and Oregon, and to a lesser degree in California, Canada, Washington and Nevada.
Figure 5.2.10-2. WEP Potential Contribution to Fine PM at North Absaroka Wilderness
and Washakie Wilderness Areas on 20oh Best Visibility Days
Best 20% Visibility Days
(WRAP TS S - http ://v i sta. cira. co lostate.edu/tss/)
Dust sources in Montana and ldaho are the overwhelming fine PM contributors for the 20% best
visibility days at North Absaroka. The next largest contributor is Wyoming, followed closely by
Utah, Oregon, Canada, Washington and California, respectively. The second largest source in
Wyoming is natural fire, and in Montana and Idaho it is area sources.
Figure 5.2.10-3. WEP Potential Contribution to Fine PM at Bridger Wilderness and
Potential Sources and Area-s-of eine ptvt gmissioni on
Itaaot**
LlFuqiliva Drrd
IRoad Dust
loftfoad t obf,r,
Ion-noao uoorc
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Ipoit
33.8
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EEEEEEEEHEHEHEHEHE HEEEg*HEHEEEHEHEEE
,r * J* 33dre e gpad f E ** d d*i;EiddddBi =*** i
12.m
s.m
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3.@
0.00
WM'E
2000'04 Bassline & 201 I PRPb
_*__ rilrl{flgt Ullqgllelq lfqqs, eqe0Z"_Best Visibility Qay_s_
Potential Sources and Areas of Fine PM Emissions on Best 20% Visibilitv Davs
(WRAP TS S - http ://vi sta. cira.co lostate.edu/tss/)
and Areas of Fine PM Emissions on Best 20% Visibility Days
200&04 Baselins & 201 I PRPb
Iua oust
flFuqfiiv? Dusl
lnoooust
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!,lalurd Fie
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38383€383t3888383838863888tt8t363€3t
EqEqEqqqEqqqEqFqE+Fq+qFq8q8qF+EqqqEq
**,*.,nT** s 3 B 3 E I ae H H " " E E = = 221== t 5 5 I I a I 5 = g f ! E
Class I Areas - Bddger W, WY: FitspatrickT ---r---I-t
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 89 of 206
79
For the 20%obest visibility days at Bridger, Idaho is the dominant contributor to fine PM,
followed by Wyoming and Utah. Dust sources are predominant, followed by natural fire, point,
and area sources. Montana, Oregon, California, Nevada and Washington, respectively, are the
next largest contributors. Dust sources, followed by area and point sources, make up the
majority of the contribution components from these states.
5.2.11 WEP Potential Contribution to Coarse PM on 207o Worst Days
Figures 5.2.1l-l through 5.2.11-3 in this section illustrate the contribution of coarse PM to the
Zlo/oworst days in Wyoming Class I areas for 2002 and 2018, based on WEP profiles for each
IMPROVE monitoring site representing the nearest Class I areas.
The figures below show that the profile for coarse PM is dominated by road dust, windblown
dust, and to a lesser extent, fugitive dust. These dust sources are generated mainly from
Montana and Idaho, with the exception of the Bridger site, where most of the coarse PM
emissions are generated in Wyoming. These dust sources are a combination of natural and
human activity, such as construction, mining, unpaved and paved roads, and agriculture. There
is some contribution from natural fire sources, mainly from Wyoming and Idaho, as well as
contributions from point sources in Wyoming, Utah and Montana.
When comparing 2002 and20l8, most figures show increases in fugitive dust and road dust
mainly due to population growth. Windblown dust remains constant in all figures.
Teton NP. and Teton Wilderness Area on 207" Worst Visibi
Potential Sources and Areas of Coarse PM Emissions on Worst 20% Visibility Days
fi,.m
30.m
27fi
2'lm
1m
f, ra.m
E rs.o
t2.m
9m
6ID
3.00
0m
200tI0il ga8Elins & 201 I PRPb
T
I
t
I
I
!l rl
Class I Areas - Grend Telon NP. yJY: Red Rock Lekss NT: Tgton W. WY:YEllorlEtone NP. WY
Iuaala
$fuglvaDud
Inoaoals
Llotnoomoma
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88t8388838r88838 r8883
EEEEHEHECECEEEEE HEEEEr,i g e g ge en S ; aU I * * di*;i
(WRAP TS S - http ://vi sta.cira.colostate.edu/tssA
For the 20oZ worst visibility days at Yellowstone, the most sizeable coarse PM contributions are
from dust sources originating in Montana and Idaho. Wyoming is the third largest contributor of
coarse PM, with slightly less than 50oZ coming from natural fire sources and the remainder
Exhibit No. 4
Case No.lPC-E-13-'16
T. Harvey, IPC
Page 90 of 206
Figure 5.2.11-1. WEP Potential Contribution to Coarse PM at Yellowstone NP, Grand
80
P-otentiat Sources
70.00
60.00
50.00
- 40.m
E
& .0.*
20.00
t0.m
0.00
Iuaoust
Bl Furlive Dusl
IRoad Dusi
i ;orfioad t ot la
Ion.RoaO Nooite
{3ott-straa
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38t838t8388
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e8
mainly from dust sources. To a much Iesser extent, Utah, Oregon, Washington and Canada also
contribute coarse PM to the Yellowstone monitoring site.
Figure 5.2.11-2. WEP Potential Contribution to Coarse PM at North Absaroka Wilderness
and Washakie Wilderness Areas on 20oh Worst Visibility Days
(WRAP TS S - htto ://v i sta. cira.co lostate.edu/tss/)
Dust sources from Montana, by far, are the largest contributor to coarse PM on the 207o worst
visibility days at North Absaroka. Idaho and Wyoming are the next largest contributors,
followed by Canada.
Figure 5.2.11-3. WEP Potential Contribution to Coarse PM at Bridger Wilderness and
rick Wilderness Areas on2Ooh Worst
and Areas of Coarse PM Emissions on Worst 20% !'isibility Days
200tr04 Baseline & 201 I PRPb
30.00
27.00
24.m
r.m
t 16.me
b ls.md
12.m
9.00
6tr
3.m
0.00
WRA' E
lretus
n Fuglive Dust
I Roau oust
I Oflfoad l,loUlc
Ionloao xofne
[:oir-shse
It^nAP Arca o8o
Haro
lgogmlc
Ndurd FFB
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Ipoa
t383t33883338-r-d-frHfrFfHfrHftHEHE, . .; .EEEp868==g*gI
talon9@989
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cn*o?D?otololo666666060@OOO@O@OO
HIHEHIE4HqEqHqHEHI
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WRAP TS S - http ://v i sta.c ira.co lostate.edu/tss/)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 91 of206
Class I Areas - Bridger W V\rY: FiEpatrick VY, V\rY
=.r_=-- ir-'-lllriil
8l
For the 20o/oworst visibility days at Bridger, Wyoming is the largest contributor of coarse PM,
followed closely by Idaho, Utah and Montana, respectively. Point and natural fire sources from
Wyoming comprise approximately one-third of the coarse PM contribution, while dust sources
make up roughly two-thirds of the contribution. Oregon, Canada, California, Washington and
Nevada contribute coarse PM to a much lesser extent at this site.
5.2.12 WEP Potential Contribution to Coarse PM on 20o/o Best Days
Figures 5.2.12-l through 5.2.12-3 in this section illustrate the contribution of coarse PM to the
2}%obest days in Wyoming Class I areas for 2002 and,2018, based on WEP profiles for each
IMPROVE monitoring site representing the nearest Class I areas.
The figures below show that the profile for coarse PM is dominated by road dust, windblown
dust, and to a lesser extent, fugitive dust. These dust sources are generated mainly from
Montana and ldaho, with the exception of the Bridger site, where most of the coarse PM
emissions are generated in Idaho, Wyoming and Utah, respectively. Montana generates
approximately one-third of the amount of dust compared to Idaho at the Bridger monitoring site.
These dust sources are a combination of natural and human activity, such as construction,
mining, unpaved and paved roads, and agriculture. There is some contribution from natural fire
sources, mainly from Wyoming and ldaho, as well as smaller contributions from point sources in
Utah, Wyoming, and Montana.
When comparing 2002 and 2018, most figures show increases in fugitive dust and road dust
mainly due to population growth. Windblown dust remains constant in all figures.
Figure 5.2.12-1. WEP Potential Contribution to Coarse PM at Yellowstone NP, Grand
Teton NP, and Teton Wilderness Area on 20%o Best
Potential Sources and Areas of Coarse PM Emissions on Best 20% Visibility Days
Class I ffsas - Orand Teton NP. tryY: REd Rock Lakss WY:Yallorstons NP.IYY
g,.m
30-00
27.fi'
24m
21.m
E,..,5d tsm
12fr
9.(D
6.m
3.m
0.m
Iuaurst
Erunvcag
lnoaa OuS
f]offnoamois
Ior*o*mmc
@ott-gnrc
lvnen.*aoao
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llaogorie
llurure rrr
I,crrrro rrr
Iport
to?DaacEaDeDn4calo ?atacato*a+Ela+E?E o6860606
HEEEEENTEEEEEEEEEE EEEEHE*EEEEEEEEEFE
",,*.,# *,i giAf e s q H d dI E * * d i***r d *d d a a * 1* * i i
(WRAP TS S - htto ://vista.cira.colostate.edu/tss/)
For the 20% best visibility days at Yellowstone, the most sizeable coarse PM contributions are
from dust sources originating in Idaho and Montana. Wyoming is the third largest contributor of
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 92 of 206
200$04 BasalhB & 201 I PRPb
coarse PM, with approximately 50Yo coming from natural fire sources and 50% from dust
sources. Utah is the fourth largest contributor, with the majority attributable to dust sources, and
a smaller amount coming from point sources. To a much lesser extent, Oregon, Canada, Nevada,
California and Washington also contribute coarse PM to the Yellowstone monitoring site.
Figure 5.2.12-2. WEP Potential Contribution to Coarse PM at North Absaroka Wilderness
and Washakie Wilderness Areas on2Ooh Best Visibil
and Areas of Coarse PM Emissions on Best 20% Visibility Days
200G04 Basslino & 201 I PRPb
Class I Areas - Nonh Absaroka W WY: Washalda W WY
T
T
-EIE
(WRAP TS S - http ://vi sta.cira.colostate.edu/tssA
Dust sources from Montana and Idaho are the largest contributors to coarse PM on the 20% best
visibility days at North Absaroka. Wyoming and Utah are the next largest contributors, followed
by Oregon, Canada and Washington.
40.m
36In
32.m
28m
E 21.m
E 20m
'r6-(D
12fi
8.(D
4.m
0.m
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r838r83838tttt38386tt8383888t8388838
HEEEEENIf;ENgHEHEEENNHEHEEEEEHEEEHEgE
nou*.,jj J,i f g E "6d d n g i a q E * * ii*** i * d dd d I = = i f * E
Exhibit No. 4
Case No.IPC-E-13-16
T. Harvey, IPC
Page 93 of 206
83
Potential Sources and Areas of Coarse PM Emissions on Best 20% Visibility Days
200tI04 BasElinE & 201 I PRPb
YilY: FitsBatrickW.WY
Iurooust
Elrugftvc trd
Inoao u.et
f_lotnoouou'r
IOn*oXNoOlc
Mott-strorc
lunae nrca oao
Eer-
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I*ttno rlra
lpon
$.m
gr.ff
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r.m
! ra.oo
& rs.m
12.@
g.m
6.ff)
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0m t6EtStEtBtEtstEeSt EtrSrSrtrtEtEttts6
BqFqHq(E8qEq$q$qEq $EHq+qHq+qHr$qiEFq
*r*.,# t 3 3 3 6 6 s I H H o o E [ =
E e zltz ] r 5 s I a B s 5 B'f E I
Figure 5.2.12-3. WEP Potential Contribution to Coarse PM at Bridger Wilderness and
Fitzpatrick Wilderness Areas on20oh Best Visibilitv Davs
(WRAP TS S - http ://vi sta.cira.co lostate.edu/tssA
For the 20o/obest visibility days at Bridger, Idaho is the largest contributor of coarse PM,
followed by Wyoming, Utah and Montana, respectively. Dust sources are the dominant
component of the coarse PM emissions at the Bridger site, followed by natural fire and point
sources.
5.3 CMAQ 2018 Projected Visibility Conditions
This section summarizes the regional haze improvements projected using the CMAQ model for
Wyoming's Class I areas. The CMAQ model was used to estimate 2018 visibility conditions in
Wyoming and all Western Class I areas, based on emission inputs described in Section 5.1.2 of
this chapter. The Division relied upon the results of the CMAQ modeling in establishing the
Reasonable Progress Goals described in Chapter 7.
These visibility projections were calculated from modeled results by multiplying a species-
specific relative response factor (RRF) with the baseline monitored result, and then converting to
extinction and deciview. The RRF is defined as the ratio of future-to-current modeled mass.
Chapter 7 details how the 2018 projected visibility conditions were used for setting Reasonable
Progress Goals. Analysis of the WRAP 2018 preliminary reasonable progress modeling runs are
contained in an August2009 ENVIRON Memorandum in Chapter 5 of the Wyoming TSD.
Table 5.3-1 shows the 2018 visibility projections for the 207o worst and best days, compared to
the 2018 Uniform Rate of Progress (URP) for Wyoming Class I areas (grouped by IMPROVE
monitoring site). These 2018 projections are shown in deciview, and in the percent of the URP
achieved by 2018 for the 20%o worst days (first shaded column). Also indicated is whether the
20%obest days for 2018 are projected to be under the 2000-2004 baseline (second shaded
column).
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 94 of 206
84
This table shows that Wyoming's Class I areas are slightly less than half way to meeting the
2018 URP for the 20olo worst days. Section 5.3.1 provides a breakdown by pollutant species to
analyze the cause of this. For the 20Yobest days, all Class I areas are under the baseline, and
thus show no visibility degradation by 2018.
Table 5.3-1. CMAQ Modeling Results for 20oh Worst Days and 20ohBest Days for
Class I Areas
5.3.1 CMAQ Modeling Breakdown by Pollutant for 207o Worst Days
As indicated by the 2018 visibility projections using CMAQ modeling, none of the Class I areas
meet the URP goal for 2018 for the 207o worst days. In order to determine the cause, it is
necessary to break down these results to identiff individual pollutants. The information provided
below shows the contribution of each pollutant in extinction (Mm-l) to the total extinction level
for each Class I area. As pointed out earlier in this chapter, it is important to note whether the
pollutants affecting the modeling are anthropogenic, such as sulfates or nitrates, or the other
pollutants that are mostly natural in origin (OC, EC, and PM). This assessment is important in
the determination of reasonable progress, described in Chapter 7.
Figures 5.3.1-l through 5.3.1-3 provide a breakdown of individual pollutant contribution (in
extinction) by showing the glide slope of each pollutant in each Class I are4 from the baseline to
2018, and beyond, for the 20% worst days. Below each figure is a table that shows the 201 8
projections for each pollutant, and whether the projection is under the 201 8 URP goal, and the
percent improvement toward the 2018 URP goal.
The results of this breakdown by pollutant shows that at all Class I areas, nitrate exceeds or
meets the 2018 URP goal. For sulfate, while none of the Class I areas meet the 2018 URP goal,
the improvement is as high as 82o/o at the Bridger Class I area. Conversely, these tables and
figures show that organic carbon is the highest contributor to extinction, and projections for 2018
show very little improvement. Much of the organic carbon can be attributed to fire, of which the
majority is wildfire, and thus non-anthropogenic in origin. For fine soil there is no progress
toward the 201 8 URP goal because the projected 201 8 values are higher than or equal to baseline
conditions. Chapter 7 provides further discussion related to Reasonable Progress Goal
demonstration.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 95 of 206
Yellowstone National Park
Grand Teton National Park
Teton Wilderness
North Absaroka Wilderness
Washakie Wilderness
(WRAP T S S - hff p ://vi sta. c ira. co lostate. edu/tssA
85
Class I Ar8as - Grand Tebn NP, WY: Rsr, Rock Lskss I'lWRlt , }lT: Tabn W IVY: Yellonsbns NP. UIY
Figure 5.3.1-1. Gtide Slope by Pollutant on20o/o Worst Days for Yellowstone NP, Grand
Teton NP, and Teton Wilderness Area
- EPA Specific Days
140
12fr
t0I)
805i
6rl
43
2.0
00
+iO3Edh.do.r
.f" SO4 Enh.ilo.r
*orcE{hdion
.l,EC Bfficdon
+OilEffi.r
*SolErffit
+ S.asilEdiE'lin
-
o
zII.{r4Bs*EAYU{a
Table 5.3.1-1. Pollutant Breakdown on 20oh Worst Days for Yellowstone NP, Grand Teton
NP. and Teton Wilderness Area
*No progress towards URP goal because projected 2018 values are higher than or equal to baseline
conditions.
(WRAP TS S - http ://v i sta. c ira. co lo state. ed u/tss/)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 96 of 206
(WRAP TS S - http ://vi sta.cira.colostate. edu/tss/)
2000-04
Baseline
(Mm-1)
2018
URP
Goal
(Mm-1)
2018
Projected
Visibility
(Mm-1)
2064
Natural
Conditions
(Mm-1)
2018
Under
URP
Goal?
%o of
URP
Goal
Sulfate 4.3 3.4 3.7 0.8 No 67o/o
Nitrate 1.8 1.5 1.4 0.6 Yes >l00%o
Organic
Carbon l3.s 11.0 12.9 4.6 No 24lJ
Elemental
Carbon 2.5 2.0 2.2 0.4 No 600
Fine Soil 1.0 1.0 1.0 1.0 Yes None*
Coarse
Material 2.6 2.7 2.6 3.0 Yes >1000
Sea Salt 0.0 0.0 0.0 0.0 Yes 1000
86
Figure 5.3.1-2. Glide Slope by Pollutant on 20oh Worst Days for North Absaroka and
Washakie Wilderness Areas
Vsibility Conditions on Worst 20%
Class lArBas - Norh lbsaml€ l{. WY:Washalde
Da}s-
v{Y125
1ro
10.0
9.0
8.0
7n
60
5!
4.0
30
20
1.0
0I}
1
+lOAExthcthn
i: SO{Eiron
*oltEElHin
.|.EC Edhdirl
*ffffibr
.|.SdEdhcrEr
.+ Sc6dEniE{Fn
I20fi[0(Br.*!A,ruiqp
_- _itst __.__ ammrE-lrta:
Table 5.3.1-2. Pollutant Breakdown on 20o/o Worst Days for North Absaroka and
Washakie Wilderness Area
*No progress towards URP goal because projected 2018 values are higher than or equal to baseline
conditions.
(WRAP T S S - http ://v i sta. cira. co I ostate. edu/tss/)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 97 of 206
(WRAP TS S - http : //v i sta. c ira. co I ostate. edu/tss/)
2000-04
Baseline
(Mm-1)
2018
URP
Goal
(Mm-1)
2018
Projected
Visibility
(Mm-l)
2064
Natural
Conditions
(Mm-1)
2018
Under
IJRP
Goal?
Yo of
URP
Goal
Sulfate 4.9 3.8 4.5 0.8 No 45o/"
Nitrate 1.6 1.4 1.3 0.8 Yes >1000/"
Organic
Carbon 11.6 9.8 11.0 4.6 No 33Yo
Elemental
Carbon 1.9 1.5 1.6 0.4 No 75o/o
Fine Soil 0.9 0.9 1.0 0.9 No None*
Coarse
Material 2.9 3.0 2.9 3.4 Yes >1000h
Sea Salt 0.0 0.0 0.0 0.0 Yes 1000
87
ProjecEd 2018 PRP18b Visibility Conditions 0n Worst 20% Visibility Days - EPA Specfic Drys
CI88B ArBa9 wY:FiEpaficl(w,wY
10.6 d03
\
\\o*
.4.1
;;ru Ll
r.0 1
0
., ffi 2010 M 2(E0 zr0 zEo at! 207t)
fio
10a
sIl
8I'
7fi
- 611Irro
{o
30
2i
1I)
0-0
+ts3Bffi.r
i'So{Efrildr
+0i,lcE{inEthn
*ECBrurdion
*O{Effin
*SdAffiin
*.S.&Edhdin
2fiD01Bdr.Avrr{r
(WRAP T S S - http : //vi sta. cira. co I ostate. edu/ts s/)
Figure 5.3.1-3. Glide Slope by Pollutant on20Yo Worst Days for Bridger and Fitzpatrick
Wilderness Areas
Table 5.3.1-3. Pollutant Breakdown on2Ooh Worst Days for Bridger and Fitzpatrick
Wilderness Areas
*No progress towards URP goal because projected 2018 values are higher than or equal to baseline
conditions.
(WRAP T S S - http : //v i sta. cira. co I ostate. ed u/tss/)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 98 of 206
2000-04
Baseline
(Mm-1)
2018
URP
Goal
(Mm-1)
2018
Projected
Visibility
(Mm-1)
2064
Natural
Conditions
(Mm-1)
2018
Under
URP
Goal?
oh of
URP
Goal
Sulfate 5.0 3.9 4.1 0.8 No 82Yo
Nitrate 1.4 1.3 1.2 0.8 Yes >1000/"
Organic
Carbon 10.6 9.0 10.3 4.6 No 19o/o
Elemental
Carbon 2.0 1.6 r.8 0.4 No 500h
Fine Soil l.l 1.t 1.2 1.1 No None*
Coarse
Material 2.5 2.6 2.5 2.7 Yes >100(,
Sea Salt 0.0 0.0 0.0 0.0 Yes l00Yo
88
CHAPTER 6
BEST AVAILABLE RETROFIT TECHNOLOGY (BART)
6.1 Introduction
One of the principal elements of Section l694. of the 1977 Clean Air Act Amendments addresses
the installation of Best Available Retrofit Technology (BART) for certain existing sources of
pollution. The provision, l69A(b)(2), demonstrates Congress' intent to focus attention directly
on pollution from a specific group of existing sources. The U.S. EPA's Regional Haze Rule
requires certain emission sources that may reasonably be anticipated to cause or contribute to
visibility impairment in downwind Class I areas to install BART (see 40 CFR 51.308(e); see also
64 Fed. Reg. 35714 et seq. (July l, 1999)). These requirements are intended to reduce emissions
from certain large sources that, due to age, were exempted from other requirements of the Clean
Air Act.
BART requirements pertain to 26 specified major point source categories including power
plants, cement kilns and industrial boilers. To be considered BART-eligible, sources from these
categories must have the potential to emit 250 tons or more of haze forming pollution and must
have commenced operation in the l5-year period prior to August 7, 1977.
In addition to source-by-source command and control BART implementation, EPA has allowed
for more flexible alternatives if they achieve greater progress toward the State's visibility goals
than the standard BART approach.
On July 1., 1999, the EPA published regulations to address regional haze visibility impairment.
The regulations required states to address BART requirements for regionalhaze visibility
impairment, and allowed nine westem states to develop plans that were based on the GCVTC
recommendations for stationary SOz sources in lieu of BART.
In 2000 the Westem RegionalAir Partnership (WRAP) submitted an Annex to the GCVTC
recommendations that provided more details regarding the regional SOz milestones and backstop
trading program that had been recommended in the GCVTC Report, and included a
demonstration that the milestones achieved greater reasonable progress than would have been
achieved by the application of BART in the region. The Annex was approved by EPA in 2003,
but this approval was later vacated by the DC Circuit Court of Appeals in 2005 due to problems
with the methodology that was re_quired in the regional haze rule for demonstrating greater
reasonable progress than BART. r
On July 6,2005 EPA revised the RegionalHaze Rule in response to the judicial challenges to the
BART requirements. On October 13,2006 EPA published additional revisions to address
alternatives to source-specific BART determinations.
3 Centerfor Energt and Economic Development v. EPA, February 18,2005; American Corn Growers Association v.
EPA,May 24,2002.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 99 of 206
Five westem states (Arizona, New Mexico, Oregon, Utah, and Wyoming) had submitted State
Implementation Plans (SIPs) in 2003 under 40 CFR 51.309. Four of those states (Arizona, New
Mexico, Utah, and Wyoming) have updated their SIPs to include new SOz milestones that are
based on more recent emission inventories as well as the revised BART requirements in the
Regional Haze Rule. The fifth state, Oregon, is no longer participating in the program. Details
on the altemative to the BART program are contained in the 309 SIP submittal to EPA under a
separate action.
6.2 SO2: Regional SOz Milestone and Backstop Trading Program
Wyoming is a $309 state participating in the Regional SOz Milestone and Backstop Trading
Program. $308(e)(2) provides states with the option to implement or require participation in an
emissions trading program or other altemative measure rather than to require sources subject to
BART to install, operate, and maintain additional control technology to meet an established
emission limit on a continuous basis. However, the altemate program must achieve greater
reasonable progress than would be accomplished by installing BART. A demonstration that the
alternate program can achieve greater reasonable progress is prescribed by $308(e)(2)(i). Since
the pollutant of concem is SOz, this demonstration has been performed under $309 as part of the
State Implementation Plan. $309(dX4Xi) requires that the SOz milestones established under the
Plan "...must be shown to provide for greater reasonable progress than would be achieved by
application of BART pursuant to $51 .308(e)(2)."
Wyoming participated in creating a detailed report entitled Demonstration That the SOz
Milestones Provide Greater Reasonable Progress Than BART covering SOz emissions from
all states participating in the Regional SOz Milestone and Backstop Trading Program. The
document was submitted to EPA in support of the $309 Wyoming RegionalHaze SIP in
November of2008.
As part of the $309 program, participating states, including Wyoming, must submit an annual
Regional Sulfur Dioxide Emissions and Milestone Report that compares actual emissions to pre-
established milestones. Participating states have been filing these reports since 2003. Each year,
states have been able to demonstrate that actual SOz emissions are well below the milestones.
The actual emissions and their respective milestones are shown below:
Table 6.2-l. Resional Sulfur Dioxide Emissions and Milestone
Year
Reported SO2
Emissions
(tons)
3-year Milestone
Average
(tons)
2003 330.679 447,383
2004 337,970 448.259
2005 304,591 446.903
2006 279,134 420,194
2007 273,663 420,637
Summary
In addition to demonstrating successful SOz emission reductions, $309 states have also relied on
visibility modeling conducted by the WRAP to demonstrate improvement at Class I areas. The
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 100 of206
90
able 6.2-2.- Sulfate Extinction
Class I Area Monitor
(Class I Areas Represented)
20%o Worst Visibility Days
Monthlv Averase. Mm'r)
207o Best Visibility Days
(Monthlv Averase. Mm-r)
2018 I
Base Case
(Base 18b)
2018 "
Preliminary
Reasonable
Progress Case
(PRP18a)
2019 I
Base Case
(Base 18b)
2018"
Preliminary
Reasonable
Progress Case
(PRP18a)
Bridger, WY
(Brideer WA and FitzDatrick WA)5.2 4.3 1.6 1.3
North Absaroka, WY
fNorth Absaroka WA and Washakie WA)4.8 4.5 l.l 1.1
Yellowstone, WY
(Yellowstone NP, Crrand Teton NP and Teton WA)4.3 3.9 1.6 1.4
Badlands. SD 17.8 16.0 3.5 3.1
Wind Cave. SD 13.0 t2.t 2.7 2.5
Mount Zirkel, CO
(Mt. Zirkel WA and Rawah WA)4.6 4.1 1.4 1.3
Rocky Mountain, CO 6.8 6.2 3
Gates ofthe Mountains. MT 5.3 5.1 0 0
UL Bend, MT 9.7 9.6 8 7
Craters of the Moon. ID 5.8 5.5 5 .5
Sawtooth.ID 3.0 2.8 2
Canyonlands, UT
(Canyonlands NP and Arches NP)5.4 4.8 2.1 1.9
Capitol Reef. UT 5.7 5.4 1.9 1.8
2018 Base Case srowth plus all established controls as of Dec. 2004. No BART or SO, Milestone assumotions were included.
complete modeling demonstration showing deciview values was included as part of the visibility
improvement section of the $309 SIP, but the SO2 portion of the demonstration has been
included as Table 6.2-2 to underscore the improvements associated with SOz reductions.
' Represents 2018 Base Case growth plus all established controls as of Dec. 2004. No BART or SO2 Milestone assumptions were include,
? Represents 201 8 Preliminary Reasonable Progress growth estimates and established SO2 limits (including milestone levels established at
the time of the model run).
All Class I areas in the surrounding states show a projected visibility improvement for 2018 with
respect to SOz on the worst days and no degradation on the best days. More discussion on the
visibility improvement of the $309 program can be found in the Wyoming $309 Regional Haze
SIP revision submitted to EPA in November 2008.
Therefore, in accordance with $308(e)(2), Wyoming's $309 RegionalHaze SIP, and WAQSR
Chapter 6, Section 9, sources will not be required to install BART controls to meet an SOz
emission limit. Instead, sources will be required to participate in the Regional SOz Milestone
and Backstop Trading Program authorized under Chapter 14 of the WAQSR.
The remainder of this section, therefore, focuses on how Wyoming has satisfied the BART
requirements with respect to NO* and PM in EPA's Regional Haze Rule. Wyoming's review
process is described and a list of BART-eligible sources is provided. A list of sources that are
subject to BART is also provided, along with the requisite modeling analysis approach and
justification. Wyoming made its BART determinations using the methodology in EPA's
Guidelines for BART Determinations Under the RegionalHaze Rule, 40 Fed. Reg. 39104 et seq.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 101 of206
9l
(July 6, 2005) (hereinafter "Appendix Y"), and the Wyoming Air Quality Standards and
Regulations (WAQSR) Chapter 6, Permitting Requirements, Section 9, Best available retrofit
technology (BART). EPA's Guidelines for BART Determinations and Chapter 6, Section 9 of
the WAQSR can be found in Chapter 6 of the Wyoming TSD.
6.3 Overview of Wyoming's BART Regulation
Wyoming's Environmental Quality Council approved a State-only BART regulation (Chapter 6,
Permitting Requirements, Section 9, Best available retrofit technology (BART)) on October 10,
2006, that became effective in December 2006. The provisions of the regulation required
BART-subject sources to submit an application, according to a schedule determined by the Air
Quality Division, for a BART determination.
Wyoming's BART Rule is based largely upon EPA's BART Rule and related Appendix Y,
which includes procedures to be followed when making BART determinations for individual
sources. States are only required to follow Appendix Y procedures for sources which are electric
generating units (EGUs) with greater than 750 MW generating capacity. EPA's BART Rule has
no specific requirements for conducting BART determinations for sources that are not electric
generating plants with greater than 750 MW capacities. EPA encourages states to use its
guidelines for all source categories, but states are not required to do so.
6.4 SIP BART Requirements From EPA's Regional Haze Rule
The following sections address the SIP elements relative to BART contained in EPA's Regional
Haze Rule. Section numbers refer to provisions in section 308(e), the BART provision of the
Regional Haze Rule.
308(e)(l)(i) - A list of all BART-eligible sources within the State.
The U.S. EPA regulations for best available retrofit technology (BART) are contained in 40 CFR
part 51, Appendix Y, published July 6, 2005 in the Federal Register, and provide the guidelines
for BART determinations. Section II of Appendix Y discusses a three-step procedure for
identifying BART-eligible sources. A source was BART-eligible if it l) belonged to one of the
26 listed categories,2) was'oin existence" on August7,1977, but not'oin operation" before
August 7, 1962, and 3) had the potential to emit greater than 250 tons per year of any single
visibility impairing pollutant. If a facility met all three criteria mentioned, then a screening
analysis was used to determine if it was "subject to BART", per Section III of Appendix Y.
Using Appendix Y as a guideline, the State of Wyoming determined that there were fourteen
(14) facilities with BART-eligible emission units. These facilities are listed below:
PacifiCorp - Jim Bridger
PacifiCorp - Naughton
FMC - Granger
FMC - Green River
Basin Electric - Laramie River
General Chemical
P4 Production
OCI Wyoming
Dyno Nobel
Sinclair - Casper Refinery
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 102 of206
92
PacifiCorp - Wyodak
PacifiCorp - Dave Johnston
Black Hills - Neil Simpson I
Sinclair - Sinclair Refinery
Not Subject to BART
P4 Production
OCI Wyoming
Dyno Nobel
Sinclair - Casper Refinery
Black Hills - Nei[ Simpson I
Sinclair - Sinclair Refinery
The Division completed a BART screening analysis on the fourteen facilities to determine which
facilities had a significant impact on visibility in Class I areas in Wyoming, South Dakota, and
Colorado.
As specified in the Division's BART Air Modeling Protocol dated March 2006 (see Chapter 6 of
the Wyoming TSD), a source was deemed to produce a significant impact to visibility on a Class
I area if the source had a modeled impact to visibility value greater than 0.5 deciview (dv) to
determine a daily maximum change in visibility (Adv) value for each Class I area and year of
meteorological data. The visibility impact threshold to determine BART sources is a 98u
percentile .hung" in visibility (Adv) of 0.5 dv above background conditions. Therefore, if the 8s
highest Adv value was equal to or greater than 0.5 dv, the source was considered to cause or
contribute to visibility impairment in the subject Class I area, and therefore was "subject to
BART". However, if the 8th highest value for all three years at each Class I area in a given
domain was less than 0.5 dv, the source was not subject to BART. Using these criteria, the
fourteen facilities were screened for BART subjectivity. The BART Facilities Emissions
Inventory in Chapter 6 of the Wyoming TSD details the emission units at the BART-eligible
sources. Screening results, which provide the maximum change in visibility, number of days
>0.5 dv, and 8th high values, are summarized in the WY BART Screening Analysis Results and
the WY BART Screening Analysis Results DV Frequency, which can also be found in Chapter 6
of the Wyoming TSD. After evaluating the results of the screening analysis, the following
facilities were found to be subject to BART or not subject to BART.
Subject to BART
PacifiCorp - Jim Bridger
PacifiCorp - Naughton
FMC - Granger
FMC - Green River
Basin Electric - Laramie River
PacifiCorp - Wyodak
PacifiCorp - Dave Johnston
General Chemical
308(e)(l)(ii) - A determination of BARTfor each BART-eligible source in the State that emits
any air pollutant which may reasonably be anticipated to cause or contribute to any impairment
ofvisibility in any mandatory Class I Federal area. All such sources are subject to BART.
The following table summarizes the Division's BART determinations for sources that cause or
contribute to visibility impairment in Class I areas. These BART determinations are part of this
Regional Haze SIP that will be submitted to EPA.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 103 of206
93
Unit NO, Control
Tvne
NO, Emission
Limit
Particulate Control
Tvne
PMls Emission
Limit (l)
Basin Electric - Laramie (''
River Unit I (550 MW)
LNB + OFA 0.21 IbA,IMBtu
(3O-dav rollins)
ESP 0.030lb/lvlMBtu
Basin Electric - Laramie ('r
River Unit 2 (550 MW)
LNB + OFA 0.21 lb/\4MBru
(3O-dav rollins)
ESP 0.030 lb/I\,IMBtu
Basin Electric - Laramie ("
River Unit 3 (550 MW)
LNB + OFA 0.21 lbA4MBtu
(3O-dav rollins)
ESP 0.030Ib/lvlMBtu
FMC Wyoming - Granger 14
(358.5 MMBtu)
nla nla nJa n/a
FMC Wyoming - Granger 15
(358.5 MMBtu)
nla nla n/a nla
FMC Wyoming - Westvaco
NS-IA
(887 MMBtU)
LNB + OFA 0.35 lb/lvlMBtu
(30-day rolling)
ESP 0.05lb/\,lMBtu
FMC Wyoming- WesWaco
NS.IB
(887 MMBtu)
LNB + OFA 0.35lb/IvlMBtu
(30-day rolling)
ESP 0.05lb/TvlMBru
FMC Wyoming- Westvaco
PH-3
(333.6 MMBtU)
nla n/a nla n/a
General Chemical - Green
River GR-2-L
(534Ib/\4MBtu)
LNB + SOFA
or equivalent
technoloev
0.28Ib/TvIMBru
(30-day rolling)
ESP 0.09 lb/N,IMBtu
General Chemical - Green
River GR-3-W
(880lb/MMBtu)
LNB + SOFA
or equivalent
technolosv
0.28lb/\4MBtu
(3O-day rolling)
ESP 0.09lb[vlMBtu
PacifiCorp - Dave Johnston
Unit 3 (230 MW)
LNB + OFA 0.28Ib/lvlMBtu
(30-dav rolline)
Fabric Filter 0.0l5lb/IvIMBtu
PacifiCorp - Dave Johnston
Unit 4 (330 MW)
LNB + OFA 0.l5lb/TvIMBtu
(30-dav rolline')
Fabric Filter 0.0l5lb/TvIMBtu
PacifiCorp - Jim Bridger
Unit I (530 MW)
LNB + OFA 0.26Ibl\4MBru
(30-dav rolline)
ESP + FGC 0.030Ib/MMBtu
PacifiCorp - Jim Bridger
unit 2 (530 MW)
LNB + OFA 0.26IblTvIMBru
(30-dav rolline)
ESP + FGC 0.030 lb/lr4MBtu
PacifiCorp - Jim Bridger
unit 3 (530 MW)
LNB + OFA 0.26IblMMBtu
(3O-dav rollins)
ESP + FGC 0.030Ib/MMBtu
PacifiCorp - Jim Bridger
unit 4 (530 MW)
LNB + OFA 0.26IblIvIMBtu
(3O-dav rollins)
ESP + FGC 0.030Ib/TvIMBtu
PacifiCorp - Naughton Unit I
(160 Mw)
LNB + OFA 0.26IblMMBtu
(30-dav rolline)
ESP + FGC 0.040lb/lvlMBtu
PacifiCorp - Naughton Unit 2
(210 Mw)
LNB + OFA 0.26lbA,fMBtu
(30-dav rolline)
ESP + FGC 0.040 lb/N4MBtu
PacifiCorp - Naughton Unit 3
(330 MW)
LNB + OFA +
SCR
0.07lb/lvlMBtu
(30-dav rolline)
Fabric Filter 0.0l5lb/\,IMBtu
PacifiCorp - Wyodak Unit 1
(335 MW)
LNB + OFA 0.23|bllvlMBtu
(30-dav rolline)
Fabric Filter 0.0l5lb/TvIMBtu
Filterable portion onlyt (') These emission limits reflect condition 7c in the Seftlement Asreement between DEO/AOD and
Table 6.4-1. BART Determinations for Wyoming Sources
portlon only;Agreement DEQ/AQD
Basin Electric, EQC Docket No. l0-2802.
ESP = electrostatic prtcipitator; FGC : flue gas conditioning; LNB = low NO* bumers; n/a : not subject to BART;
OFA = overfire air; SCR: selective catalyic reduction; SOFA: separated overfire air
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 104 of206
94
I. The Five-Factor Analysis
308(e)(1)(ii)(Q - fhe determination of BART rnust be based on an analysis of the best system of
continuous emission control technologt available and associated emission reductions achievable
for each BART-eligible source that is subject to BART within the State. In this analysis, the State
must take into consideration the technologt available, the costs of compliance, the energt and
non-air quality environmental impacts of compliance, any pollution control equipment in use at
the source, the remaining useful lfe of the source, and the degree of irnprovement in visibility
which may reasonably be anticipated to resultfrom the use of such technologt.
Details of how each of these factors is taken into consideration during the BART determination
process are found below in the Facility Analysis section.
II. Compliance With Appendix Y
308(e)(1)(ii)(B) - The determination of BARTforfossil-fuelfired power plants having a total
generating capacity greater than 750 megawatts must be made pursuant to the guidelines in
appendix Y of this part (Guidelines for BART Determinations Under the Regional Haze Rule).
EPA's guidelines are only mandatory with respect to plants greater than 750 megawatts (see 70
Fed. Reg. at 39108, 3913 I ). EPA does not require that the guidelines be followed for other
source types (see id.). ln fact, EPA concluded that it "would not be appropriate for EPA to
require states to use the guidelines in making BART determinations for other categories of
sources" (id. at 39 1 08). States thus "retain the discretion to adopt approaches that differ from the
guidelines" (id. at 39158). The following fossil-fuel fired power plants have a total generating
capacity greater than 750 megawatts:
Basin Electric Power Cooperative - Laramie River (1,650 MW)
PacifiCorp - Dave Johnston (772MW)
PacifiCorp - Jim Bridger (2,120 MW)
EPA's guidelines in Appendix Y were followed for the three facilities listed above. Details of
how the guidelines were followed are found in the Facility Analysis section below.
III. Exoeditious Installation and Operation of BART
308(e)(1)(iv) - A requirement that each source subject to BART be required to install and
operate BART as expeditiously as practicable, but in no event later than 5 years after approval
of the implementation plan revision.
This requirement is addressed in Wyoming's BART Rule and compliance with this requirement
is discussed in the specific Facility Analysis for each source below.
IV. Proper Maintenance and Operation of Control Equipment
308(e)(1)(v) - A requirement that each source subject to BART maintain the control equipment
required by this subpart and establish procedures to ensure such equipment is properly operated
and maintained.
95 Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 105 of206
This requirement is addressed in Wyoming's BART Rule and compliance with this requirement
is discussed in Section V.
V. Monitoring and Recordkeeping Requirements
Startup Notification: The owner or operator shall fumish the Administrator written notification
of: (i) the anticipated date of initial startup not more than 60 days or less than 30 days prior to
such date, and; (ii) the actual date of initial startup within l5 days after such date in accordance
with Chapter 6, Section 2(i) of the WAQSR.
Chapter 6, Section 3 Operating Permit: The owner or operator shall modiff their Operating
Permit in accordance with Chapter 6, Section 9(e)(vi) and Chapter 6, Section 3 of the WAQSR.
Initial Performance Tests: The owner or operator shall conduct initial performance tests in
accordance with Chapter 6, Section 2O ofthe WAQSR, within 30 days of achieving a maximum
design rate but not later than 90 days following initial startup, and a written report of the results
shall be submitted. If a maximum design rate is not achieved within 90 days of startup, the Air
Quality Division Administrator may require testing be done at the rate achieved and again when
a maximum rate is achieved.
Periodic Particulate Performance Testing: Particulate testing shall be conducted annually, or
more frequently as specified by the Air Quality Division Administrator following the test
methods specified in this section.
Test Methods:
NO* Emissions - Compliance with the NO* 30-day rolling average shall be
determined using a continuous emissions monitoring system (CEMS) certified in
accordance with 40 CFR part 60 (Non-EGUs) or 40 CFR part75 (EGUs).
PM/PMr9 Emissions - Testing shall follow 40 CFR 60.46 and EPA Reference
Test Methods l-4 and 5.
Prior to any testing, a test protocol shall be submitted to the Division for approval,
at least 30 days prior to testing. Notification should be provided to the Division at
least 15 days prior to any testing. Results of the tests shall be submitted to the
Division oflice within 45 days of completing the tests.
NO* CEM Requirements: At alltimes after the compliance deadline specified in Section 6.5, the
owner/operator of each BART unit shall maintain, calibrate, and operate a CEMS in full
compliance with the requirements found at 40 CFR part 60 (Non-EGUs) or 40 CFR part 75
(EGUs), to accurately measure NO*, diluent (CO2 or O2), and stack gas volumetric flow rate
from each BART unit. The CEMS shall be used to determine compliance with the NO, BART
emission limits for each BART unit.
BART Limits: The NO* limits in terms of [b/IMMBtu, lb/trr and tpy apply at all times, including
periods of startup and shutdown. The PM/PMro limits in terms of lb/hr and tpy apply at all
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 106 of206
96
times, including periods of startup and shutdown. The PM/PMro limits in terms of lb/I4MBtu
apply at all times except during startup. Emissions in excess of the BART limits due to
unavoidable equipment malfunction are not considered a violation if the event is covered under
Chapter l, Section 5 of the WAQSR. The burden of proof is on the owner or operator of the
source to provide sufTicient information to demonstrate that an unavoidable equipment
malfunction has occurred.
BART NO* Limits: lb/TvIMBtu and lb/hr shall be 30-day rolling averages and the tpy shall be a
calendar year total.
Exceedances of the NO* limits shall be defined as follows:
Any 30-day rolling average which exceeds the lbllt'IMBtu NO* limits as
calculated using the following formula:
Eoug =
I(c),h=l
Where:
Eo,g : Weighted 30-day rolling average emission rate (lb/TvIMBtu).
C: l-hour average emission rate (lb/I\4MBtu) for hour "ft" calculated using
valid data from the CEM equipment certified and operated in accordance
with part 75 and the procedures in 40 CFR part 60, Appendix A, Method
19. V alid data shall meet the requirements of WAQSR, Chapter 5,
Section 2(j). Valid data shall not include data substituted using the
missing data procedure in Subpart D ofpart 75, nor shall the data have
been bias adjusted according to the procedures ofpart 75.
The number of unit operating hours in the last 30 successive boiler
operating days with valid emissions data meeting the requirements of
WAQSR, Chapter 5, Section 2O. A "boiler operating day" shall be
defined as any 24-hour period between 12:00 midnight and the following
midnight during which any fuel is combusted at any time at the steam
generating unit.
Any 30-day rolling average which exceeds the lb/hr NO. limits as calculated
using the following formula:
En, =
ir.l,
h=t
Where:
DLavg Weighted 30-day rolling average emission rate (lb/hr).
ll.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 107 of206
97
C: l-hour average emission rate (lb/hr) for hour "i" calculated using valid
data (output concentration and average hourly volumetric flowrate) from
the CEM equipment certified and operated in accordance with prt 75.
Valid data shall meet the requirements of WAQSR" Chapter 5, Section
2O. Valid data shall not include data substituted using the missing data
procedure in Subpart D of part 75, nor shall the data have been bias
adjusted according to the procedures ofpart 75.
The number of unit operating hours in the last 30 successive boiler
operating days with valid emissions data meeting the requirements of
WAQSR, Chapter 5, Section 2O. A "boiler operating day" shall be
defined as any 24-hour period between 12:00 midnight and the following
midnight during which any fuel is combusted at any time at the steam
generating unit.
Any l2-month rolling emission rate which exceeds the tpy NO* limit as
calculated using the following formula:
I(c),n h=lt = z,ooo
Where:
C- l-hour average emission rate (lb4rr) for hour "h" calculated using
data from the CEM equipment required by 40 CFR part 75. For
monitoring data not meeting the requirements of WAQSR, Chapter
5, Section 2O, Basin Electric shall provide substituted data for an
emissions unit according to the missing data procedures of 40 CFR
part75 during any period of time that there is not monitoring data.
E - l2-month rolling emission rate (tpy).
iv. Any calendar year total calculated using valid data (output concentration
and average hourly volumetric flow rate) from the CEM equipment and
operating data from the boiler which exceeds the tpy NO* limit. Valid
data shall meet the requirements of WAQSR Chapter 5, Section 2O. For
EGUs, the owner or operator shall use EPA's Clean Air Markets reporting
program to convert the monitoring system data to annual emissions. The
owner or operator shall provide substituted data according to the missing
data procedures of 40 CFR part 75 during any period of time that there is
no monitoring data.
BART PM/PMro Limits: lbA{MBtu and lb/hr limits shall be a l-hour average based on the
average of three performance tests. Compliance with lblTvlMBtu and lb/hr shall be determined
from the initial and annual performance tests. Annual emissions (tpy) shall be a calendar year
total calculated using the lb/lv1MBtu performance test result and boiler operating data.
llr.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 108 of206
98
Recordkeeping and Reporting: The owner or operator shall comply with all reporting and
recordkeeping requirements as specified in WAQSR Chapter 5, Section 2(g) and 40 CFR part60,
Subpart D. All excess emissions shall be reported using the procedures and reporting format
specified in WAQSR Chapter 5, Section 2(g). Records shall be maintained for a period of at
least five (5) years and shall be made available to the Division upon request.
6.5 Facility Analysis
Note that the following discussions of BART determinations are based upon proposed BART
permit conditions that are undergoing public review and comment. Following issuance of final
BART permits as required by Chapter 6, Section 9 of the WAQSR, the State of Wyoming will
supplement the SIP with revised descriptions of the BART determinations, if necessary.
6.5.1 FMC Wyoming Corp. - Granger Facility
The State of Wyoming performed a refined CALPUFF visibility modeling analysis for the two
BART-eligible units at the FMC Wyoming Granger Facility, and demonstrated that the predicted
98th percentile impacts at Bridger WA and Fitzpatrick WA would be below 0.5 dv for all
meteorological periods modeled. This modeling used higher-resolution meteorological data as
compared to the data used by the Division for the initial screening modeling that identified the
facility as "subject" to BART. A single source is exempt from BART if the modeled 98ff
percentile change is less than 0.5 dv at all Class I areas for each year modeled, in accordance
with Chapter 6, Section g(d)(ixc) of the WAQSR. Therefore, the State of Wyoming has
determined that the two BART-eligible units at the FMC Wyoming Granger Facility are not
subject to BART.
6.5.2 FMC Wyoming Corp. - Green River - Westvaco Facility
I. The Five-Factor Analvsis
After considering (l) the costs of compliance, (2) the energy and non-air quality environmental
impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the
remaining useful life of the source, and (5) the degree of improvement in visibility (all five
statutory factors) from each proposed control technology, the Division determined BART for
NO* and PMro emitted from two units at the Weswaco Facility. The State of Wyoming
concluded that a third unit at the facility, a gas-fired boiler, was not a significant contributor to
regional haze and a BART determination was not made for that source.
For control ofNO*emissions, the State of Wyoming requires that FMC install and operate low
NO*bumers (LNB) with enhanced overfire air (OFA) as BART for boilers NS-IA and NS-IB.
The use of LNB and enhanced OFA will result in a 1,360-ton reduction in annualNO* emissions
from each boiler. LNB/OFA on boilers NS-lA and NS-lB is cost effective, with an average cost
effectiveness of S304 per ton of NO* removed for each unit over a twenty-year operational life.
Combustion control using LNB/OFA does not require non-air quality environmental mitigation
for the use of chemical reagents (i.e., ammonia or urea) and there is a minimal energy impact.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 109 of206
For control of PM/PMr6 emissions, the State of Wyoming requires that FMC utilize the existing
ESPs as BART for boilers NS-lA and NS-lB.
Visibility impacts were addressed in a comprehensive visibility modeling analysis covering three
visibility impairing pollutants and associated control options. The cumulative 3-year averaged
visibility improvement from the baseline across Bridger WA and Fitzpatrick WA achieved with
LNB/OFA (based on the 98th percentile modeled results) was 0.2 Adv from each of the two
boilers.
The State of Wyoming considers the BART-determined permit limit to be equivalent to the
control effectiveness of a control technology. The limit is based on continuous compliance when
the control equipment is well maintained and operated in a manner consistent with good air
pollution control practices for minimizing emissions.
Unit-by-unit BART determinations for NO*and PM/PMro:
Filterable portion onlyESP : electrostatic precipitatorLNB : low NO* bumers
OFA : overfire air
III. Expeditious lnstallation and Operation of BART
The State of Wyoming requires that FMC install and operate new LNB with enhanced overfire
air on boilers NS- l A and NS- I B to achieve the BART emissions limits for NO*. Installation of
LNB and enhanced overfire air has been completed. LNB with OFA will continue to operate on
boilers NS-lA and NS-lB. The State of Wyoming requires that FMC continue the use of the
existing ESPs on boilers NS-lA and NS-l B to achieve the BART emissions limits for PM/PMro.
Initial performance tests for NO* and PM/PM1s have been completed for both boilers. NO* and
PM/PMro compliance deadlines for both boilers was on or before October 17,2009.
IV. Proper Maintenance and Operation of Control Equioment
The State of Wyoming requires that FMC follow the monitoring and recordkeeping requirements
of Section 6.4 V . to ensure proper maintenance and operation of control equipment.
6.5.3 General Chemical - Green River Works
L The Five-Factor Analysis
After considering (l) the costs of compliance, (2) the energy and non-air quality environmental
impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 110 of206
Units Pollutant Control Type 1b/lvlMBtu lb/hr tpv
NS-1A NO*LNB/OFA 0.35 (30-day rolling)284.0 (fo-aay rolling)244.0
PM/PMl6(u)ESP 0.05 45.0 97.0
NS-IB NO*LNB/OFA 0.35 (30-day rolling)284.0 lfOaay rolling)244.0
PM/PM16(")ESP 0.05 4s.0 97.0
100
remaining useful life of the source, and (5) the degree of improvement in visibility (all five
statutory factors) from each proposed controltechnology, the Division determined BART for
NO* and PMro emitted from the two boilers at Green River Works.
For control ofNO*emissions, the State of Wyoming requires that General Chemical install and
operate LNB and SOFA or an equivalent performing control technology as BART for boilers C
and D. The use of LNB and SOFA will result in a 512-ton reduction from baseline for Boiler C
and a737-ton reduction from baseline for Boiler D. LNB and SOFA on boilers C and D is cost
effective, with an average cost effectiveness of $1,280-1,480 per ton of NO,, removed for each
unit over a twenty-year operational life. Combustion control using LNB and OFA does not
require non-air quality environmental mitigation for the use of chemical reagents (i.e., ammonia
or urea) and there is a minimal energy impact. Affording General Chemical the option to install
an equivalent performing control technology does not change the basis of the BART
determination as the BART determination is made based on currently available controls (e.g.,
existing LNB with new SOFA, SNCR, SCR), which were alldeemed reasonable. Allowing the
company to install an equivalent performing technology provides additional flexibility to control
emissions to the specified BART levels, presumably in the most cost-effective manner.
For control of PM/PMrs emissions, the State of Wyoming requires that General Chemical utilize
the existing ESPs as BART for boilers C and D.
Visibility impacts were addressed in a comprehensive visibility modeling analysis covering three
visibility impairing pollutants and associated control options. The cumulative 3-year averaged
visibility improvement from the baseline across Bridger WA and Fitzpatrick WA achieved with
LNB and OFA (based on the 98th percentile modeled results) was 0.41 Adv from the two boilers.
The State of Wyoming considers the BART-determined permit limit to be equivalent to the
control effectiveness of a controltechnology. The limit is based on continuous compliance when
the control equipment is well maintained and operated in a manner consistent with good air
pollution control practices for minimizing emissions.
Unit-by-unit BART determinations for NO* and PM/PMro:
portion onlyESP : electrostatic precipitator
LNB = low NO, bumersSOFA = separated overfire air
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page111ot206
Units Pollutant Control Type lb/Ir4MBtu lb/hr tpy
C NO*
LNB/SOFA or
equivalent
technolow
0.28 1:O-aay rolling)149.5 (f O-day rolling)654.9
PM/PM1g (")ESP 0.09 50 219.0
D NO*
LNB/SOFA or
equivalent
technolow
0.28 (fo-aay rolling)246.4 poaay rolling)1,079.2
PM/PMro (")ESP 0.09 80 350.4
ton
l0l
III. Expeditious Installation and Operation of BART
The State of Wyoming requires that General Chemical install and operate low NO* bumers with
SOFA or equivalent performing technology on boilers C and D, in accordance with the
Division's BART determination, and conduct the required initial perforrnance tests to
demonstrate compliance as expeditiously as practicable, but no later than five years after EPA
approval of the state implementation plan revision. The State of Wyoming requires that General
Chemical continue the use of the existing ESPs on boilers C and D to achieve the BART
emissions limits. tnitial performance tests for PM/PM16 have been completed for both boilers.
The PM/PMro compliance deadline for both boilers was on or before November I l, 2009.
IV. Proper Maintenance and Operation of Control Equioment
The State of Wyoming requires that General Chemical follow the monitoring and recordkeeping
requirements of Section 6.4V. to ensure proper maintenance and operation of control equipment.
6.5.4 PacifiCorp - Jim Bridger Power Plant
I. The Five-Factor Analysis
After considering (l) the costs of compliance, (2) the energy and non-air quality environmental
impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the
remaining useful life of the source, and (5) the degree of improvement in visibility (all five
statutory factors) from each proposed control technology, the Division determined BART for
NO* and PM/PMro emitted from the four units subject to BART at the Jim Bridger Power Plant.
In addition to the five-factor analysis, the Division also considered the unique situation
PacifiCorp is in since they own and operate 19 coal-fired generating units in the West. The
Division believes that the size of PacifiCorp's fleet of coal-fired units presents unique challenges
when reviewing costs, timing of installations, customer needs, and state regulatory commission
requirements. Information has been supplied by PacifiCorp elaborating on additional factors to
be considered in PacifiCorp's BART determination (see "PacifiCorp's Emissions Reductions
Plan" in Chapter 6 ofthe Wyoming TSD).
For control of NO* emissions, the State of Wyoming requires that PacifiCorp install and operate
LNB with separated OFA as BART for Units I through 4. Annual NO* emission reductions
from LNB with separated OFA on Units l, 3, and 4 are 4,493 tons per unit for a total annual
reduction at the Jim Bridger Power Plant of 13,479 tons per year. There are no NO* reductions
from Unit 2 as LNB separated OFA is baseline for the unit.
LNB with separated OFA on Units l, 3, and 4 is cost effective, with an average cost
effectiveness of $255 per ton of NO* removed for each unit over a twenty-year operational life.
LNB with separated OFA on Unit 2 did not require any additional capital cost or annual O&M
cost. Combustion control using LNB with separated OFA does not require non-air quality
environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is a
minimalenergy impact.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 112 ol 206
102
For control of PM/PMro emissions, the State of Wyoming requires that PacifiCorp utilize the
existing electrostatic precipitators (ESPs) with the addition of flue gas conditioning (FGC) as
BART for Units l -4. The control technology is cost effective for each unit, with costs per ton
removed of $1,544 for Unit l,$526 for Unit 2, and $857 for Unit 3. Unit 4 does not require
additional capital cost. No negative non-air environmental impacts are anticipated from the use
of the existing ESPs with FGC.
Visibility impacts were addressed in a comprehensive visibility modeling analysis covering three
visibility impairing pollutants and associated control options. The cumulative 3-year averaged
98th percentile visibility improvement from the baseline across the three Class I areas (Bridger,
Fitzpatrick, and Mt. Zirkel wilderness areas) achieved with LNB with separated OFA, upgraded
wet FGD, and FGC for enhanced ESP controlwas 1.070 Adv from Unit l, 0.199 Adv from Unit
2, 1.068 Adv from Unit 3, and 0.892 Adv from Unit 4. While the visibility improvement
attributable to the installation of FGC on existing ESPs can't be directly determined from the
visibility modeling, the Division does not anticipate the contribution from PM to be significant
when compared to the contributions from NO* and SO2.
The State of Wyoming considers the BART-determined permit limit to be equivalent to the
control effectiveness of a control technology. The limit is based on continuous compliance when
the control equipment is well maintained and operated in a manner consistent with good air
pollution control practices for minimizing emissions.
Unit-by-unit BART determinations for NO*and PM/PMro:
Filterable portion onlyESP : electrostatic precipitator
FGC : flue gas conditioningLNB : low NO. bumersOFA : overfire air
III. Expeditious Installation and Operation of BART
The State of Wyoming requires that PacifiCorp install and operate new LNB with separated OFA
on Unit l, in accordance with the Division's BART determination, and conduct the required
initial perfoffnance tests to demonstrate compliance as expeditiously as practicable, but no later
than five years after EPA approval of the state implementation plan revision. Installation of
LNB and separated OFA has been completed and initial performance tests have been completed
on Units 2,3, and 4. The NO* compliance deadline for Units 2-4 was on or before March 3 l,
2010. With respect to particulate matter, the State of Wyoming requires that PacifiCorp continue
the use of the existing ESPs on Units I through 4 with FGC to achieve the BART emissions
limits. Initial performance tests have been conducted and the PM/PMro compliance deadline for
Units I -4 was on or before March 3 l, 2010.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 113 of206
Units Pollutant Control Type lb/h4MBtu lb/hr tpv
1,2,3, & 4 NO*LNB/OFA 0.26 (30-day rolling)1,560 1lo-dayrolling)6,833
1,2,3, & 4 PM/PMro(")ESP + FGC 0.030 180 788
IV. Proper Maintenance and Operation of Control Equipment
The State of Wyoming requires that PacifiCorp conduct initial NO* performance tests on Unit l,
after the installation of LNB and separated OFA, within 30 days of achieving a maximum design
rate, but not later than 90 days following initial start-up. If a maximum design rate is not
achieved within 90 days of start-up, the AQD Administrator may require testing be done at the
rate achieved and again when a maximum rate is achieved. A test protocol shall be submitted for
Division approval prior to testing and a written report of the test results shall be submitted to the
Division. Testing required by the WAQSR Chapter 6, Section 3 operating permit may be
submitted to satisfy the testing required.
The State of Wyoming requires that PacifiCorp follow the monitoring and recordkeeping
requirements of Section 6.4 V . to ensure proper maintenance and operation of control equipment.
6.5.5 PacifiCorp - Dave Johnston Power Plant
I. The Five-Factor Analysis
After considering ( l) the costs of compliance, (2) the energy and non-air quality environmental
impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the
remaining useful life of the source, and (5) the degree of improvement in visibility (all five
statutory factors) from each proposed controltechnology, the Division determined BART for
NO* and PMro emitted from the two units subject to BART at the Dave Johnston Power Plant.
For control of NO* emissions, the State of Wyoming requires that PacifiCorp install and operate
LNB with advanced OFA as BART for Units 3 and 4. The State of Wyoming willrequire aNO*
control level of 0.28 lb/IvtMBtu on a 30-day rolling average, below EPA's applicable
presumptive limit of 0.45 lb/I\4MBtu for cell-fired boilers burning subbituminous coal, for Unit
3. For Unit 4, the State of Wyoming will require a NO* control level of 0. I 5 lbA,IMBtu on a 30-
day rolling average, equal to EPA's applicable presumptive limit for tangential-fired boilers
burning subbituminous coal. Annual NO* emission reductions from LNB with advanced OFA
on Unit 3 and 4 are 2,723 tons and 6, 142 tons, respectively.
LNB with advanced OFA on Units 3 and 4 is cost effective, with an average cost effectiveness of
$648 per ton of NO* removed for Unit 3 and $137 per ton for Unit 4. Combustion control using
LNB with advanced OFA does not require non-air quality environmental mitigation for the use
of chemical reagents (i.e., ammonia or urea) and there is a minimal energy impact.
For control of PM/PMre emissions, the State of Wyoming requires that PacifiCorp install and
operate new full-scale fabric filters on Units 3 and 4 to meet coresponding BART emission
limits on a continuous basis. When considering all the factors above and beyond the benefits
associated with regionalhaze which include the existing precipitator's current condition and
performance and end of life issues, the ability of the current electrostatic precipitator to meet an
ESP BART rate of 0.23 lb/lvfMBtu on a continuous basis and the enhanced mercury removal co-
benefits the baghouse provides, the Wyoming Air Quality Division has determined that the costs
associated with the installation of a new full-scale fabric filter are reasonable. A full-scale fabric
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 114 of206
104
filter is the most stringent PMiPMro control technology and therefore the Division accepts it as
BART. The Division considers the installation and operation of the BART-determined PM/PMIo
controls of a new full-scale fabric filter on Unit 3 at Dave Johnston, as recently permitted in Air
Quality Permit MD-5098, to meet the requirements of BART.
When considering allthe factors above and beyond the benefits associated with regionalhaze
which include the existing venturi scrubber's current condition and performance and end of life
issues, the ability of the current venturi scrubber to meet a venturi scrubber BART rate of 0.21
lb/IvIMBtu on a continuous basis and the enhanced mercury removal co-benefits the baghouse
provides, the Wyoming Air Quality Division has determined that the costs associated with the
installation of a new full-scale fabric filter are reasonable. A full-scale fabric filter is the most
stringent PM/PM1o control technology and therefore the Division accepts it as BART. The
Division considers the installation and operation of the BART-determined PM/PM1o controls of a
new full-scale fabric filter on Unit 4 at Dave Johnston, as recently permitted in Air Quality
Permit MD-5098, to meet the requirements of BART.
Visibility impacts were addressed in a comprehensive visibility modeling analysis covering three
visibility impairing pollutants and associated control options. The cumulative 3-year averaged
98fr percentile visibility improvement from baseline, summed across all four Class I areas
(Badlands and Wind Cave national parks, and Mt. Zirkel and Rawah wilderness areas) and
achieved with LNB with advanced OFA, dry FGD, and a new full-scale fabric filter, was 3.558
Adv from Unit 3 and 1.963 Adv from Unit 4.
The State of Wyoming considers the BART-determined permit limit to be equivalent to the
control effectiveness of a control technology. The limit is based on continuous compliance when
the control equipment is well maintained and operated in a manner consistent with good air
pollution control practices for minimizing emissions.
Unit-by-unit BART determinations for NO*and PM/PMro:
Filterable portion onlyLNB : low NO* burnersOFA = overfire air
III. Expeditious Installation and Operation of BART
The State of Wyoming requires that PacifiCorp install and operate new low NO* burners with
advanced OFA on Units 3 and 4, in accordance with the Division's BART determination, and
conduct the required initial perforrnance tests to demonstrate compliance as expeditiously as
practicable, but no later than five years after EPA approval of the state implementation plan
revision. The State of Wyoming requires that PacifiCorp install new full-scale fabric filters on
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 115 of206
Unit Pollutant ControlType lb/MMBtu lb/hr tpv
J
NO*LNB/OFA 0.28 1:o-0ay rolling)784 1fo-day rolling)3,434
PM/PM1e(")Fabric Filter 0.015 42.1 184
4
NO*LNB/OFA 0.15 (30-day rolling)615 1:o-aayrolling)2,694
PM/PMro(")Fabric Filter 0.015 61.5 269
105
Units 3 and 4, in accordance with the Division's BART determination, and conduct the initial
performance tests required to demonstrate compliance as expeditiously as practicable, but no
later than five years after EPA approval of the state implementation plan revision.
IV. Proper Maintenance and Operation of Control Equipment
The State of Wyoming requires that PacifiCorp follow the monitoring and recordkeeping
requirements of Section 6.4 V. to ensure proper maintenance and operation of controlequipment.
6.5.6 PacifiCorp - Naughton Power Plant
I. The Five-Factor Analysis
After considering (l) the costs of compliance, (2) the energy and non-air quality environmental
impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the
remaining useful life of the source, and (5) the degree of improvement in visibility (all five
statutory factors) from each proposed controltechnology, the Division determined BART for
NO* and PMro emitted from the three units subject to BART at the Naughton Power Plant.
For controlof NO*emissions, the State of Wyoming requires that PacifiCorp install and operate
LNB with advanced OFA as BART for Units I and2, and tune the existing LNB/OFA system on
Unit 3 and install SCR. AnnualNO* emission reductions from baseline for LNB with advanced
OFA on Units I and2 are2,334 and,2,649 tons, respectively. Annual NO* emission reductions
from baseline achieved by tuning the existing LNB/OFA and installing SCR on Unit 3 are 5,542
tons.
LNB with advanced OFA on Units I and 2 is cost effective, with an average cost effectiveness of
9426 and $357, respectively, per ton of NO* removed for each unit over a twenty-year
operational life. Combustion control using LNB with advanced OFA for Units I and 2 does not
require non-air quality environmental mitigation for the use of chemical reagents (i.e., ammonia
or urea) and there is a minimal energy impact. The cost effectiveness of tuning the existing LNB
with OFA and installing SCR on Unit 3 was reasonable, with a value of $2,830 per ton of NO*
removed.
For control of PM/PMr6 emissions, the State of Wyoming requires that PacifiCorp utilize the
existing ESPs and add FGC as BART for Units I and 2. The control technology is cost effective
for each unit, with costs per ton removed of $ 1,721 for Unit I and $949 for Unit 2. No negative
non-air environmental impacts are anticipated from the use of existing ESPs with FGC. For
control of PM/PMro emissions from Unit 3, the State of Wyoming requires that PacifiCorp install
and operate a new, full-scale fabric filter to meet a corresponding BART emission limit on a
continuous basis. When considering all the factors above and beyond the benefits associated
with regionalhaze which include the existing precipitator's current condition and performance
and end-of-life issues, the ability of the current electrostatic precipitator to meet an ESP BART
rate of 0.04 lb/IvIMBtu on a continuous basis, the enhanced mercury removal co-benefits the
baghouse provides, and the reduced ash loading on the SOz scrubber which will enhance the
scrubber performance, the Wyoming Air Quality Division has determined that the costs
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 'l 16 of 206
106
associated with the installation of a new full-scale fabric filter are reasonable. A full-scale fabric
filter is the most stringent PM/?Mro control technology and therefore the Division accepts it as
BART. The Division considers the installation and operation of the BART-determined PM/PM1o
controls of a new full-scale fabric filter on Unit 3 to meet the statutory requirements of BART.
Visibility impacts were addressed in a comprehensive visibility modeling analysis covering three
visibility impairing pollutants and associated control options. The cumulative 3-year averaged
98s percentile visibility improvement from the baseline across Bridger WA and Fitzpatrick WA
achieved with LNB with advanced OFA, wet FGD, and FGC for enhanced ESP control was
I .716 Adv from Unit I and I .934 Adv from Unit 2. While the visibility improvement
attributable to the installation of FGC on existing ESPs can't be directly determined from the
visibility modeling, the Division does not anticipate the PM contribution to be significant when
compared to the NO* and SO2 contributions. For Unit 3, the cumulative 3-year averaged 98ft
percentile visibility improvement from the baseline summed across both Class I areas achieved
by tuning the existing LNB with OFA, wet FGD and installing a new full-scale fabric filter, was
0.826 Adv. The installation of SCR on Unit 3 produces an additional 1.023 Adv in cumulative,
3-year averaged 98ff percentile modeled visibility improvement across the two Class I areas.
The State of Wyoming considers the BART-determined permit limit to be equivalent to the
control effectiveness of a control technology. The limit is based on continuous compliance when
the control equipment is well maintained and operated in a manner consistent with good air
pollution control practices for minimizing emissions.
Unit-by-unit BART determinations for NO" and PM/PM r o:
Filterable portion onlyESP : electrostatic precipitator
FCC = flue gas conditioningLNB : low NO*bumersOFA = overfire air
III. Expeditious Installation and Operation of BART
The State of Wyoming requires that PacifiCorp install and operate new low NO* burners with
advanced OFA and install flue gas conditioning on the existing ESPs on Units I and2,in
accordance with the Division's BART determination, and conduct the required performance tests
to demonstrate compliance as expeditiously as practicable, but no later than five years after EPA
approval of the state implementation plan revision.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 117 of206
Units Pollutant Control Type lb/TvIMBtu lb/hr tpy
I NO*LNB/OFA 0.26 1fo-aay rolling)481 (:o-aayrolling)2,107
PM/PM16 (")ESP + FGC 0.040 74 324
2 NO*LNB/OFA 0.26 1fo-aay rolling)624 Qo-aay rolling)2,733
PM/PMro G)ESP + FGC 0.040 96 421
3
NO*Tune LNB/OFA + SCR 0.07 (:o-day rolling)259 Go-aay rolling)1,134
PM/PMro (")Fabric Filter 0.0r5 56 243
107
The State of Wyoming requires that PacifiCorp shall tune the existing low NO* burners with
OFA and install selective catalytic reduction and a full-scale fabric filter on Unit 3, in accordance
with the Division's BART determination to demonstrate compliance as expeditiously as
practicable, but no later than five years after EPA approval of the state implementation plan
revision.
IV. Prooer Maintenance and Operation of Control Equipment
The State of Wyoming requires that PacifiCorp follow the monitoring and recordkeeping
requirements of Section 6.4 V. to ensure proper maintenance and operation of control equipment.
6.5.7 PacifiCorp - Wyodak Power Plant
I. The Five-Factor Analysis
After considering (l) the costs of compliance, (2) the energy and non-air quality environmental
impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the
remaining useful life of the source, and (5) the degree of improvement in visibility (all five
statutory factors) from each proposed control technology, the Division determined BART for
NO* and PMro emitted from the single unit subject to BART at the Wyodak Power Plant.
For control of NO* emissions, the State of Wyoming requires that PacifiCorp install and operate
LNB with advanced OFA as BART for Unit l. Annual NO* emission reductions from baseline
with LNB with advanced OFA on Unit I are 1,483 tons. LNB with advanced OFA on Unit I is
cost effective, with an average cost effectiveness of $881 per ton of NO" removed over a twenty-
year operational life. Combustion control using LNB with advanced OFA does not require non-
air quality environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and
there is a minimal energy impact.
For control of PM/PMro emissions from Unit l, the State of Wyoming requires that PacifiCorp
install and operate a new, full-scale fabric filter to meet a corresponding BART emission limit on
a continuous basis. When considering all the factors above and beyond the benefits associated
with regionalhaze which include the existing precipitator's current condition and performance
and end of life issues, the ability of the current electrostatic precipitator to meet an ESP BART
rate of 0.10 lb/lv1MBtu on a continuous basis, and the enhanced mercury removal co-benefits the
baghouse provides, the Wyoming Air Quality Division has determined that the costs associated
with the installation of a new full-scale fabric frlter are reasonable. A full-scale fabric filter is the
most stringent PM/PMro controltechnology and therefore the Division accepts it as BART. The
Division considers the installation and operation of the BART-determined PM/PMro controls of a
new full-scale fabric filter at Wyodak, as recently permitted under Air Quality Permit MD-7487,
to meet the requirements of BART.
Visibility impacts were addressed in a comprehensive visibility modeling analysis covering three
visibility impairing pollutants and associated control options. The cumulative 3-year averaged
98n percentile visibility improvement from the baseline summed across both Class I areas
(Badlands and Wind Cave national parks) achieved with LNB with advanced OFA, upgrading
the dry FGD, and a new full-scale fabric filter was 0.996 Adv.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 118 of206
108
The State of Wyoming considers the BART-determined permit limit to be equivalent to the
control effectiveness of a control technology. The limit is based on continuous compliance when
the control equipment is well maintained and operated in a manner consistent with good air
pollution control practices for minimizing emissions.
Unit-by-unit BART determinations for NO*and PM/PMro:
Filterable portion onlyLNB = lowNO"bumersOFA = overfire air
III. Expeditious Installation and Ooeration of BART
The State of Wyoming requires that PacifiCorp install new low NO* burners with advanced OFA
and a new full-scale fabric filter on Unit l, in accordance with the Division's BART
determination, and conduct the initial performance tests to demonstrate compliance as
expeditiously as practicable, but no later than five years after EPA approval of the state
implementation plan revision.
O
IV. Proper Maintenance and Operation of Control Eouipment
The State of Wyoming requires that PacifiCorp follow the monitoring and recordkeeping
requirements of Section 6.4 V. to ensure proper maintenance and operation of control equipment.
6.5.8 Basin Electric Power Cooperative - Laramie River Station
The Air Quality Division issued a BART permitfor Basin Electric Power Cooperative -
Laramie River Station on December 31,2009 under Permit No. MD-6047. A summary of the
Division'sftve-factor analysis performed to support the BART permit issued on December 31,
2009 is included below. The daailedftve-factor analysis is included in Attachment A of this
SIP.
L The Five-Factor Analysis
After considering (l) the costs of compliance, (2) the energy and non-air quality environmental
impacts of compliance, (3) any pollution equipment in use or in existence at the source, (4) the
remaining useful life of the source, and (5) the degree of improvement in visibility (all five
statutory factors) from each proposed controltechnology, the Division determined BART for
NO* and PMro emitted from the three units at the Laramie River Station.
For control of NO* emissions, the State of Wyoming requires that Basin Electric install new LNB
with OFA as BART for Units I through 3. Annual NO* emission reductions from new LNB
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 119 of206
Unit Pollutant Control Type lb/lvlMBtu lb/hr tpy
I
NO.LNB/OFA 0.23 (fO-day rolling)1,081.0 (30-day rolling)4,735
PM/PMro(")Fabric Filter 0.0r5 71.0 309
109
withOFAonUnits l,2,and3arel,862-l,9l0tonsperunitforatotalannualreduction of 5,645
tons.
LNB with separated OFA on Units I through 3 is cost effective, with an average cost
effectiveness of $2,036-$2,088 per ton of NO* removed for each unit over a twenty-year
operational life. Combustion control using LNB with OFA does not require non-air quality
environmental mitigation for the use of chemical reagents (i.e., ammonia or urea) and there is a
minimal energy impact.
For control of PM/PMro emissions, the State of Wyoming requires that Basin Electric utilize the
existing ESPs as BART for Units I through 3. The cost of compliance for the sole technically
feasible control option, a retrofit fabric filter on the Unit 3 ESP, is not reasonable over a twenty-
year operational life. No negative non-air environmental impacts are anticipated from use of the
existing ESPs.
Visibility impacts were addressed in a comprehensive visibility modeling analysis covering three
visibility impairing pollutants and associated control options. The cumulative 3-year averaged
visibility improvement from the baseline across Wind Cave NP and Badlands NP achieved with
new LNB with OFA at the 30-day limit of 0.23 lb/\{MBtu (based on the 98th percentile modeled
results) was 0.14 Adv from each of the three units. The expected visibility improvement over the
course of a full annual period would be even greater due to the annual BART limit that is based
on 0.19 lb/\4MBtu.
The State of Wyoming considers the BART-determined permit limit to be equivalent to the
control effectiveness of a control technology. The limit is based on continuous compliance when
the control equipment is well maintained and operated in a manner consistent with good air
pollution control practices for minimizing emissions.
Unit-by-unit BART determinations for NO*and PM/PMro:
Filterable portion onlyESP : electrostatic precipitatorLNB = low No*bumersOFA : overfire air
The performance/efficiency-based, 30-day rolling average emission rate of 0.23 lb/IVfMBtu is set
to allow for continuous compliance with proper operation of the control equipment, while taking
into account the normal operational variability that is typical for a boiler. The 30-day limits that
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page '120 of 206
Units Pollutant Control Type lb/MMBtu 1b/hr tpy
I
NO*LNB/OFA 0.23 (fo-aay rolling)1,348 (:o-aay rotling)5,343 112-month
rolline)
PM/PMro (")ESP 0.030 193 844
2 NO*LNB/OFA 0.23 (30-day rolling)1,348 (:O-aay rotling)5,343 1l2-month
rolline)
PM/PMro(u)ESP 0.030 193 844
3
NO*LNB/OFA 0.23 1:O-day rolling)1,386 1lo-day rolling)5,493 (12-month
rolline)
PM/PMro (")ESP 0.030 198 867
are expressed in terms of mass emissions (lb/hr) are based on 0.21 lb/IvIMBtu. Because reduced
steam loads on a boiler can result in periods of increased emissions in terms of lb/IvIMBtu but
lower emissions in terms of lb/hr, the Division has chosen to set the dual 30-day limits, one set at
0.23 lbA{MBtu and one expressed in lb/hr based on 0.21 lb/IvIMBtu. For the l2-month rolling
emission limits, the Division considered the ability of the source to maintain a lower emission
rate over a longer time period and set the long-term limit (expressed in tpy) based on 0.19
lblTttMBtu.
III. Expeditious Installation and Operation of BART
The State of Wyoming requires that Basin Electric install new low NO* burners with separated
OFA on Units I through 3, in accordance with the Division's BART determination, and conduct
the required initial performance tests to demonstrate compliance as expeditiously as practicable,
but no later than five years after EPA approval of the state implementation plan revision.
The State of Wyoming requires that Basin Electric continue the use of the existing ESPs on Units
I through 3 to achieve the BART emissions limits. The PM/PM1g compliance deadline was
March 3 l, 20 10.
IV. Proper Maintenance and Operation of Control Equipment
The State of Wyoming requires that Basin Electric follow the monitoring and recordkeeping
requirements of Section 6.4 V. to ensure proper maintenance and operation of control equipment.
Subsequent NO^ BART Determinations
On March 8, 2010, Basin Electric Power Cooperative appealed the BART permitfor the
Laramie River Station before the lVyoming Environmental Quality Council (EQC). The
Department of Environmental Quality entered into a settlement agreement on November 16,
2010 with Basin Electric Power Cooperative (Docket No. 10-2802). On December 8,2010, the
Division held a State Implementation Plan (SIP) Hearing on Regional Haze. The SIP hearing
was held in Cheyenne, Wyoming at the Laramie County Library,2200 Pioneer Avenue. At
that time, the Division collected public comment on the Regional Haze SIP revisions.
After carefully considering all comments on revisions to the State Implementation Plan to
address Regional Haz4 the Division has determined that the following table, taken from the
Settlement Agreement Filed November 16,2010 before the Wyoming EQC and incorporated
into the EQC Order approving the Settlement, shall establish the BART limits for three units
at Laramie River Station with respect to NO* and NO, only, and that these BART lirnits shall
replace the BART limitsfor NO*determined by the Division in Permit MD-6047 issued on
December 31,2009. The Division has remodeled the emission limits established through this
Settlement to detertnine the resulting visibility impacts. This impact analysis is included in
Attachment A.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 121 of206
llr
Effective upon completion of the initial performance tests to verify the emission levels below,
emissionsfrom Laramie River Station Units I through 3 shall not exceed the levels below.
0.21 (j0-day rolling)Unit 1: 1,220
Unit 2: 1,220
Unit 3: 1,254
Unit 1: 4,780
Unit 2: 4,780
Unit 3: 4,914
all l2-month
Overall NO*Reductions in Wyoming
In the State of Wyoming, significant additional NO* reductions will be made at the completion of
the BART process. The overall cumulative NO* reductions from Wyoming BART sources over
time are demonstrated in the figure below. If regional funding becomes available, future
regional modeling will demonstrate the additional progress towards 2018 visibility goals.
6.5.8-1. Additional Cumulative N0, Reductions From W BART Sources
Total BART EGU & NonEGU N0, Emission Reductions (tons!
410m
40,0m
35,00
30,0m
25,0([
20,000
$,0m
10,0m
1m0
0
,d" d) di dP d d ,ot d ,ot dP d,t d| ,C d
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 122 ot 206
tt2
CHAPTER 7
REASONABLE PROGRESS GOALS
7.1 Overview
The fundamental purpose of the Regional Haze Rule (RHR) is to restore visibility in all
mandatory Class I areas across the United States to natural conditions by the year 2064. As
required by the RHR, each state must submit a State Implementation Plan (SIP) that addresses
visibility reductions in Class I areas for the initialplanning period of 2005-2018, with successive
revisions occurring every ten years after 2018. In order to demonstrate incremental visibility
improvement during the first planning period, the State of Wyoming was required to establish
reasonable progress goals (RPGs) for the seven Class I areas within the state.
Reasonable progress goals listed in Section 7.5 of this chapter are used to gauge the progress that
the State of Wyoming can reasonably make towards improving visibility to natural conditions in
Class I areas within the state. Each Class I area RPG consists of two visibility values, expressed
as deciviews (dv), that represent the most impaired visibility days (i.e., the average of the 20Yo
most impaired days over an entire year) and the least impaired visibility days (i.e., the average of
the 20Yo least impaired days over an entire year).
While the reasonable progress goals are not enforceable, the control measures adopted by the
State of Wyoming are enforceable. To determine if reasonable progress is being made in
improving visibility, the State will need to collect and analyze air quality data and update the 5-
year visibility averages for the 20% worst visibility days and the 20Yo best visibility days and
compare the 5-year average with the baseline conditions (after 2018, the 5-year average will be
compared to the impairment levels reported in the previous SIP revision). If the control
measures set by the State do not result in a reduction in visibility impairment equal to or greater
than the RPG for 2018, then the State of Wyoming can either revise its control strategies to meet
the RPG or revise the RPG for the next planning period.
RPGs are non-enforceable, interim goals, expressed in deciviews, which represent interim
visibility improvement in an effort to eventually achieve natural visibility conditions in Class I
areas. When RPGs are established, they must provide for visibility improvement for the 20o/o
worst visibility days and ensure that there is not a reduction in visibility for the least impaired
days, calculated as the20Yo best visibility days, through 2018. For states with multiple Class I
areas, RPGs can be established separately for each one. The established goals must represent
greater visibility improvement than what would result from the other requirements of the Clean
Air Act (CAA).
States must revisit their reasonable progress goals in 2018, as discussed in Chapter 10, by
evaluating the progress towards natural conditions and the effectiveness of the long-term strategy
for achieving the goals. If progress towards natural visibility conditions is unsatisfactory, the
reasonable progress goals can be revised.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 123 of206
l13
7.2 Process for Establishing Reasonable Progress Goals
Several steps for establishing reasonable progress goals were outlined in the RHR and are
discussed in the following subsections.
o Calculate/Estimate Baseline and Natural Visibility Conditions
Baseline visibility conditions were determined by the Western Regional Air Partnership (WRAP)
Technical Support System (TSS) using the Interagency Monitoring of Protected Visual
Environments (IMPROVE) algorithm. The IMPROVE algorithm followed the established
guidelines presented in the RHR. To determine baseline visibility conditions, the average degree
of visibility (expressed as dv) for the 20Yoleast impaired days and the 20o/o worst impaired days
was calculated, using IMPROVE air quality monitoring dat4 for each calendar year from 2000
to2004. The IMPROVE monitoring program collects speciated PMz.s, and PMzs and PMro
mass. IMPROVE is a nationwide network which began in 1988 and expanded significantly in
2000 in response to the EPA's Regional Haze Rule (RHR). The RegionalHaze Rule specifically
requires data from this program to be used by states and tribes to track progress in reducing haze.
The annual values were then averaged over five years to determine the baseline visibility
condition values. Baseline visibility is discussed in detail in Chapter 2.
Natural conditions are an estimate of the amount of visibility impairment that would occur if no
human-caused visibility impairment existed. Natural conditions were determined by the WRAP
through the Natural Haze Levels II Committee for the20Yo worst visibility days andthe20Yo
best visibility days using available monitoring data and the IMPROVE algorithm. The Natural
Haze Levels II Committee was established in 2006 to review and refine the default approach.
The committee included representatives from NOAA, NPS, Cooperative Institute for Research in
the Atmosphere (CIRA), Regional Planning Organizations (RPOs) and industry representatives,
and other participants. The final report of the committee can be found at:
http://wrapair.org/forums/aoh/meetings/060726denA.{aturalHazelevelsllReport.ndf. Additional
information about the baseline and natural visibility impairment calculations can be found in
Chapter 13.
o Determine the Uniform Rate of Progress (URP)
The URP (also known as the glide slope), which was determined by the State of Wyoming for all
mandatory Class I areas within the state, is the rate of visibility change necessary to achieve
natural visibility conditions by the year 2064. The URP represents the slope between baseline
visibility conditions in2004 and naturalvisibility conditions in2064. Using interpolation, the
improvement necessary by 2018 to achieve natural visibility conditions in2064 can be calculated
as shown in Table 7 .2-l . The URP is discussed in greater detail in Chapters 3 and 5.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 124 of 206
l14
Table 7.2-1. 20o Best and Worst Days Baseline, Natural Conditions, and Uniform Rate of
P Goal for Wvomins Class I Areas
o Four Factor Analysis
In an effort to reduce visibility impairing air pollutants, emission control measures had to be
evaluated. The four factor analysis process was established in the RHR and is discussed in detail
in Section 7.3 of this chapter. Each emission control strategy, as required by the four factor
analysis guidelines, was evaluated based on l) the cost of compliance, 2) time necessary for
compliance, 3) the energy and non-air quality environmental impacts of compliance, and 4) the
remaining useful life of any existing source subject to such emission controls.
o Consultation With Other States
According to the RHR, the State of Wyoming must consult with other states that may cause or
contribute to visibility impairment in Wyoming Class I areas. For the State of Wyoming,
consultations with other states contributing to visibility impairment in Class I areas were
conducted through the WRAP. Additional information on the state consultations can be found in
Chapter I l.
o Determination of Reasonable Progress Goals
Reasonable progress goals, when established, demonstrate the amount of visibility improvement
the State of Wyoming believes to be feasible, based on the four factor analysis and Clean Air Act
(CAA) requirements, during the first planning period. The reasonable progress goal may be the
same, less stringent, or more stringent than the visibility improvement based on the URP. The
reasonable progress goals, and the logic used to determine the goals, are discussed in Sections
7.5 and 7.6 of this chapter.
7.3 Four Factor Analysis Performed.for Wyoming Sources
The four factor analysis, which is presented in the RHR, is a method for evaluating potential
control strategies for facilities that are not eligible for Best Available Retrofit Technology
(BART) or better-than-BART programs. The analysis considers l) the cost of compliance, 2) the
time necessary for compliance, 3) environmental impacts of compliance, and 4) the remaining
useful life of the facility.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 125 of 2QO
IMPROVE
Monitor
Name
Wyoming Class I Areas
20%Worst DaYs Z0% Best Days
2000-04
Baseline
(dv)
201 8
URP
Goal
(dv)
201 8
Reduction
Needed
(dv)
2064
Natural
Conditions
(dv)
Future Date
for Reaching
Natural
Conditions at
Curent Rate
2000-04
Baseline
(dv)
2064
Natural
Conditions
(dv)
YELL2
Yellowstone National Park
Grand Teton National Park
Teton Wilderness
Il8 t0.5 1.3 6.4 2t30 2.6 0.4
NOABI North Absaroka Wildemess
Washakie Wildemess ll5 104 ll 68 2t16 2.0 0.6
BRIDI Bridger Wrlderness
Fiupatrick Wildemess I l.l 100 l.l 6.5 2165 2.1 0.3
(WRAP TS S - httn ://v i sta.cira.colostate.edu/tss/)
I 15
The WRAP hired EC/R Incorporated (EC/R), headquartered in Chapel Hill, North Carolina, to
complete the four factor analysis. Control measures for NO* and direct particulate matter
emissions were evaluated for selected sources in Wyoming. A four factor analysis is not
required for SO2 since the State of Wyoming has addressed visibility impairment associated with
this pollutant under the 309 SIP previously submitted to EPA.
7.3.1 Detailed Description of the Four Factors
o Cost of Compliance
Both control costs and net annual costs were analyzed for all control measures identified by
ECIR. Control costs cover direct and indirect capital costs. Examples of direct capital expenses
includes the costs associated with purchased equipment, construction, installation,
instrumentation and process controls, ductwork and piping, electrical components, and structural
and foundation components. Indirect capital expenses include costs such as engineering and
design, contractor fees, startup and performance testing, contingency costs, and process
modifications.
Net annual costs include the expenses associated with the typical operation of the control
equipment over a year. Annual costs include items such as the utility expenses, labor, waste
disposal expenses, and amortized costs ofthe capital investment. All cost estimates calculated
by ECIR were updatedto 2007 dollars using the Marshall and Swift Equipment Cost Index or the
ChemicalEngineering Plant Cost lndex, which are both published in the joumal Chemical
Ensineerins.
o Time Necessary for Compliance
The time necessary for compliance includes the time needed for the State of Wyoming to
develop and implement regulations for emissions controls, as well as the time the sources require
to procure the capital to purchase the emission control equipment, design and fabricate the
equipment, and to install the emission controls. When a retrofit control device is required, the
time necessary for compliance includes the time for capital procurement, device design,
fabrication, and installation.
. Energy and Other Non-Air Quality Environmental Impacts
Emission control devices often require some form of energy input to operate. To determine the
energy requirements for a particular control device, the electricity needs, steam requirements,
increased fuel requirements, and any additional energy inputs required were quantified. Only the
direct energy requirements were considered; indirect energy needs, such as the amount of energy
required to produce the fuel for the control device, were not analyzed. In addition, any impacts
the controltechnologies had on other source processes, such as boiler efficiency, were not
evaluated.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 126 of206
l16
While the control devices reduce air pollution, they often produce waste. Environmental impacts
of each control technology were analyzed by EC/R and included the waste generated, the
wastewater generated, additional CO2 produced, reduced acid deposition, and reduced nitrogen
deposition. If available, the benefits from PM2 5 and ozone reductions were also evaluated.
o Remaining Equipment Life at Source
The remaining equipment life of the source will impact the cost of emission control technologies
if the expected life of the source is less than the lifetime of the pollution control device being
considered. Therefore, if the remaining equipment life is less than the lifetime of the pollution
control device, the capital cost of the pollution control device is amortized for the remaining life
of the emission source. To determine the annual cost ofthe emission control device if the
expected life of the source is less than the expected life on the control device, the following
equation can be used:
At:Ao+Cx
where:
1-(1*r)--
1 - (1*r)-a
,{1 : the annual cost of control for the shorter equipment life ($)
46: the original annual cost estimate ($)
C : the capital cost of installing the control equipment ($)
r: the interest rate (0.07)
m: the expected remaining life of the emission source (years)
n: the projected lifetime of the pollution conffol equipment
7.3.2 Source Selection Process for Four Factor Analysis
To select the sources that would undergo the required four factor analysis, emission data for
sources in Wyoming had to first be collected. This was accomplished using the WRAP
Emissions Data Management System (EDMS), which contains inventories from stationary
sources, fires, area sources, on-road mobile sources, off-road mobile sources, windblown dust,
and biogenic sources across the state. After evaluating the emissions, it was determined that the
primary emissions from anthropogenic sources, which are sources the State of Wyoming can
regulate, were NO* and SOz based on Tables 4.2-l and 4.3-1, and Figures 5.2.1-l through 5.2.1-
3 and 5.2.3-l through 5.2.3-3 found in Chapters 4 and 5. Since sources of SOz were addressed in
great detail in the previous 309 submittal, this screening process focuses on NO" sources.
A basic screening technique, referred to as the Quantity over Distance or "Q over D" analysis,
was implemented by the State of Wyoming in order to select the sources to undergo the four
factor analysis, There is no requirement to use this technique, but it has been employed by EPA
and other states to roughly determine which sources had the largest contributions of visibility
impairing pollutants in Class I areas in Wyoming and surrounding states. It is a basic, intuitive
toolthat allows the State to evaluate emissions from sources of concern. The sources of concern
in this first SIP were the large sources that were similar in magnitude to the sources covered
under BART, but were not covered by the timeframe requirements of BART.
Exhibit No. 4
Case No. IPC-E-I3-16
T. Harvey, IPC
Page127 ot206
tt7
The screening technique included sources when the following was met:
l, ,o
where Q represents the maximum emission rate, in tons per yeilr, of the source and D is the
distance in kilometers to the nearest Class I area. A spreadsheet showing all of the sources with
a Q/D greater than l0 can be found in Chapter 7 of the Wyoming TSD. Three emission units
were identified in the state having 3 = ,o and thereby selected to undergo the four factor
analysis.
7.3.3 PacifiCorp Dave Johnston Electric Generating Station
Two units, BW4l and 8W42, at the Dave Johnston Electric Generating Station were selected for
the four factor analysis in Wyoming. Both units are sub-bituminous coal-fired boilers capable of
producing up to I l4 megawatts (MUD. Emissions are currently controlled with a cold-side
electrostatic precipitator (ESP).
Four possible emission control devices were identified and analyzed using the four factor
analysis process for the boilers: low NO* burners (LNB), low NO* burners with overfire air
(LNB dOFA), selective non-catalytic reduction (SNCR), and selective catalytic reduction
(SCR). LNB technology reduces the amount ofNO* produced by reducing the flame
temperature. The flame temperature is reduced by controlling the fuel and air mixing, which
creates a larger, branched flame. LNB ilOFA reduces NO" emissions by separating the
combustion air into primary and secondary flows. When the combustion air is separated, a more
complete burn occurs and forms Nz rather than NO*. With SNCR, an aqueous reagent, typically
either ammonia or ureao is injected into the hot flue gas. The reagent reacts with the NO* in the
gas to form Nz and water vapor. Similar to the SNCR technology, SCR technology uses
ammonia to reduce NO* to Nz and HzO. However, with SCR the NO* in the flue gas reacts with
the ammonia within a catalyst bed.
o Cost
The estimated capital costs, annual costs, and the cost effectiveness for the possible emission
control devices at the Dave Johnston Electric Generating Station are shown in Table 7.3.3-1.
The capital costs, which are expressed in terms of cost per MW size, were estimated based on a
cost estimate document produced by the EPA.4 The capital costs for the Dave Johnston boilers
had to be extrapolated from the cost estimate data provided by the EPA reference due to their
large size. To determine the annual costs for the control devices, the capital costs were
amortized over 20 years at an interest rate of 7Yo and then multiplied by a factor to account for
operation and maintenance (O&M) costs. While SCR is expected to be far more efficient in
controlling NO* emissions than LNB or LNB dOFA, the estimated capital and annual costs are
far higher than the costs associated with LNB or LNB WOFA. As shown in Table 7.3.3-1, NO*
4eea 12002;, EPA Air Pollution Control Cost Manual,6th ed.,EPAl452lB-02-001, U.S. EPA, Office of Air
Quality Planning and Standards, RTP, NC, Section 5 - SO2 and Acid Gas Controls, pp l-30 through l-42,
http ://www.epa. eov/ttncatc I /products.html#cccinfo.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 128 of206
ll8
reductions using LNB or LNB dOFA technology are far more cost effective than the SNCR and
SCR technologies.
Table 7.3.3-1. Estimated Costs of Potential Emission Control Devices for Two Boilers at
the Dave Johnston Electric Generation Station*
l'6d EdimctPs
Unit ID Control
Technology
Estimated
Control
Ffficienw loZ)
E$rmated
Capital Cost(s)Annual Cost ($/year)Cost Effectiveness ($/ton)
BW4l LNB
LNB w/OFA
SNCR
s,ap
5l
65
40
80
4,030,000
5,760,000
4, I 60,000
l 1.500.000
63 1,000
962,000
2.490.000
3.390.000
528
632
2,659
1.810
BW42 LNB
LNBilOFA
SNCR
SCR
5l
65
40
80
4,030,000
5.760.000
4, I 60,000
I 1.500_000
63 t.000
962,000
2,490,000
3_390.000
538
644
2,709
1.844*All values listed in Table 7.3.3-l were obtained tlom the EC/R Incorporated teport "Supplementary Intbrmation for
Four-Factor Analyses for Selected Individual Facilities in Wyoming" and is included in Chapter 7 of the Wyoming
TSD.
. Time Necessary for Compliance
EC/R estimated that it would take nearly five and a half years for NO* reduction strategies to
become effective. It was determined that roughly two years would be necessary for the State of
Wyoming to develop the necessary regulations to implement the selected control measures.
EC/R estimated that it would take up to a year for the source to secure the capital necessary to
purchase emission control devices. Based on estimates calculated by the Institute of Clean Air
Companies (ICAC), approximately l8 months would be required for a company to design,
fabricate, and install SCR or SNCR technology. Since there are two boilers being evaluated at
Dave Johnston, an additional year may be required for staging the installation process.
. Energy and Non-Air Quality Environmental Impacts
The energy required to operate the emission control devices, including electricity and steam, and
the waste produced by the emission control devices, such as solid waste and wastewater, are
shown in Table 7 .3.3-2. As illustrated by the values in Table 7 .3.3-2, none of the four
technologies are expected to produce solid waste or wastewater. However, it should be noted
that the SCR technology would periodically produce solid waste when the catalyst would need to
be changed. While LNB and LNB ilOFA do not require steam, both SNCR and SCR require
steam to operate. None of the technologies are expected to increase fuel consumption, though
LNB and LNB w/OFA may reduce the fuel consumption due to optimized fuel combustion. [n
addition, LNB and LNB ilOFA technologies need roughly l/6th the electricity required by
SNCR and l/1506 the electricity required by SCR.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 129 of206
l19
Table 7.3.3-2. Estimated Energy and Non-Air Environmental Impacts of Potential
Emission Control Devices for Two Boilers at the Dave Johnston Electric
Generation Station*
Enerw and Non-Air Pollution Imnacts
Unit tD Control
Technology
Estimated
Control
Efficienry {o/")
bleclrlcrty
Requirements
1kw)
steam
Requirements(lh/hr)
Solid Waste
Generated (ton/hr)
Wastewater Produced
(galimin)
BW4t I,NB
LNB WOFA
SNCR
SCR
5l
65
40
80
54
5.4
3t
825
N/A
N/A
439
527
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
BW42 LNB
LNB ilOFA
SNCR
SCR
5l
65
40
80
54
5.4
3l
825
N/A
N/A
431
517
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
All values listed in Table 7 .3 .3-2 were obtained from the EC/R Incorporated report "Supplementary Information for
Four-Factor Analyses tbr Selected Individual Facilities in Wyoming" and is included in Chapter 7 of the Wyoming
TSD.
o Remaining Life of the Boilers
The remaining life of the boilers at the Dave Johnston facility is not expected to have an impact
on the cost ofthe control technologies.
. Dave Johnston Boilers BW4l and BW42 Four Factor Analysis Conclusion
As discussed previously, the LNB and LNB w/OFA emission control technologies have a
relatively low cost effectiveness value when compared with the SCR and SNCR technologies.
While the LNB and LNB WOFA estimated control efficiencies are between fifteen and twenty-
nine percent lower than the SCR technology, the electricity requirements are far lower for LNB
and LNB w/OFA and neither requires steam. In addition SCR will produce solid waste every
time the catalyst must be replaced. Therefore, based on the relatively low cost effectiveness, the
reasonable control efficiency, possible reduction in fuel usage, low electricity requirements, and
the fact that solid waste and wastewater will not be produced, the LNB or LNB wiOFA seem to
be the most reasonable choice for the Dave Johnston Electric Generating Station boilers BW4l
and BW42 based on the four factor analysis. The implementation of new controltechnologies on
the two boilers are discussed in further detail in Chapter 8 (Section 8.3.4), Long-Term Strategy.
7.3.4 Mountain Cement Company, Laramie Plant
At the Mountain Cement Company, Laramie Plant, only one unit was selected for the four factor
analysis. The selected source, Cement Kiln #2, is a long dry kiln that can produce up to 1,500
tons of clinker per day.
Several options are available for the control of NO* emissions and include both combustion and
NO* removal controls. Combustion control options include direct-fired low NO* burners (LNB),
indirect-fired LNB, and the CemStar process. NO* removal control options include biosolid
injection, LoTO*rM, selective catalytic reduction (SCR), selective non-catalytic reduction
(SNCR), and NO*OUT. Low NO* burners, whether installed on direct or indirect-fired kilns,
reduce the flame turbulence, delay the fuel/air mixing, and establish fuel-rich zones for initial
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 130 of 206
120
combustion. These three factors contribute to a reduction in thermal NO* formation. The
CemStar process introduces a small amount of steel slag to the kiln feed, which helps reduce the
ki ln operating tem perature.
Biosolid injection uses wastewater treatment plant solids to reduce the kiln temperature required
to produce clinker. The LoTO* system (licensed by the BOC group), which injects ozone into
the kiln, oxidizes NO* and the resulting higher oxides of nitrogen are then removed by a wet
scrubber. SCR technology uses a catalyst such as titanium dioxide or vanadium pentoxide to
convert NO* to N2 and H2O. SNCR, while similar to SCR, uses ammonia or urea to reduce NO*
formation, but does not require a catalyst. NO*OUT is similar to SNCR and uses urea to convert
NO* to nitrate and oxygen, but also has a proprietary additive that allows for a wider temperature
range than the typical SNCR system.
o Cost
The estimated capital costs, annual costs, and the cost effectiveness for the possible emission
control devices compiled by EC/R for the Mountain Cement Company, Laramie Plant are shown
in Table ?.3.4-1. Two options, SCR and LoTO*rM have high control efficiencies that are
predicted to be over 80%. However, no cost data was available for the LoTO*ru system, making
it impossible to evaluate its viability at the Laramie facility. SCR, while an effective control
technology, has a cost effectiveness value that makes it cost prohibitive. Of the more cost
effective options, SNCR using either urea or ammonia appears to be the most reasonable. SNCR
provides a control efficiency similar to many of the other control technologies, but with a far
better cost effectiveness ratio.
Kiln at the Mountain Cement C Laramie Plant.'
*All values listed in Table 7.3.4-1 were obtained from the ECIR Incorporated report "supplementary Information for
Four-Factor Analyses for Selected Individual Facilities in Wyoming" and is included in Chapter 7 of the Wyoming
TSD.
o Time Necessary for Compliance
ECiR estimated that it could potentially take seven years to achieve emission reductions at the
Laramie facility. This estimate includes the two years that will be necessary for the State of
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 131 of206
Table 7.3.4-1. Estimated Costs of Potential Emission Control Devices for One Cement
)att
Cost Estimates
Unit ID Control Technology
ESllmaleo
Control
Efficiencv (%)
Pollutant
Controlled
ESumated
Capital Cost
rs)
Annual Cost
($/year)Cost Effectiveness ($/ton)
Kiln#2
LNB (indirect)
LNB (direct)
Biosolid Injection
NO.OU"t
CemSTAR
LoTO*'rM
SCR
SNCR (urea)
SNCR (ammonia)
30-40
40
50
35
20-60
80-90
80
35
35
NO-
826,000
2.460,000
474,000
960,000
Unknown
Unknown
27,042,000
Unknown
lJnknom
205,000
449,000
-t27,OO0
507,000
Unknown
Unknown
7,553,000
Unknown
Unknown
,568-4,9r0
I 3,853
t,124
8,023
Unknown
Unknown
82,535
1,223
1.223
Fabric Filter
llru F(P
99
95-98 PMro 5.261 .000
I 0 926 000
4,451 .000
6 475 000
262,489
441 156 - A'tO 292
Fabric Filter
Drv ESP 95-98 PMrs 5,261 ,000
I 0.926.000
4,451,000
6,47a Ofifi
647,472
I 242.915 - I 150 054
t2t
Wyoming to implement new regulations and the I year Mountain Cement will likely need to
obtain the necessary capital for the purchase of new emission control technology. However, the
total time necessary varies based on the control technology selected. For example, it is predicted
that one and a half years will be required to design, fabricate, and install SCR or SNCR
technology, while over two and a half years will be required to design, fabricate, and install
LoTO*rM technology.
. Energy and Non-Air Quality Environmental Impacts
Table 7 .3.4-2 details the energy requirements and waste produced by the potential emission
control devices. Energy requirements include direct electricity and steam requirements, but do
not include the energy required to produce the steam and electricity. None of the NO* control
technologies require additional fuel and some are even predicted to increase fuel efficiency. The
options that are expected to increase fuel effrciency are indirect and direct LNB, biosolid
injection, and CemSTAR. However, there is no data indicating the expected fuel efficiency
increase. Without adequate datq it is not possible to determine if the increase in fuel effrciency
is substantial and ifthere is any advantage to selecting an option that increases fuel efficiency
over an option that does not increase fuel efliciency.
Several of the NO* control technologies are expected to require electricity and include both
direct and indirect LNB, LoTO*rM, and SNCR using urea or ammonia. Many of the technologies
did not have sufficient data to quantifr the energy requirements. This made it difficult to
adequately evaluate the control options based on electricity requirements. However, some of the
NO* control technologies are not predicted to have electricity requirements, which could make
those options potentially more attractive. Those options include SCR, CemSTAR, NO*OUT,
and biosolid injection. None of the NO* control technologies are expected to require steam.
Only a few of the NO* control technologies are expected to produce waste, whether solid waste
or wastewater. LoTO* is expected to produce both solid waste and wastewater, but estimates on
the amount are not available at this time. Spent catalyst for SCR systems must be replaced
periodically, which becomes solid waste. [n addition, some fine particulate matter is produced
by SCR systems that must be collected by a fabric filter or dry electrostatic precipitator (ESP).
The particulate matter collected by a fabric filter or dry ESP must be disposed of as solid waste;
the presence of fine particles from the catalyst may require disposal as a hazardous waste.
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 132 of206
122
Energy and Non-Air Pollution Impacts
(Der ton ofemission reduced)
Unit
ID
Control
Technology
Potential
Emission
Reductions
(1000 tonVw)
Pollutant
Controlled
Additional
Fuel
Requirements(o/-\
Electricity
Requirements
(kw-h0
Steam
Requiremants
(lbftr)
Solid Waste
Generated
(ton/hr)
Wastewater
Produced
(gallmin)
Kiln
LNB (indirect)
LNB (direct)
Biosolid Injection
NO-OUT
CemSTAR
LoTO*rM
SCR
SNCR (urea)
SNCR (ammonia)
t57-210
210
262
183
I 05-314
419472
419
183
r83
NO,
a
a
a
b
a
b
b
b
b
lE2
182
b
b
b
c
b
d
d
b
b
b
b
b
b
b
b
b
b
b
b
b
b
d
b
b
b
b
b
b
b
d
b
b
b
Fabric Filter
Drv ESP
37
l5 PMro b
b
d
d
b
b
b
h
Pabric Frlter
Drv ESP
36-37
l4-ls PM::b
h
d
A
b
h
b
h
Table 7.3.4-2. Estimated Energy and Non-Air Environmental Impacts of Potential
Emission Control Devices for Kiln #2 atthe Mountain Cement Company,
Laramie Plant*
a - The control technology is expected to improve fuel efficiency.
b - Impact not expected.
c - Electricity requirements are expected to be high, but not enough data to quantifi.
d - Technology expected to have an impact, but insutficient data available to evaluate requirements.
e - Spent catalyst will have to be disposed of on occasion.
"All values listed in Table7.3.4-2 were obtained from the ECIR Incorporated report "Supplementary Information
for Four-Factor Analyses tbr Selected Individual Facilities in Wyoming" and is included in Chapter 7 of the
Wyoming TSD.
o Remaining Equipment Life
If Mountain Cement chooses to replace kiln#2, then the cost of the control technologies for the
currently operating kiln would likely be cost prohibitive.
If Mountain Cement decides not to replace kiln #2, then the remaining life of the kiln would
likely be indefinite. Under this scenario, the lifetime of the selected control technology could be
assumed to be equal to or less than the lifetime of the cement kiln. The capital cost of the control
technology would not have to be amortized over the kiln lifetime, thus eliminating the impact of
the remaining equipment life on the cost of the control technology.
The implementation of new control technologies on the cement kiln is discussed in Chapter 8
(Section 8.3.4), Long-Term Strategy.
7.3.5 Oil and Gas Exploration and Production Field Operations
Oil and gas production, which is not limited to just one area of Wyoming, is an important and
critical component of the state economy. Sources associated with oil and gas production emit
NO* and PM. Sources include turbines, diesel engines, glycol dehydrators, amine treatment
units, flares and incinerators.
Emissions from large stationary oil and gas sources in the WRAP region have been well
quantified over the years, while smaller field and production sources are not as well understood.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page '133 of 206
t23
To better understand the emissions from all oil and gas sources across the region, the WRAP
region instituted a three-phase emission inventory project. Phase [, which was completed in
2005, was an emission inventory project that estimated regional emissions from oil and gas field
operations for the first time. Phase II, completed in late 2007, was an effort to more fully
characterize the oil and gas field operations emissions. The WRAP inventory currently addresses
only large stationary sources and a consistent reporting system for oil and gas emissions for
WRAP member states has not yet been developed. Members of the Independent Petroleum
Association of Mountain States (IPAMS) felt that still more improvement in the accuracy of
these emission estimates was needed. So, in late 2007, TPAMS initiated a Phase III regional oil
and gas emission inventory project funded by their organization. The project was undertaken in
conjunction with the WRAP to assure that the products from Phase III were widely distributed
among non-industry stakeholders (state/local agencies, tribal air programs, Federal Land
Managers, environmental groups and EPA). Phase III results will not be ready for this SIP
review.
While inventory work has not been completed on the oil and gas industry, the WRAP did engage
EC/R to assist with the four factor analysis for oil and gas.
EC/R evaluated controltechnologies for common emission sources in the oil and gas industry:
reciprocating engines and turbines, process heaters, flares and incinerators, and sulfur recovery
units. For compressor engines and gas-fueled reciprocating engines, potential control options
presented by EC/R include air-fuel ratio controls (AFRC), ignition timing retard, low-emission
combustion (LEC) retrofit, selective catalyic reduction (SCR), selective non-catalytic reduction
(SNCR), and replacement with electric motors. LEC retrofit technology requires modification of
the combustion system to increase the air-to-fuel ratio, which creates very lean combustion
conditions. Currently in Wyoming, many of the rich-bum engines associated with compressor
stations utilize SNCR in conjunction with AFRC, while lean-bum engines often utilize an
oxidation catalyst to reduce emissions.
Regulating drill rig engines is problematic for states. Drill rig engines are, for the most part,
considered mobile sources and emission limits for mobile sources are set by the Federal
government under Section 202 of the CAA. Several control options exist and include ignition
timing retard, exhaust gas recirculation, SCR, replacement of Tier 2 engines with Tier 4 engines,
and diesel oxidation catalyst.
Other common oil and gas exploration and production equipment also have emission control
device options. Turbine emissions can be controlled by water or steam injection, low NO*
burners, SCR, and water or steam injection with SCR. NO* emission controltechnologies for
process heaters include LNB, ultra-low NO* burners (ULNB), LNB with flue gas recirculation
(FGR), SNCR, SCR, and LNB installed in conjunction with SCR. Glycol circulation rates on
glycol dehydrators can be optimized to reduce VOC emissions. Controlmeasures for flares,
incinerators, and sulfur recovery units evaluated by ECIR control only SO2 emissions and are not
addressed in this SIP.
NO* emissions vary based on the equipment and fuel source. Emissions from individual natural
gas-fired turbines at production operations can be as high as 877 tons of NO* per year (tpy),
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 134 of206
124
while emissions from individual natural gas turbines at exploration operations can reach l3 I tpy.
Individual gas reciprocating engines have comparable NO* emissions with up to 700 tpy at
production operations and 210 tpy at exploration operations. Diesel engine emissions can
approach 46 tpy for production operations and I 0 tpy for exploration operations.
o Cost
Table 7.3.5-l lists the various control technologies identified by EC/R for oil and gas field
operations. Both the capital and annual costs for each technology is dependent on the engine
size or on the process throughput. For several of the control technologies listed in Table 7.3.5-1,
cost estimate ranges are provided. The lower end of the cost estimates represent the cost per unit
for the larger units or higher production due to economy of scale, while the higher end of the cost
estimates represent the cost per unit for the smaller units or lower production.
Flares, incinerators, sulfur recovery units, and glycol dehydrators were not included because the
control technology evaluated by EC/R for those sources were only applicable for SO2 or VOCs,
which are not addressed by this SIP.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 135 of206
125
Cost Estimates
Source Type Control Technology
Estimated
Control
Ffficiencw /o/^l
Pollutant
Controlled
Estrmated
Capital Cost(S/unit)
Annual Cost
($&earlunit)Units
Cost
Effectiveness
(S/ton)
Compressor
Engines
Air-fuel ratio
control (AFRC)1040 NO*5.3 - 42 0.9-68 hp 68 - 2,500
Ignition timing
retard I 5-30 NO,N/A l-3 hp 42 - t,200
LEC retrofit 80-90 NO,120-820 30 - 210 hn 320 -2.500
SCR 90 NO.100-450 40 -270 hD 870 - 3 1.000
SNCR 90-99 NO"t7 -35 3-6 hD 16-36
Replacement with
electric motors
100
100
100
NO.
PM,n
PM,.
120 - 140 38-44 hp
100 - 4,700
>79,000
>79.000
Drilling Rig
Engines and
Other
Engines
Ignition timing
retard l5-30 NO.t6 - t20 t4-66 hp I,000 - 2,200
Exhaust gas
recirculation (EGR)40 NO"100 26-67 hp 780 - 2.000
SCR Pn-q5 NO-t00-2000 40 - I.200 ho 3000-7700
Replacement of
Tier 2 engines with
Tier 4
87
85
85
NO.
PMro
PM..
t25 20 hp
900 -2,400
25.000 - 68,000
25.000 - 68.000
Diesel oxidation
catalvst
25
25
PM',
PM,.l0 1.7 hp 1,400
Turbines
Water or steam
in ieciinn 68-80 NO.4.4 - t6 2-5 IOOO BTU 560 - 3,1 00
Low NO. burners(LNB)58-84 NO.I -22 2.7 -8.5 IOOO BTU 2,000 - 10,000
SCR 90 NO"t3-34 5l-13 IOOO BTU 1.000 - 6.700
Water or steam
iniection with SCR 93 -96 NO,t3-34 5 l - 13 IOOO BTU 1.000 - 6,700
Process
Heaters
LNB 40 NO"3 8-76 0.41 - 0 8l 1000 BT(J 2.1 00 - 2-800
Ultra-Low NO.
Bumers (ULNB)75-85 NO_40-13 043-t 3 t000 BTtl l, 500 - 2,000
LNB and FGR 48 NO l6 T7 I 000 BTll 2 600
SNCR 60 NO.to-22 t.t -2.4 IOOO BTU 4.700 - 5.200
SCR 70-90 NO"33-48 3.7 - 5.6 IOOO BTU 2900 - 6.?00
LNB and SCR /t, - 9{,NO.37-55 4-6.3 IOOO BTU 2.900 - 6.300
Table 7.3.5-1.Estimated Costs for Oil and Gas loration and Production
'All values listed in Table 7.3.5-l were summarized tiom the EC/R Incorporated report "Supplementary Intbrmation
for Four Factor Analyses by WRAP States" and is included in Chapter 7 of the Wyoming TSD.
Based on available State permitting data, some of the larger compressor engines in the state can
approach 2,900 hp, while coal bed methane engines can be as small as 98 hp. Some of the
emissions control technologies for compressor engines, such as SCR, can become quite costly
based on the horsepower (hp) of the engine. This also holds true for other oil and gas
exploration and production equipment depending on the engine size or production. Drilling rig
engines can range from 550 hp for dieselengines up to 2,1l9 hp for naturalgas engines, with
l,476hp engines common in the field. Turbines are generally around I l2 MMBtu/hr, though
turbines can be as small as 0.4 MMBtu/hr or as large as 380 MMBtu/hr. Process heaters in
Wyoming commonly range from 0.87 MMBtu/hr to 1.5 MMBtu/hr, with process heaters having
a throughput of 0.75 MMBtu/hr being common in the state.
In the case of compressor engines, many facilities throughout the state have already installed
control equipment. For lean burn engines, oxidation catalysts are commonly installed while
SNCR catalysts with AFRC are commonly installed for rich burn engines.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page '136 of 206
126
o Time Necessary for Compliance
EC/R predicted that up to two years would potentially be required for Wyoming to develop the
necessary regulations. It is estimated that companies would require a year to procure the
necessary capital to purchase the control equipment. The time required to design, fabricate, and
install control technologies vary based on the control technology selected and other factors. It is
predicted that l3 months would be required for the design, fabrication, and installation of SCR or
SNCR technology, though some regulators have found that the time required is closer to l8
months. If multiple sources at a facility are to be controlled, an additional l2 months may be
required for staging the installation process.
The implementation of new control technologies for oil and gas operations is discussed in further
detail in Chapter 8, Long-Term Strategy.
7.4 309 SIP and 309(9)
51.309(9) allows the State to demonstrate reasonable progress for Wyoming's seven Class I
areas by building upon and taking full credit for the strategies already adopted, and taking full
credit for the strategies already adopted for protecting the l6 Class I areas on the Colorado
Plateau with a primary emphasis on controlling SO2 and anthropogenic smoke. All of those
strategies have been submitted to EPA under a 309 SIP. Furthermore, those strategies have been
included in the WRAP regional modeling demonstration establishing expected visibility
conditions on the most impaired and least impaired days for all of Wyoming's Class I areas. A
comparative review of Wyoming SOz source impact on the Colorado Plateau Class I areas and
the Wyoming Class I areas shows that reductions in SOz have a much greater impact on
Wyoming Class I areas than those on the Colorado Plateau. This Plan, which is submitted under
309(9), contains many additional measures focused on controlling NO* and PM. The combined
SO2 control strategies of the 309 SIP and the 309(9) SIP, which have been modeled by the
WRAP, provide the basis for established reasonable progress goals in Wyoming's Class I areas.
7.5 Setting Reasonable Progress Goals
Under Section 308(d)(l) of the Regional Haze Rule, states must "establish goals (expressed in
deciviews) that provide for reasonable progress towards achieving natural visibility conditions"
for each Class I area of the state. These RPGs must provide for an improvement in visibility for
the most impaired visibility days, and ensure no degradation for the least impaired visibility days
over the same period. The RPCs are interim goals that represent incremental visibility
improvement over time, in this case out to the year 201 8, to be compared to the 201 8 Uniform
Rate of Progress (URP) glide slope. Based on the steps outlined in Section 7.2 and the Four-
Factor Analysis in Section 7.3, the Division has established RPGs for each of Wyoming's seven
Class I areas, as described below. These RPGs are based primarily on results of the CMAQ
modeling described in Section 5.1.2, and on the four-factor analysis on major source categories.
These goals do not reflect additional improvements in visibility from controls that were not
included in the 2018 WRAP modeling. [t would be difficult to set goals lower than the
anticipated target without additional modeling.
Exhibit No. 4
Case No. IPC-E-'|3-16
T. Harvey, IPC
Page '137 of 206
127
Table 7.5-l shows that for the20Yo best days, the RPGs show an improvement over baseline
conditions, and thus ensure no visibility degradation. For the 20oZ worst days, the RPGs are
short of the 2018 URP, but can be justified based on the demonstration provided in Section 7.6.
Table 7.5-1. Reasonable Progress Goals for 20Yo Worst Days and 207o Best Days for
w C lass I Areas
Baseline
Condition
(dv)
2018
Uniform
Progress
Goal
(dv)
2018
Reasonable
Progress
Goal
(dv)
Baseline
Condition
(dv)
2018
Reasonable
Progress
Goal
(dv)
Yellowstone National Park
Grand Teton National Park
Teton Wilderness
ll.8 r0.5 Lt.2 2.6 2-4
North Absaroka Wilderness
Washakie Wilderness I1.5 10.4 I1.0 2.0 2.0
Bridger Wilderness
Fitzoatrick Wilderness I l.l 10.0 10.6 2.1 2.0
(WRAP TS S - http ://v i sta. cira. co lostate. edu/tssO
7.6 Demonstration That the RPGs for 20 Percent Best and Worst Days are Reasonable
EPA guidance indicates that "States may establish an RPG that provides for greater, lesser or
equivalent visibility improvement as that described by the glidepath." The 2018 RPGs identified
in Table 7.5-l for 20 percent worst days show an improvement in visibility, although less than
the 2018 URP. The Division believes that RPGs are reasonable based on the following factors:
t.Emissions from natural sources greatly affect the State's ability to meet the 2018
deciview URP goal. The analysis in Chapters 4 and 5 ofthis Plan containing summaries
of emissions data, source apportionment, and modeling shows the contribution from
natural or nonanthropogenic sources, such as natural wildfire and windblown dust is the
primary reason for not achieving the 2018 URP in Wyoming's Class I areas. The State
has little or no control over OC, EC, PM2 5, coarse PM and soil emissions associated with
natural fire and windblown dust. Prolonged droughts in the West have resulted in
extensive wildfires and increased dust emissions. The idea of seffing deciview URP
goals was developed before the causes of haze in the West were well understood. The
extensive technical analysis of the causes of haze conducted by the WRAP has led to a
better understanding of the role of wildfire and dust in visibility impairment. As long as
there are wildfires in the Western United States, there will be significant impact to
visibility in Class I areas and there is little states can do about it.
Emissions from sources outside the WRAP modeling domain (intemational emissions)
also affect the State's ability to meet the 2018 URP goal. The analysis in Chapter 5 of
this Plan containing monitoring and modeling results shows the emissions from
intemational sources are a significant contributor to sulfate and nitrate concentrations at
the monitors in most Western Class I areas, including those in Wyoming. The State has
little or no control over emissions coming from other countries in the world.
)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page '138 of 206
128
Major reductions in SOz emissions established in the previously submiffed Wyoming 309
SIP demonstrate the State's commitment to reducing visibility impairment. Tremendous
progress has already been made toward capping and controlling SO2 emissions from
major point sources from the four states that have elected to participate in the Western
Backstop Trading Program, including Wyoming.
The largest point source category of NO* emissions is coal-fired power plants. In
Wyoming, significant reductions from these plants will be achieved through the
implementation of BART levels established in this Plan, as well as additional reductions
committed to in the long-term strategy.
The second largest category of stationary sources in the West is oil and gas development
and production. Increased oil and gas development is expected in many areas of the
West, due in large part to increased leasing to oil and gas operators on Federal land. The
WRAP has developed the first comprehensive oil and gas inventory in the Western
United States, and many states are moving forward with evaluating control options.
Wyoming is evaluating and testing many of the control strategies, but the specific
strategies are not ready for incorporation into this first round of regional haze SIPs.
Control options for ozone are being evaluated simultaneously and the State believes that
many co-benefits from controlling emissions for ozone will be realized under the regional
haze program. Numerous additional emission reductions from oil and gas are expected
over the next ten-year period.
Wyoming Class I areas have some of the cleanest air in the United States. The haziest
days in Wyoming generally have the same level of visibility impairment as the clearest
days in the Eastern United States. Monitors at visibility sites in Wyoming Class I areas
show fine particle loadings that are a fraction of those in the East, and Rayleigh, or
natural light scattering, dominates the clearest days in the West. Therefore, it is more
difficult to show improvement in visibility over time in Wyoming than it is in an Eastem
state because the state is starting out so clean.
Wyoming is not alone in setting reasonable progress goals which do not achieve the
uniform rate of progress. The vast majority of sites in the Western United States will not
come close to URP goals primarily because controllable emissions are only a small
fraction of the total contribution to visibility impairment in the Western Class I areas.s
Reasonable progress goals in Wyoming have been based on the control strategies of two
major State Implementation Plans - 309 and 309(9). Major work undertaken by the State
of Wyoming along with three other Westem states and one local entity to cap and reduce
SOz emissions represents major progress towards controlling SO2. Capping and reducing
SOz from all of Wyoming's 100-ton sources has a bigger impact on nearby Wyoming
Class I areas than Class I areas on the Colorado Plateau. The 309 program provides a
declining cap for all non-BART 100-ton SO2 sources through 2018. Visibility
t Sou.ce Contributions to Visibility Impairment in the Southeastern and Western United States (Patricia Brewer and
Tom Moore)
3.
4.
5.
7.
8.
6.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 139 of206
t29
improvement, as it relates to sulfate extinction, has been demonstrated at all of
Wyoming's Class I areas as a result of the application of the 309 program. This visibility
information is shown in Chapter 6 of this SIP in Table 6.2-2. Additional work completed
for the 309(9) requirements, which is spelled out in great detail in this SIP, provides still
further improvement.
9. Wyoming air quality monitoring for visibility pollutants has not shown a trend toward
degraded visibility resulting from anthropogenic sources thus far, in spite of industrial
growth. Time series plots of individual chemical species measured for visibility on the
worst days are shown below. While organic carbon measurements (primarily from forest
fires) show a high degree of variability from year to year, sulfates and nitrates (primarily
from anthropogenic sources) have not shown a significant degree of variation over time.
Figure 7.6-1. Time Series Plot by Pollutanton20oh Worst Days for Yellowstone NP,
Grand Teton NP. and Teton Wilderness Area
(WRAP TSS -
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey,IPC
Page 140 of206
130
Figure 7.6-2. Time Series Plot by Pollutant on 20oh Worst Days for North Absaroka and
Washakie Wilderness Areas
Figure 7.6-3. Time Series Plot by Pollutant on20Yo Worst Days for Bridger and
Fitzpatrick Wilderness Areas
Monitoring Data for Worst 20% Visibilrty Days
Class I Areas - Norh Abgamka W. WY: Washakie l{. tlY
200
18.0
16.0
t{0
- 12.0
AI 100
8.0
6.0
10
2i
00
--. *.-. - ** ffinmrrnB-a&E i
rr Sffftlhdim
.+l{C3BlirEtin
*oilcEffiiort
*ECffidin
+Sfllhd['!E&n
-ClilEffin
(WRAP TS S - http ://vi sta.cira.colostate.edu/tssA
Monibring Data for Worst 20% Visibilrty Dq/s
,t10
12.0
10ll
: 8.0tsE
6.0
I S04tutrEtiut
+NO3Effiim
+OrlCEdirction
+ECEdMion
+SoilExthstion
*CHEnhdin
1.0
2.0
0.0 otOOOFNOt60000c,000ooooooooofFNNNNN
(WRAP TS S - http ://vi sta.cira.co lostate.edu/tssA
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 141 of206
l3r
CHAPTER 8
LONG.TERM STRATEGY
8.1 Overview
The RegionalHaze Rule requires states to submit a l0-15 year long-term strategy (LTS) to
address regional haze visibility impairment in each Class I area in the state, and for each Class I
area outside the state which may be affected by emissions from the state. The LTS must include
enforceable measures necessary to achieve reasonable progress goals, and identiff all
anthropogenic sources of visibility impairment considered by the state in developing the long-
term strategy. Where the state contributes to Class I visibility impairment in other states it must
consult with those states and develop coordinated emission management strategies, and
demonstrate it has included all measures necessary to obtain its share of the emission reductions.
If the state has participated in a regionalplanning process, the state must include measures
needed to achieve its obligations agreed upon through that process.
8.1.1 Summary of all Anthropogenic Sources of Visibility Impairment Considered in
Developing the Long-Term Strategy
Section 51.308(dx3)(iv) of the Regional Haze Rule requires the identification of "all
anthropogenic sources of visibility impairment considered by the State when developing its long-
term strategy." Chapter 4 of this Plan describes Wyoming statewide emissions, including
projections of emissions reductions from anthropogenic sources from 2002 to 2018. Chapter 5
ofthis Plan provides source apportionment results, including projected reductions from
anthropogenic sources during the same period. Chapter 5 addresses anthropogenic sources from
all potential sources in the world. Chapter 7 includes the results of a screening analysis which
identifies the major anthropogenic sources in the State of Wyoming. Together, these three
chapters show the major anthropogenic sources affecting regional haze in Wyoming and in the
West. Chapter 7 further describes the major anthropogenic source categories evaluated through
the four-factor analysis.
8.1.2 Summary of Interstate Transport and Contribution
Sections 51.308(dx3)(i) and (ii) of the Regional Haze Rule requires that the Long-Term Strategy
address the contribution of interstate transport of haze pollutants between states. Chapter 4 of
this Plan illustrated Wyoming statewide emissions, while Chapter 5 identified interstate transport
of pollutants and larger source categories based on source apportionment results.
8.1.2.1 Other States' Class I Areas Affected by Wyoming Emissions
Wyoming used baseline period visibility data from the IMPROVE monitors along with the
WRAP baseline modeling results to estimate Wyoming's emissions impact on neighboring
states' Class I areas (see Figure 8.1 .2.1-l ). Wyoming focused on anthropogenic emissions
transported to other states, primarily sulfates and nitrates.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 142 of 206
t32
Wyoming, South Dakota, Montah?, Idaho,
Utah, North Dakota and Colorado Class I Areas
. Lostwood National Wildlife RefJpe
Reruse North Dakota
\\r Theodore Roosevelt National Park \\
Northem Cheyenne lndian
;
,_l
(
South Dakota
,;*.Padlands NP
-_r..,._... .... -... .... Irildamacc LMountWildemess1 Rawah Wildemess
Flat Tops
$ nocty Mountain NP iil
\ EaSles NestWildemess
]
d Maroon Bells-snowmass Wildem{ss
o t W""t Elk Wilderness
Black Canyon of the Gunnisonr La Garita Wildemess :| , Great Sand Dunes NP i
Weminuche Wilderness i
Mesa Verde NP Coloradol
Figure 8.1 .2.1-1
r Gates of the Mountains Wildemess
jl Anaconda Pintler Wildemess
.\
I
\
\
\
i(
l)
--s
f= -.-..---,_!t, i GlacierCabinet Moufiiains / IWildernesq ( 1'\/\Mission Mountains W\emess
/ '..
Itr t! Red Rock Lakes^ E - ---
Sawtoothtildemess YellowstoneNP tt
Grand r"ron Np
f ,I#:::lY:::*' cr"no r"ton Nef fillffashak.wirdemess.q l* Teton Wilderness (Red)
craters of the Moon NM / t FiEpatrick wildemess
BridgerWildem""t \1__=-l Wyomingt'I,l
I;iI L_-
capitotReerNP
\ "*1,""J. *,
.s f \.
,Zion National'Park tq 'Bryce Canyon ttationaj pa*
:
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page '143 of 206
133
In the table below, the first column shows the contribution of nitrates to visibility impairment at
surrounding Class I areas calculated from the IMPROVE monitoring data measured during the
baseline period to provide perspective on the role of nitrates to overall impairment. The second
column shows Wyoming's contribution to particle mass calculated from the modeled
concentrations of nitrate for the baseline years. The table below illustrates two things: l) the
role of nitrates in visibility impairment at the Class I are4 and 2) the probable share of Wyoming
emissions contributing to the pollutant species.
Table 8.1.2.1-1. Nitrate Contribution to Haze in Baseline Years
When modeled, Wyoming NO* emissions contribute up to l8 percent of the nitrate
concentrations at some neighboring states on worst days. As shown in the above table, however,
nitrate contributes only l4 percent of the visibility impairment at the corresponding nearest Class
I areas in neighboring states. Hence, only a small portion of out-oGstate visibility degradation is
due to nitrate formed from Wyoming emissions. By 2018, NO* emissions from Wyoming are
projected by the WRAP to decrease by 39,861 tons, which will help reduce Wyoming's impact
to out of state Class I areas.
Exhibit No. 4
Case No. IPC-E-'|3-16
T. Harvey, IPC
Page 144 of 206
State and Mandatory Class I Area
2000-2004
Average Annual Nitrate
Share of Particle Light
Extinction
(measured values)
2000-2004
Wyoming's Average
Annual Share of Nitrate
Concentration
(based on modelins)
Worst Davs Best Davs Worst Davs Best Davs
South Dakota
Wind Cave National Park l4Yo 5o/o t8%34Y.
Badlands National Park r0%6v,l2Yo 34%
Colorado
Mount ZirkellRawah Wildemess*7%4o/o l0o/o LYo
Rocky Mountain National Park t3%3%l0o/o 80/o
Utah
Arches/Canvonlands National Park*9Yo 4v,2%3Yo
Idaho
Craters of the Moon National Monument 27o/o 8%3%<lYo
Montana
Anaconda-Pintler/Se lwav-B itterroot*3Yo 3%3%<lYo
Gates of the Mountains Wilderness 6%4%2%<lYo
North Dakota
Theodore Roosevelt National Park 22o/o 7o/o 4Vo 7%
Lostwood National Wildlife Refuse 3t%8%3%2%
*These Class I areas share one monitor.
134
Table 8.1.2.1-2. Sulfate Contribution to Haze in Baseline Years
State and Mandatory Class I Area
2000-2004
Average Annual Sulfate
Share of Particle Light
Extinction
(measured values)
2000-2004
Wyoming's Average
Annual Share of Sulfate
Concentration
(based on modelins)
Worst Davs Best Davs Worst Days Best Davs
South Dakota
Wind Cave NationalPark 26%t5%tt%22%
Badlands National Park 33o/o t7%6%20%
Colorado
Mount ZirkellRawah Wildemess*t7%t3%7%t2%
Rockv Mountain National Park l9%lt%5%10%
Utah
Arches/Canvon lands National Park*t8%t5%3%8%
ldaho
Craters of the Moon National Monument t4%t0%2o/o t%
Montana
Anaconda-Pintl erlSelwav-B itterroot*n%8%2%<lYo
Gates of the Mountains Wildemess t7%8%t%<lYo
North Dakota
Theodore Roosevelt National Park 28o/o l7o/o 2%lo/o
Lostwood National Wildlife Refuee 29o/o l9Yo lYo <lYo
* These Class I areas share one monitor.
When modeled, Wyoming sulfate emissions contribute up to I I percent of the sulfate
concentrations at some neighboring states on worst days. As shown in the above table, sulfate
contributes 26 percent of the visibility impairment at the corresponding nearest Class I areas in
neighboring states. By 2018, SOz emissions from Wyoming are projected by the WRAP to
decrease by 22,794 tons, which will help reduce Wyoming's impact on out of state Class I areas.
8.1.2.2 Wyoming Class I Areas Affected by Other States, Nations and Areas of the World
The contribution of neighboring states of South Dakota, Colorado, Utah, Idaho and Montana to
Wyoming Class I areas was examined to determine where significant emissions might be coming
from. In the case of both nitrates and sulfates on best and worst days, the most significant
impacts on all Wyoming Class I areas came from sources outside the modeling domain. These
would be emissions from other parts ofthe world. This review has focused on nitrates and
sulfates since those emissions tend to focus on anthropogenic sources. Data for this impact
analysis comes from the PSAT runs performed by the WRAP and documented in the TSS.
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Yellowstone National Park. Grand Teton National Park. and Teton Wilderness Area
o Sulfates
On the best days in the baseline years, 50 percent of the sulfates come from sources outside of
the modeling domain. The next largest contribution of sulfates comes from Idaho showing a l4
percent contribution to sulfate extinction in the baseline years. Sulfates, overall, contribute
ll%oto visibility impairment in these Class I areas on the best days. Similarly, on the worst
days, most of the impact (47%) comes from sources outside the modeling domain. The next
largest contribution is from Idaho showing an eight percent contribution to sulfate extinction in
the baseline years. Sulfates, overall, contribute l2Yoto visibility impairment in these Class I
areas on the worst days. Other states surrounding Wyoming showed smaller contributions (less
than five percent). Canadian impacts were between six and nine percent on the worst and best
days, respectively. Wyoming has worked with ldaho through the WRAP process and believes
that Idaho is working to reduce sulfate impacts to these Class I areas. Idaho is projected by the
WRAP to reduce sulfate related emissions by 13,272 tons by 2018.
o Nitrates
On the best days in the baseline years, 25 percent of the nitrates come from sources outside the
modeling domain. 22 percent is attributed to ldaho and approximately 14 percent to Utah. Other
states surrounding Wyoming, and including Wyoming, showed less than five percent impact.
Overall impact of nitrates on visibility impairment on the best days is six percent in these Class I
areas. On the worst days in the baseline years, 3l percent of the nitrates come from sources
outside of the modeling domain , and 28 percent is attributed to Idaho sources. Other states
surrounding Wyoming, and including Wyoming, showed impacts between zero and eight
percent. Overall impacts from nitrates on worst days in these Class I areas is five percent.
Wyoming has worked with both ldaho and Utah through the WRAP process and believes that
both states are working to reduce nitrate impacts to these Class I areas. Idaho is projected by the
WRAP to reduce nitrate causing emissions by 32,418 tons by 2018 and Utah is projected by the
WRAP to reduce nitrate causing emissions by 71,678 tons by 2018.
Bridger and Fitzpatrick Wilderness Areas
o Sulfates
On the best days in the baseline years, 56 percent of the sulfates come from sources outside of
the modeling domain. The next largest contribution of sulfates comes from Idaho, showing an
l8 percent contribution to sulfate extinction in the baseline years. Other states, including
Wyoming, show less than nine percent contribution. Sulfates, overall, contribute l2%o to
visibility impairment in these Class I areas on the best days. Similarly, on the worst days, most
of the impact (31%) comes from sources outside the modeling domain. The next largest
contribution is from Wyoming, showing a l5 percent impact to sulfate extinction in the baseline
years. Other states in the region showed less than eight percent impact. Sulfates, overall,
contribute 160/oto visibility impairment in these Class I areas on the worst days. Wyoming has
worked with Idaho through the WRAP process and believes that Idaho is working to reduce
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sulfate impacts to these Class I areas. Idaho is projected by the WRAP to reduce sulfate related
emissions by 13,272 tons by 2018. Emission reductions from Wyoming sources are addressed
through the 309 SIP, previously submitted to EPA.
o Nitrates
On the best days in the baseline years, 30 percent of the nitrates come from sources outside the
modeling domain. 24 percent is affributed to Utah and approximately l5 percent to Idaho. Other
states surrounding Wyoming, and including Wyoming, showed less than nine percent impact.
Overall impact of nitrates on visibility impairment on the best days is three percent in these Class
I areas. On the worst days in the baseline years, 22 percent of the nitrates come from sources
outside of the modeling domain, and l9 percent is attributed to Wyoming. Utah and Idaho are
estimated to contribute l6 and I I percent, respectively. Other states surrounding Wyoming
showed impacts between one and seven percent. Overall impacts from nitrates on worst days in
these Class I areas is five percent. Wyoming has worked with both Idaho and Utah through the
WRAP process and believes that both states are working to reduce nitrate impacts to these Class
I areas. Idaho is projected by the WRAP to reduce nitrate causing emissions by 32,418 tons by
2018 and Utah is projected by the WRAP to reduce nitrate causing emissions by 71,678 tons by
2018. Wyoming is committed to reducing projected WRAP emissions by at least 39,861 tons by
2018.
North Absaroka and Washakie Wilderness Areas
o Sulfates
On the best days in the baseline years, 50 percent of the sulfates come from sources outside of
the modeling domain. The next largest contribution of sulfates comes from Canada, showing an
l8 percent contribution to sulfate extinction in the baseline years. Other states, including
Wyoming, show less than ten percent contribution. Sulfates, overall, contribute nine percent to
visibility impairment in these Class I areas on the best days. Similarly, on the worst days, most
of the impact (50%) comes from sources outside the modeling domain. The next largest
contribution is from Canada, showing a l3 percent contribution to sulfate extinction in the
baseline years. States in the region showed less than seven percent impact. Sulfates, overall,
contribute l5Yoto visibility impairment in these Class I areas on the worst days. EPA is working
with Canadian officials to develop cooperative strategies for reducing sulfate emissions from
Canada and the U.S.
o Nitrates
On the best days in the baseline years, 29 percent of the nitrates come from sources outside the
modeling domain. 14 percent is attributed to Idaho, l3 percent to Canada, and approximately I I
percent from Utah. Other states surrounding Wyoming, and including Wyoming, showed less
than seven percent impact. Overall impact of nitrates on visibility impairment on the best days is
three percent in these Class I areas. On the worst days in the baseline years, 3l percent of the
nitrates come from sources outside of the modeling domain, and 17 percent is attributed to Idaho.
Montana and Canada are estimated to contribute l5 and 12 percent, respectively. Other states
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surounding Wyoming showed impacts between zero and five percent. Overall impacts from
nitrates on worst days in these Class I areas is five percent. Wyoming has worked with Idaho
through the WRAP process and believes that Idaho is working to reduce nitrate impacts to these
Class I areas. Idaho is projected to reduce nitrate causing emissions by 32,418 tons by 2018.
Montana's emissions are being addressed by EPA through a Federal Implementation Plan, and
nitrate emissions are projected to decrease by 63,099 tons by 2018. EPA is also working with
Canadian officials to develop cooperative strategies for reducing nitrate emissions from Canada
and the U.S.
The Division consulted with neighboring states as part of this review, and discussed the need for
coordinated strategies to address interstate transport. Based on this consultation, no significant
contributions were identified that supported developing new interstate strategies. Both Wyoming
and neighboring states agreed that the implementation of BART and other existing measures in
state regionalhaze plans were sufficient to address the contributions discussed below. This
interstate consultation is an on-going process and continuing commitment between states. See
Chapter I I for further information.
8.1.3 Summary of Interstate Consultation
In addition to evaluating interstate transport, the affected states are required to consult with each
other under Section 51.308(d)(3)(i), in order to develop coordinated emission management
strategies. See Section I I .l for information on the state-to-state consultation process.
8.1.4 Estimated International and Global Contribution to Wyoming Class I Areas
Although not specifically addressed under the RegionalHaze Rule in terms of interstate
transport, it is important to identiff the contribution to visibility impairment in Wyoming from
international sources, such as Canada and Mexico, offshore marine shipping in the Pacific
Ocean, and "global" sources of haze. The PSAT and WEP results in Chapter 5 describe the
amount of contribution to visibility impairment in Wyoming from Canada, Mexico, offshore
marine shipping in the Pacific and general global or "outside domain" sources. Because the
State of Wyoming does not have any authority over any ofthe above-mentioned intemational
sources, the Division is not pursuing any new strategy for haze impacts due to international
sources.
The following text was extracted from EPA responses to state questions posed by the WRAP
Implementation Work Group in March 2007:
The U.S. and Canada have been working on addressing transboundary emissions issues through
the bilateral l99l Canada-United States Air Quality Agreement. Information, including progress
reports and articles, on this agreement can be found at
http://www.epa.sov/airmarkets/resource/usaqa-resource.html. Under the agreement, Canada and
the United States have looked at addressing transboundary air pollution, namely, acid rain and
ground-level ozone. Over the last two years, Canada and the United States have continued to
successfully reduce their emissions of sulfur dioxide (SOz) and nitrogen oxides (NOJ, the major
contributors to acid rain and also to regional haze. Both countries have also made considerable
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progress in meeting the requirements of the Ozone Annex to reduce emissions of NO* and
volatile organic compounds (VOCs), the precursors to ground-level ozone. Canada and the
United States have focused their actions on reducing these emissions from major sources such as
electric generating units, industrial sources, and on-road and nonroad transportation.
This Agreement has provided important opportunities for collaboration between Canada and the
United States and has produced impressive results, not just in environmental improvements, but
also in diplomacy and working relationships. Both countries rely on the Agreement as the
mechanism to address air pollution issues and are committed to its continuing viability and
relevance as new bilateral issues emerge. The Agreement's flexibility provides opportunities to
go beyond the challenges identified by the Acid Rain and Ozone annexes, and the Parties look
forward to considering whether and how to address bilateral issues associated with particulate
matter, mercury, and other air pollutants.
EPA Region l0 has been meeting with their counterparts in the British Columbia Ministry of
Environment for the past five years to identifr air quality issues in the Georgia-Basin-Puget
Sound Airshed, and to develop an Intemational Airshed Strategy (IAS) to address these issues.
The IAS includes protection of visibility as a goal, and the Canadian-United States Air Quality
Agreement also addresses visibility. At the most recent IAS meeting in January 2007, the air
program director of the BC Ministry of Environment gave a presentation on the process for
developing a visibility rule in BC. This rule would be the first of its type in Canada and could be
a model for the rest of Canada. This BC visibility rule would establish a visibility management
framework and identiff policies needed to achieve visibility protection. A Discussion Paper is
being developed on this topic and will be the focus of a workshop this spring with
representatives from Canadian air quality agencies, Canadian Tourism, Parks (National and
Provincial), Forestry, U.S. EPA, Washington Dept. of Ecology, and U.S. National Park Service.
The relationship between the air quality improvement programs in Mexico and the United States
received formal recognition through the Agreement between the United States and Mexico for
Cooperation on the Environment on the U.S.-Mexico Border (the La Paz Agreement of 1983).
This recognition provided the authority for EPA and Mexico's Environmental Ministry to
conduct cooperative activities to reduce air pollution. In September 1989 the two countries
signed Annex V to the LaPaz Agreement through which they agreed to cooperatively monitor
air quality in sister cities along the U.S.-Mexico border; Annex V was formally expanded in
1996. In February 1992,the environmental authorities of both Federal governments released the
Integrated Border Environmental Planfor the U.S.-Mexico Area (IBEP). The IBEP, a two-year
plan, was the first bi-national Federal initiative created under the assumption that increased
liberalization of trade would place additional stress on the environment and human health along
the border. The Border XXI Program was initiated in 1996 to build on the experiences of and
improve the specific efforts undertaken under the IBEP and earlier environmental agreements.
Pursuant to the LaPaz Agreement of 1983, the Administrator of the U.S. Environmental
Protection Agency (U.S. EPA) and the Secretary of the Secretariat for the Environment and
Natural Resources (SEMARNAT) agreed on October 2001 to work jointly with the ten border
states and the U.S. border tribes to develop a new bi-national ten year plan to improve the
environment and reduce the highest public health risks on the U.S.-Mexico border. On April 4,
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2003, the representatives of the U.S. EPA, the Secretary of the Secretariat for the Environment
and Natural Resources (SEMARNAT), the ten Border States, and the 26 U.S. Tribes, met in
Tijuana, Baja California, Mexico to mark the beginning of a ten year joint effort, the Border
2012: U.S.-Mexico Environmental Program replacing the Border XXI Program.
The United States and Mexico, in partnership with border tribal, state, and local governments,
have worked to increase the knowledge about air pollution sources and their impacts on both
sides of the border, establish monitoring networks in several key areas, conduct emissions
inventories, and build local capacity through training.
Pollutants from a number of sources including motor vehicles, power plants and industrial
facilities, agricultural operations, mining, dust from unpaved roads, and open buming have
affected urban and regional air quality along the U.S.-Mexico border. The most common and
damaging pollutants from these sources include sulfur dioxide, suspended particulate matter
(PMto and PM2 5), nitrogen dioxide, ground-level ozone, and carbon monoxide.
To provide technical assistance about air quality planning and management to government,
academia, industry, and the general public in the border region, the U.S. and Mexico established
the Centro de Informacion sobre Contaminacion de Aire (CICA, or Border Information Center
on Air Pollution). The CICA Program, which is implemented by the Clean Air Technology
Center of EPA's Oflice of Air Quality Planning and Standards, has established a website at
http ://www.epa. sov/ttn/catc/cica.
The Big Bend Regional Aerosol and Visibility Observational (BRAVO) Study was conducted to
quantifr the contribution to visibility degradation at Big Bend National Park (BBNP) from
various air pollution source regions and source types in the U.S. and Mexico. The study
included evaluation of the impacts from the Carbon l-2 power plants in Coahuila, l8 miles from
the U.S. border. Findings from the BRAVO study can be found at
http ://www2.nature.nps. gov/airlstudies/bravo/index.htm.
Beginning in 2003 an effort was undertaken to understand better the smoke/haze from spring
burning in CentralAmerica/Mexico, which prompted State Department of Health alerts for up to
70Yo of the population of Texas on some days. Components of this effort include an ambient
study of particle chemical constituents to determine the sources of haze; remote sensing analysis
to evaluate locations of the burning and to assess the potential seriousness of such burning to
transport of particles in Texas; and on-the-ground assessment of ways to fight the fires and
mitigate damage.
Under the Border 2012 Program bi-national efforts have continued with the transfer of the
northern Baja California network to the State of Baja California, update of existing emissions
inventories, and the completion of the first Mexico National Emissions lnventory.
Additionally, the United States and Mexico in partnership with border tribal, state, and local
governments, are working together on projects such as retrofitting diesel trucks and school buses
with either diesel oxidation catalysts or diesel particulate filters to operate on ultra low sulfur
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diesel fuel, constructing "lower polluting" or "environmentally friendly" brick kilns, and road
paving to reduce the levels of particulate matter in the border region.
8.2 Required Factors for the Long-Term Strategy
As required in Section 5l.308(dx3)(v) of the Regional Haze Rule, the State must consider, at. a
minimum, the following factors: l) emission reductions due to ongoing air pollution control
programs; 2) measures to mitigate the impacts of construction activities; 3) emission limitations
and schedules for compliance; 4) source retirement and replacement schedules; 5) smoke
management techniques for agricultural and forestry burning; 6) the enforceability of emission
limitations and control measures; and 7) the anticipated net effect on visibility over the period of
the long-term strategy. These factors are discussed in the following pages along with all
measures to mitigate the impacts of anthropogenic sources. The seventh factor is discussed at
the end of the Long-Term Strategy Chapter.
8.2.1 Emission Reductions Due to Ongoing Air Pollution Control Programs
The following summary describes ongoing programs and regulations in Wyoming that directly
protect visibility, or can be expected to improve visibility in Wyoming Class I areas, by reducing
emissions in general. This summary does not attempt to estimate the actual improvements in
visibility that will occur, as many of the benefits are secondary to the primary air pollution
objective of these programs/rules, and consequently would be extremely difficult to quantiff due
to the technical complexity and limitations in current assessment techniques.
8.2.1.1 New Source Review Program
The New Source Review (NSR) Program is a permit program for the construction of new
sources and modification of existing sources as established by WAQSR Chapter 6, Section 2,
Permit requirements for construction. modification and ooeration and Chapter 6, Section 4,
Prevention of significant deterioration. Section 2 of Chapter 6 first became a State rule in 1974,
with the most recent revision being in March of 2000. Section 2 was submitted to EPA on
September 12,2003, approved by EPA on July 28,2004, and became effective on August 27,
2004. The primary purpose of the NSR Program is to assure compliance with ambient standards
set to protect public health, assure that Best Available Control Technology (BACT) is utilized to
reduce and eliminate air pollution emissions, and to prevent deterioration of clean air areas. Any
amount of air contaminant emissions from a facility subjects it to Wyoming's NSR Program.
8.2.1.1.1 Prevention of Significant Deterioration (PSD) Program
Generally, Wyoming considers its Prevention of Significant Deterioration (PSD) program as
being protective of visibility impairment from proposed major stationary sources or major
modifications to existing facilities. Wyoming has a fully-approved PSD program, and has
successfully implemented this program for many years. Wyoming's PSD rules (Chapter 6,
Section 4, of the Wyoming Air Quality Standards and Regulations (WAQSR)) were revised
effective October 6,2006, to conform with FederalNSR Reform rules. These changes were
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submitted to EPA on December 13,2006, approved by EPA on July 16, 2008, and became
effective on August 15,2008.
8.2.1.1.2 Minor Source BACT Program
The BACT process is most appropriately defined as the elimination of pollutants from being
emitted into the air whenever technically and economically feasible to do so. For example, by
application of minor source BACT, the Division has required controls ofNO* and formaldehyde
in coal bed methane (CBM) development and controls of NO*, VOC and Hazardous Air
Pollutant (HAP) emissions in oil and gas production development. The Division takes the State-
required BACT review in minor source permitting actions very seriously, as the bulk of the
Division's workload is made up of minor sources.
The Division will continue to review BACT considerations on each source type and size on a
case-by-case basis with consideration to the technical practicability and economic reasonableness
of eliminating or reducing the emissions from the proposed facility. The application of BACT in
the minor source permitting program has resulted in minimized emissions in the state as a whole
and will continue to do so as the Division continues to receive NSR permit applications for new
and modified sources.
8.2.1.2 Title V Operating Permit Program
As required by Title V of the Clean Air Act Amendments of 1990 and the implementing
regulations in 40 CFR part70, Wyoming established an Operating Permit Program under
Chapter 6, Section 3 of the WAQSR. Wyoming's proposed program was submitted to the
Environmental Protection Agency (EPA) for approval on November 22, 1993. Notice of Interim
Approval was published in the Federal Register on January 19, 1995. Final EPA approval of the
Wyoming Operating Permit Program was published on February 22,1999, and the approval was
effective April 23, 1999.
A Title V Operating Permit consolidates all air quality regulatory requirements in a single
document, so a permittee can clearly determine compliance with the air quality environmental
laws governing its operation. The Title V Operating Permit also establishes appropriate
compliance assurance monitoring on a pollutant-by-pollutant basis for large emission sources
with add-on pollution control equipment, and/or establishes periodic monitoring for other
regulated pollutants. The process of issuing the Operating Permit is designed to allow
participation by the public, the EPA and nearby states to avoid misinterpretation of air quality
regulatory requirements. This permitting is done to enhance enforceability by clearly defining
the playing field for all concerned parties, such that all regulated industry is governed by the
same rules. These permits are issued for a term of five years and must be renewed and updated
to incorporate current regulatory requirements. Nationally, this program is intended to set
minimum standards for all states to implement, in an attempt to foster consistency in air quality
permitting from state to state. The Operating Permit Program is intended to be self supporting,
and states are required under the Clean Air Act to charge regulated industry fees based upon their
actual air pollutant emissions on an annual basis; thus, Title V permittees pay for the operation of
the regulating program.
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The Operating Permit Program currently affects only major sources of air pollution operating in
the State. A major source is defined as a source which emits, or has the potential to emit, 100
tons per year of an air pollutant, or any source which emits, or has the potential to emit, l0 tons
per year of an individual hazardous air pollutant (or 25 tons per year of any combination of
hazardous air pollutants) which has been listed pursuant to section I l2(b) of the Clean Air Act.
The number of Title V sources within the State is highly variable but has typically ranged from
150 to 160 sources at any given time.
In December of 2000, WAQSR Chapter 6, Section 3 Ooerating permits, was revised to
incorporate compliance assurance monitoring (CAM). CAM is intended to provide a reasonable
assurance of compliance with applicable requirements under the Clean Air Act for large
emission units that rely on pollution control device equipment to achieve compliance.
Monitoring is conducted to determine that control devices, once installed or otherwise employed,
are properly operated and maintained so that they continue to achieve a level of control that
complies with applicable requirements. The Division is addressing the complex implementation
of CAM in renewals, significant modifications and new permits, as applicable. The
implementation of CAM will result in documenting continued operation of control devices,
within ranges of specified indicators of performance, that are designed to provide reasonable
assurance of compliance with applicable requirements.
8.2.1.3 New Source Performance Standards (NSPS)
The Air Quality Division annually incorporates by reference the FederalNew Source
Performance Standards (NSPS). These standards are incorporated via the Wyoming Air Quality
Standards and Regulations, Chapter 5, Section 2. Section 2 first became an efTective State rule
in November 1976, with the latest revision becoming effective in May 2008. Section 2 was last
submitted to the EPA on August 27,2008, approved by EPA on March 9,2009, and became
effective on March 9,2009. The list of NSPS incorporated by reference include:
40 CFR part 60, Subpart D -Standards of Performance for Fossil-Fuel-
Fired Steam Generators for Which
Construction is Commenced After August
17,1971
Standards of Performance for Electric
Utility Steam Generating Units for Which
Construction is Commenced After
September 18, 1978
Standards of performance for Industrial-
Commercial-Institutional Steam Generating
Units
40 CFR part 60, Subpart Da -
40 CFR part 60, Subpart Db -
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40 CFR part 60, Subpart Dc - Standards of Performance for Small
lndustrial-Commercial-Institutional Steam
Generating Units
40 CFR part 60, Subpart E - Standards of Performance for Incinerators
40 CFR part 60, Subpart Ea - Standards of Performance for Municipal
Waste Combustors for Which Construction
is Commenced After December 20,1989
and on or Before September 20,1994
40 CFR part 60, Subpart Eb - Standards of Performance for Large
Municipal Waste Combustors for Which
Construction is Commenced After
September 20,1994 or for Which
Modification or Reconstruction is
Commenced AfterJune 19, 1996
40 CFR part 60, Subpart Ec - Standards of Performance for
Hosp ital/Ir{ed ical/Infectious Waste
Incinerators for Which Construction is
Commenced After June 20, 1996
40 CFR part 60, Subpart F - Standards of Performance for Portland
Cement Plants
40 CFR part 60, Subpart G - Standards of Performance for Nitric Acid
Plants
40 CFR part 60, Subpart H - Standards of Performance for Sulfuric Acid
Plants
40 CFR part 60, Subpart I - Standards of Performance for Hot Mix
Asphalt Facilities
40 CFR part 60, Subpart J - Standards of Performance for Petroleum
Refineries
40 CFR part 60, Subpart K - Standards of Performance for Storage
Vessels for Petroleum Liquids for Which
Construction, Reconstruction, or
Modification Commenced After
June I1,1973, and Prior to May 19,1978
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40 CFR part 60, Subpart Ka -
40 CFR part 60, Subpart Kb -
40 CFR part 60, Subpart L -
40 CFR part 60, Subpart M -
40 CFR part 60, Subpart N -
40 CFR part 60, Subpart Na -
40 CFR part 60, Subpart O -
40 CFR part 60, Subpart P -
40 CFR part 60, Subpart Q -
40 CFR part 60, Subpart R -
40 CFR part 60, Subpart S -
Standards of Performance for Storage
Vessels for Petroleum Liquids for Which
Construction, Reconstruction, or
Modification Commenced After
May 18, 1978, and Prior to July 23,1984
Standards of Performance for Volatile
Organic Liquid Storage Vessels (Including
Petroleum Liquid Storage Vessels) for
Which Construction, Reconstruction, or
Modification Commenced After July 23,
1984
Standards of Performance for Secondary
Lead Smelters
Standards of Performance for Secondary
Brass and Bronze Production Plants
Standards of Performance for Primary
Emissions from Basic Oxygen Process
Furnaces for Which Construction is
Commenced After June I 1,1973
Standards of Performance for Secondary
Emissions from Basic Oxygen Process
Steelmaking Facilities for Which
Construction is Commenced After January
20,1983
Standards of Performance for Sewage
Treatment Plants
Standards of Performance for Primary
Copper Smelters
Standards of Performance for Primary Zinc
Smelters
Standards of Performance for Primary Lead
Smelters
Standards of Performance for Primary
Aluminum Reduction Plants
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40 CFR part 60, Subpart T -
40 CFR part 60, Subpart U -
40 CFR part 60, Subpart V -
40 CFR part 60, Subpart W -
40 CFR parl60, Subpart X -
40 CFR part 60, Subpart Y -
40 CFR part60, Subpart Z -
40 CFR part 60, Subpart AA -
40 CFR part 60, Subpart AAa -
40 CFR part 60, Subpart BB -
40 CFR part 60, Subpart CC -
40 CFR part 60, Subpart DD -
Standards of Performance for the Phosphate
Fertilizer Industry: Wet-Process Phosphoric
Acid Plants
Standards of Performance for the Phosphate
Fertilizer Industry: Superphosphoric Acid
Plants
Standards of Performance for the Phosphate
Fertilizer Industry: Diammonium Phosphate
Plants
Standards of Performance for the Phosphate
Fertilizer Industry: Triple Superphosphate
Plants
Standards of Performance for the Phosphate
Fertilizer Industry: Granular Triple
Superphosphate Storage Facilities
Standards of Performance for Coal
Preparation Plants
Standards of Performance for Ferroalloy
Production Facilities
Standards of Performance for Steel Plants:
Electric Arc Furnaces Constructed After
October 21,1974 and on or Before August
17,1983
Standards of Performance for Steel Plants:
Electric Arc Fumaces and Argon-Oxygen
Decarburization Vessels Constructed After
August 17,1983
Standards of Performance for Kraft Pulp
Mills
Standards of Performance for Glass
Manufacturing Plants
Standards of Performance for Grain
Elevators
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 156 of206
146
40 CFR part 60, Subpart EE -
40 CFR part 60, Subpart GG -
40 CFR part 60, Subpart HH -
40 CFR part 60, Subpart KK -
40 CFR part 60, Subpart LL -
40 CFR part60, Subpart MM -
40 CFR part 60, Subpart NN -
40 CFR part 60, Subpart PP -
40 CFR part 60, Subpart QQ -
40 CFR part 60, Subpart RR -
40 CFR part 60, Subpart SS -
40 CFR part 60, Subpart TT -
40 CFR part 60, Subpart UU -
Standards of Performance for Surface
Coating of Metal Fumiture
Standards of Performance for Stationary Gas
Turbines
Standards of Performance for Lime
Manufacturing Plants
Standards of Performance for Lead-Acid
Battery Manufacturing Plants
Standards of Performance for Metallic
Mineral Processing Plants
Standards of Performance for Automobile
and Light-Duty Truck Surface Coating
Operations
Standards of Performance for Phosphate
Rock Plants
Standards of Performance for Ammonium
Sulfate Manufacture
Standards of Performance for the Graphic
Arts Industry: Publication Rotogravure
Printing
Standards of Performance for Pressure
Sensitive Tape and Label Surface Coating
Operations
Standards of Performance for Industrial
Surface Coating: Large Appliances
Standards of Performance for Metal Coil
Surface Coating
Standards of Performance for Asphalt
Processing and Asphalt Roofing
Manufacture
Standards of Performance for Equipment
Leaks of VOC in the Synthetic Organic
Chem icals Manufacturing Industry
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 157 of206
40 CFR part 60, Subpart VV -
147
40 CFR part 60, Subpart WW -
40 CFR part 60, Subpart XX -
40 CFR part 60, Subpart AAA -
40 CFR part 60, Subpart BBB -
40 CFR part 60, Subpart DDD -
40 CFR part 60, Subpart FFF -
40 CFR part 60, Subpart GGG -
40 CFR part 60, Subpart HHH -
40 CFR part 60, Subpart III -
40 CFR part 60, Subpart JJJ -
40 CFR part 60, Subpart KKK -
40 CFR part 60, Subpart LLL -
40 CFR part 60, Subpart NNN -
Standards of Performance for the Beverage
Can Surface Coating Industry
Standards of Performance for Bulk Gasoline
Terminals
Standards of Performance for New
Residential Wood Heaters
Standards of Performance for the Rubber
Tire Manufacturing Industry
Standards of Performance for Volatile
Organic Compound (VOC) Emissions from
the Polymer Manufacturing Industry
Standards of Performance for Flexible Vinyl
and Urethane Coating and Printing
Standards of Performance for Equipment
Leaks of VOC in Petroleum Refineries
Standards of Performance for Synthetic
Fiber Production Facilities
Standards of Performance for Volatile
Organic Compound (VOC) Emissions From
the Synthetic Organic Chemical
Manufacturing Industry (SOCMI) Air
Oxidation Unit Processes
Standards of Performance for Petroleum Dry
Cleaners
Standards of Performance for Equipment
Leaks of VOC From Onshore Natural Gas
Processing Plants
Standards of Performance for Onshore
Natural Gas Processing: SO2 Emissions
Standards of Performance for Volatile
Organic Compound (VOC) Emissions From
Synthetic Organic Chemical Manufacturing
Industry (SOCMD Distillation Operations
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 158 of 206
148
40 CFR part 60, Subpart OOO -
40 CFR part 60, Subpart PPP -
40 CFR part 60, Subpart aaa -
40 CFR part 60, Subpart RRR -
40 CFR part 60, Subpart SSS -
40 CFR part 60, Subpart TTT -
40 CFR part 60, Subpart UUU -
40 CFR part 60, Subpart WV -
40 CFR part 60, Subpart WWW -
40 CFR part 60, Subpart AAAA -
40 CFR part 60, Subpart CCCC -
Standards of Performance for Nonmetallic
Mineral Processing Plants
Standards of Performance for Wool
Fiberglass Insulation Manufacturing Plants
Standards of Performance for VOC
Emissions From Petroleum Refinery
Wastewater Systems
Standards of Performance for Volatile
Organic Compound Emissions from
Synthetic Organic Chemical Manufacturing
Industry (SOCMI) Reactor Processes
Standards of Performance for Magnetic
Tape Coating Facilities
Standards of Performance for Industrial
Surface Coating: Surface Coating of Plastic
Parts for Business Machines
Standards of Performance for Calciners and
Dryers in Mineral Industries
Standards of Performance for Polymeric
Coating of Supporting Substrates Facilities
Standards of Performance for Municipal
Solid Waste Landfills
Standards of Performance for Small
Municipal Waste Combustion Units for
Which Construction is Commenced After
August 30, 1999 or for Which Modification
or Reconstruction is Commenced After June
6,2001
Standards of Performance for Commercial
and Industrial Solid Waste Incineration
Units for Which Construction is
Commenced After November 30, 1999 or
for Which Modification or Reconstruction
is Commenced on or After June l, 2001
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 159 of206
149
40 CFR part 60, Subpart EEEE - Standards of Perfoffnance for Other Solid Waste
Incineration Units for Which Construction is
Commenced After December 9,2004, or for Which
Modification or Reconstruction is Commenced on
or After June 16, 2006
8.2.1.4 MACT - HAPs Program
The Air Quality Division annually incorporates by reference the Federal National Emission
Standards for Hazardous Air Pollutants (NESHAPs). To the extent that NESHAPs regulate
visibility impairing pollutants through surrogates, these programs may prove helpful in reducing
visibility impairment. These standards are incorporated via the Wyoming Air Quality Standards
and Regulations, Chapter 5, Section 3. Section 3 first became an effective State rule in August
of 1997, with the latest revision becoming effective in May 2008. The delegation request for
Section 3 was submitted to the EPA in June of 2008. The list ofNESHAP (MACT) standards
incorporated by reference include:
40 CFR part63, Subpart D -Regulations Goveming Compliance
Extensions for Early Reductions of
Hazardous Air Pollutants
National Emission Standards for
Organic Hazardous Air Pollutants
From the Synthetic Organic
Chemical Manufacturing Industry
National Emission Standards for
Organic Hazardous Air Pollutants
From the Synthetic Organic
Chem ical Manufacturing Industry
for Process Vents, Storage Vessels,
Transfer Operations, and Wastewater
National Emission Standards for
Organic Hazardous Air Pollutants
for Equipment Leaks
National Emission Standards for
Organic Hazardous Air Pollutants
for Certain Processes Subject to
the Negotiated Regulation for
Equipment Leaks
40 CFR part63, Subpart F -
40 CFR part63, Subpart G -
40 CFR part63, Subpart H
40 CFR part63, Subpart I -
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 160 of206
150
40 CFR part63, Subpart J -
40 CFR part63, Subpart L -
40 CFR part63, Subpart M -
40 CFR part 63, Subpart N -
40 CFR part63, Subpart O -
40 CFR part63, Subpart Q -
40 CFR part63, Subpart R -
40 CFR part 63, Subpart S -
40 CFR part 63, Subpart T -
40 CFR part 63, Subpart U -
National Emission Standards for
Hazardous Air Pollutants for
Polyvinyl Chloride and Copolymers
Production
National Emission Standards for
Coke Oven Batteries
National Perchloroethylene Air
Emission Standards for Dry
Cleaning Facilities
National Emission Standards for
Chromium Emissions From Hard
and Decorative Chromium
Electroplating and Chromium
Anodizing Tanks
Ethylene Oxide Emissions
Standards for Sterilization
Facilities
National Emission Standards for
Hazardous Air Pollutants for
lndustrial Process Cooling
Towers
National Emission Standards for
Gasoline Distribution Facilities
(Bulk Gasoline Terminals and
Pipeline Breakout Stations)
National Emission Standards for
Hazardous Air Pollutants from the
Pulp and Paper Industry
National Emission Standards for
Halogenated Solvent Cleaning
National Emission Standards for
Hazardous Air Pollutant Emissions:
Group I Polymers and Resins
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 161 of206
l5l
40 CFR parl63, Subpart W -
40 CFR part63, Subpart X -
40 CFR part 63, Subpart Y -
40 CFR part 63, Subpart AA -
40 CFR part63, Subpart BB -
40 CFR part63, Subpart CC -
40 CFR part63, Subpart DD -
40 CFR part63, Subpart EE -
40 CFR part63, Subpart GG -
40 CFR part 63, Subpart HH -
National Emission Standards for
Hazardous Air Pollutants for
Epoxy Resins Production
and Non-Nylon Polyamides
Production
National Emission Standards for
Hazardous Air Pollutants from
Secondary Lead Smelting
National Emission Standards for
Marine Tank Vessel Loading
Operations
National Emission Standards for
Hazardous Air Pollutants From
Phosphoric Acid Manufacturing
Plants
National Emission Standards for
Hazardous Air Pollutants From
Phosphate Fertilizers Production
Plants
National Emission Standards for
Hazardous Air Pollutants From
Petroleum Refineries
National Emission Standards for
Hazardous Air Pollutants from
Off-Site Waste and Recovery
Operations
National Emission Standards for
Magnetic Tape Manufacturing
Operations
National Emission Standards for
Aerospace Manufacturing and
Rework Facilities
National Emission Standards for
Hazardous Air Pollutants From
Oil and Natural Gas Production
Facilities
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 162 of206
ts2
40 CFR part63, Subpart II -
40 CFR part63, Subpart JJ -
40 CFR part 63, Subpart KK -
40 CFR part63, Subpart LL -
40 CFR part63, Subpart MM -
40 CFR part63, Subpart OO -
40 CFR parl63, Subpart PP -
40 CFR part 63, Subpart QQ -
40 CFR part 63, Subpart RR -
40 CFR part63, Subpart SS -
40 CFR part63, Subpart TT -
40 CFR part 63, Subpart UU -
National Emission Standards for
Shipbuilding and Ship Repair
(Surface Coating)
National Emission Standards for
Wood Fum iture Manufacturing
Operations
National Emission Standards for
the Printing and Publishing Industry
National Emission Standards for
Hazardous Air Pollutants for
Primary Aluminum Reduction Plants
National Emission Standards for
Hazardous Air Pollutants for
Chemical Recovery Combustion
Sources at Kraft, Soda, Sulfite,
and Stand-Alone Semichemical
Pulp Mills
National Emission Standards for
Tanks - Level I
National Emission Standards for
Containers
National Emission Standards for
Surface Impoundments
National Emission Standards for
Individual Drain Systems
National Emission Standards for
Closed Vent Systems, Control
Devices, Recovery Devices and
Routing to a Fuel Gas System
or a Process
National Emission Standards for
Equipment Leaks - Control Level
National Emission Standards for
Equipment Leaks - Control Level
2 Standards
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 163 of206
153
40 CFR part63, Subpart W -
40 CFR part63, Subpart WW -
40 CFR par:t63, Subpart XX -
40 CFR part 63, Subpart YY -
40 CFR part63, Subpart CCC -
40 CFR part63, Subpart DDD -
40 CFR part 63, Subpart EEE -
40 CFR part63, Subpart GGG -
40 CFR part63, Subpart HHH -
National Emission Standards for
Oil-Water Separators and Organic-
Water Separators
National Emission Standards for
Storage Vessels (Tanks) - Control
Level 2
National Emission Standards for
Ethylene Manufacturing Process
Units: Heat Exchange Systems
and Waste Operations
National Emission Standards for
Hazardous Air Pollutants for
Source Categories: Generic
Maximum Achievable Control
Technology Standards
National Emission Standards for
Hazardous Air Pollutants for Steel
Pickling - HCI Process Facilities
and Hydrochloric Acid
Regeneration Plants
National Emission Standards for
Hazardous Air Pollutants for
Mineral Wool Production
National Emission Standards for
Hazardous Air Pollutants from
Hazardous Waste Combustors
National Emission Standards for
Pharmaceuticals Production
National Emission Standards for
Hazardous Air Pollutants From
Natural Gas Transmission and
Storage Facilities
National Emission Standards for
Hazardous Air Pollutants for
Flexible Polyurethane Foam
Production
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 164 of206
40 CFR parl63, Subpart III -
154
40 CFR part63, Subpart JJJ -
40 CFR part63, Subpart LLL -
40 CFR part63, Subpart MMM -
40 CFR part 63, Subpart NNN -
40 CFR part63, Subpart OOO -
40 CFR part 63, Subpart PPP -
40 CFR part 63, Subpart aaa -
40 CFR part63, Subpart RRR -
40 CFR part63, Subpart TTT -
40 CFR part63, Subpart UUU -
National Emission Standards for
Hazardous Air Pollutant Emissions:
Group IV Polymers and Resins
National Emission Standards for
Hazardous Air Pollutants From the
Portland Cement Manufacturing
Industry
National Emission Standards for
Hazardous Air Pollutants for
Pesticide Active Ingredient
Production
National Emission Standards for
Hazardous Air Pollutants for Wool
Fiberglass Manufacturing
National Emission Standards for
Hazardous Air Pollutant Emissions:
Manufacture of Am ino/Phenolic
Resins
National Emission Standards for
Hazardous Air Pollutants for
Polyether Polyols Production
National Emission Standards for
Hazardous Air Pollutants for
Primary Copper Smelting
National Emission Standards for
Hazardous Air Pollutants for
Secondary A lum inum Production
National Emission Standards for
Hazardous Air Pollutants for
Primary Lead Smelting
National Emission Standards for
Hazardous Air Pollutants for
Petroleum Refineries: Catalytic
Cracking Units, Catalytic
Reforming Units, and Sulfur
Recovery Units
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page '165 of 206
155
40 CFR part63, Subpart VW -
40 CFR parl63, Subpart XXX -
40 CFR part63, Subpart A,rA,r{A -
40 CFR part63, Subpart CCCC -
40 CFR part 63, Subpart DDDD -
40 CFR part63, Subpart EEEE -
40 CFR part63, Subpart FFFF -
40 CFR part63, Subpart GGGG -
40 CFR part63, Subpart HHHH -
40 CFR part63, Subpart IIII -
National Emission Standards for
Hazardous Air Pollutants: Publicly
Owned Treatment Works
National Emission Standards for
Hazardous Air Pollutants for
Ferroalloys Production:
Ferromanganese and
Silicomanganese
National Emission Standards for
Hazardous Air Pollutants:
Municipal Solid Waste Landfills
National Emission Standards for
Hazardous Air Pollutants:
Manufacturing of Nutritional Yeast
National Emission Standards for
Hazardous Air Pollutants: Plywood
and Composite Wood Products
National Emission Standards for
Hazardous Air Pollutants: Organic
Liquids Distribution (Non-Gasoline)
National Emission Standards for
Hazardous Air Pollutants:
Miscellaneous Organic Chemical
Manufacturing
National Emission Standards for
Hazardous Air Pollutants: Solvent
Extraction for Vegetable Oil
Production
National Emission Standards for
Hazardous Air Pollutants for Wet-
Formed Fiberglass Mat Production
National Emission Standards for
Hazardous Air Pollutants: Surface
Coating of Automobiles and Light-
Duty Trucks
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 166 of206
156
40 CFR paft63, Subpart JJJJ -
40 CFR part63, Subpart KKKK -
40 CFR part63, Subpart MMMM -
40 CFR part 63, Subpart NNNN -
40 CFR part63, Subpart OOOO -
40 CFR part 63,Subpart PPPP -
40 CFR part 63, Subpart aaaa -
40 CFR part63, Subpart RRRR -
40 CFR part63, Subpart SSSS -
40 CFR part63, Subpart TTTT -
National Emission Standards for
Hazardous Air Pollutants: Paper
and Other Web Coating
National Emission Standards for
Hazardous Air Pollutants: Surface
Coating of Metal Cans
National Emission Standards for
Hazardous Air Pollutants for Surface
Coating of Miscellaneous Metal
Parts and Products
National Emission Standards for
Hazardous Air Pollutants:
Surface Coating of Large
Appliances
National Emission Standards for
Hazardous Air Pollutants:
Printing, Coating, and Dyeing of
Fabrics and Other Textiles
National Emission Standards for
Hazardous Air Pollutants for Surface
Coating of Plastic Parts and Products
National Emission Standards for
Hazardous Air Pollutants: Surface
Coating of Wood Building Products
National Emission Standards for
Hazardous Air Pollutants: Surface
Coating of Metal Furniture
National Emission Standards for
Hazardous Air Pollutants: Surface
Coating of MetalCoil
National Emission Standards for
Hazardous Air Pollutants for Leather
Finishing Operations
National Emission Standards for
Hazardous Air Pollutants for
Cellulose Products Manufacturing
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 167 of206
40 CFR part63, Subpart UUUU -
r57
40 CFR part63, Subpart VVVV -
40 CFR part63, Subpart WWWW
40 CFR part63, Subpart XXXX -
40 CFR part63, Subpart YYYY -
40 CFR part63, Subpart ZZZZ -
40 CFR part63, Subpart AAAAA -
40 CFR part63, Subpart BBBBB -
40 CFR part63, Subpart CCCCC -
40 CFR part63, Subpart DDDDD -
National Emission Standards for
Hazardous Air Pollutants for Boat
Manufacturing
National Emissions Standards for
Hazardous Air Pollutants:
Reinforced Plastic Composites
Production
National Emission Standards for
Hazardous Air Pollutants: Rubber
Tire Manufacturing
National Emission Standards for
Hazardous Air Pollutants for
Stationary Combustion Turbines
National Emission Standards for
Hazardous Air Pollutants for
Stationary Reciprocating Internal
Combustion Engines
National Emissions Standards for
Hazardous Air Pollutants for Lime
Manufacturing Plants
National Emission Standards for
Hazardous Air Pollutants for
Sem iconductor Manufacturing
National Emission Standards for
Hazardous Air Pollutants for Coke
Ovens: Pushing, Quenching, and
Battery Stacks
National Emission Standards for
Hazardous Air Pollutants for
Industrial, Commercial, and
Institutional Boilers and Process
Heaters
National Emission Standards for
Hazardous Air Pollutants for Iron
and Steel Foundries
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 168 of 206
40 CFR part63, Subpart EEEEE -
158
40 CFR part63, Subpart FFFFF -National Emission Standards for
Hazardous Air Pollutants for
lntegrated Iron and Steel
Manufacturing Faci I ities
National Emission Standards for
Hazardous Air Pollutants: Site
Remediation
National Emission Standards for
Hazardous Air Pollutants:
Miscellaneous Coating
Manufacturing
National Emission Standards for
Hazardous Air Pollutants: Mercury
Emissions From Mercury Cell
Chlor-Alkali Plants
National Emission Standards for
Hazardous Air Pollutants for Brick
and Structural Clay Products
Manufacturing
National Emission Standards for
Hazardous Air Pollutants for Clay
Ceramics Manufacturing
National Emission Standards for
Hazardous Air Pollutants: Asphalt
Processing and Asphalt Roofing
Manufacturing
National Emission Standards for
Hazardous Air Pollutants: Flexible
Polyurethane Foam Fabrication
Operations
National Emission Standards for
Hazardous Air Pollutants:
Hydrochloric Acid Production
National Emission Standards for
Hazardous Air Pollutants for
Engine Test Cells/Stands
40 CFR part63, Subpart GGGGG -
40 CFR part63, Subpart HHHHH -
40 CFR part63, Subpart IIIII -
40 CFR part 63, Subpart JJJJJ -
40 CFR part63, Subpart KKKKK -
40 CFR part63, Subpart LLLLL -
40 CFR part63, Subpart MMMMM -
40 CFR part63, Subpart NNNNN -
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 169 of206
40 CFR part63, Subpart PPPPP -
159
40 CFR part63, Subpart QQaaa -National Emission Standards for
Hazardous Air Pollutants for
Friction Materials Manufacturing
Facilities
National Emission Standards for
Hazardous Air Pollutants: Taconite
Iron Ore Processing
National Emission Standards for
Hazardous Air Pollutants for
Refractory Products Manufacturing
National Emissions Standards for
Hazardous Air Pollutants for Primary
Magnesium Refining
40 CFR part63, Subpart RRRRR -
40 CFR part63, Subpart SSSSS -
40 CFR part63, Subpart TTTTT -
The Air Quality Division also determines case-by-case MACT determinations through Chapter
6, Section 6.
8.2.1.5 Phase I Visibility Rules - Wyoming Reasonably Attributable Visibility Impairment
Rules
In response to EPA's Phase I visibility rules, Wyoming adopted the Wyoming State
Implementation Plan for Class I Visibility Protection, effective May 10, 1988. It was approved
by the U.S. EPA by notice in the Federal Register on February 15, 1989, under 40 CFR part 52,
and became effective on April 17, 1989. This visibility rule contains short and long-term
strategies for making reasonable progress toward the national goal, related to addressing
reasonably attributable impairment in the State's Class I areas through visibility monitoring and
control strategies. This rule incorporates PSD requirements for visibility protection from new or
modified major stationary sources, and if necessary applying BART to existing stationary
sources if certified as causing reasonably attributable visibility impairment.
8.2.1.6 Ongoing Implementation of Federal Mobile Source Regulations
The Federal Motor Vehicle ControlProgram (FMVCP) has produced and is continuing to
produce large reductions in motor vehicle emissions of NO*, PM, and VOCs. Beginning in
2006, EPA mandated new standards for on-road (highway) diesel fuel, known as ultra-low sulfur
diesel (ULSD). This regulation dropped the sulfur content of diesel fuel from 500 ppm to l5
ppm. ULSD fuel enables the use of cleaner technology diesel engines and vehicles with
advanced emissions control devices, resulting in significantly lower emissions. Diesel fuel
intended for locomotive, marine and non-road (farming and construction) engines and equipment
was required to meet the low sulfur diesel fuel maximum specification of 500 ppm sulfur in2007
(down from 5,000 ppm). By 2010, the ULSD fuel standard of l5-ppm sulfur will apply to all
non-road diesel fuel. Locomotive and marine diesel fuelwill be required to meet the ULSD
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 170 of206
160
standard beginning in2012, resulting in further reductions of diesel emissions. These rules not
only reduce SOz emissions, but also NO* and PM emissions.
In addition to the ULSD standard, listed below are several other significant Federal programs:
Federal On-Road Measures
o Tier 2 vehicle emission standards and Federal low-sulfur gasoline
o National low emissions vehicle standards (NLEV)
o Heavy-duty diesel standards
Federal Non-Road Measures
o Lawn and garden equipment
o Tier 2 heavy-duty diesel equipment
o Locomotive engine standards
o Compression ignition standards for vehicles and equipment
o Recreational marine engine standards
In addition, the Renewable Fuel Standard Under Section 211(o) of the Clean Air Act as Amended
by the Energt Policy Act of 2005, is determined annually (must be published in the Federal
Register by November 30 of each year) by EPA and is applicable to refiners, importers and
blenders of gasoline.
8.2.1.7 Ongoing Implementation of Programs to Meet PMl6 NAAQS
Currently, only one community in Wyoming, Sheridan, is designated as a nonattainment area
under the PMro National Ambient Air Quality Standard (NAAQS). The significance of this
nonattainment area in terms of regional haze is that significant reductions in PM16 emissions
have been made in the last ten years, by adopting strategies to address the primary emission
sources in the community. The major contributing sources causing nonattainment in this
community are road dust, residential woodstoves, outdoor burning, and to a lesser degree,
industry.
8.2.1.7.1 Nonattainment SIP (PMro) - City of Sheridan
Because Sheridan, Wyoming was designated a Group I area under the PMro Regulations
promulgated by the EPA on July 20, 1987, the Air Quality Division was required to develop a
State Implementation Plan outlining control strategies with a demonstration of attainment and
maintenance of the standards. In cooperation with the Sheridan City govemment, a plan was
developed which addressed four PMls control measures.
The first control measure involved implementing a sanding plan or air quality maintenance plan
(AQMP), which aimed to reduce PMro emissions by designating specific limitations/guidelines
for sanding routes, sanding mediums, application rates, and street cleaning.
The second control measure was a voluntary curtailment of solid fuels combustion, whereby an
ordinance was enacted allowing the designation of voluntary "no bum days" when PMro
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 171 ot 206
l6l
concentrations exceed or are predicted to exceed established criteria levels. The Division
collects "real time" particulate data and uses the information in conjunction with weather
predictions to trigger requests for burning curtailment.
Fugitive dust concems comprised the third control measure. Several industrial areas in the City
of Sheridan were identified as significant sources of fugitive dust. The Division required that
these facilities submit a dust control plan specifing as a minimum, application of asphalt, oil, or
suitable chemical dust control agents on unpaved roads within their operations. One facility was
asked to use more durable washed sand rather than scoria for skid control.
Because some of the streets of Sheridan are maintained by the County and the Highway
Department, as a fourth control measure these agencies were also contacted by the Division in an
effort to implement similar sanding practices in the City. Sanding plans were submitted by both
the County and Highway Department specifying sanding mediums, routes, and application rates.
8.2.1.7.2 Natural and Uncontrollable Sources Program - Natural Events Action Plan
On May 30, 1996, the Environmental Protection Agency (EPA) issued a Natural Events Policy
(NEP) which recognized that certain uncontrollable natural events, such as high winds, wildland
fires, and volcanic/seismic activity can result in adverse consequences for the National Ambient
Air Quality Standard (NAAQS). The NEP set forth procedures for protecting public health
through the development of a Natural Events Action Plan (NEAP) which implements Best
Available Control Measures (BACM) for human-generated particulate emissions in areas where
the PMro (particulate matter having a nominal aerodynamic equal to or less than 10 microns)
standard may be violated due to these uncontrolled natural events. The NEP also provides that if
an approved NEAP is implemented, future air quality exceedances due to uncontrollable natural
events may be flagged, and, if demonstrated to be a natural event, not be considered when
determining the region's air quality designation if BACM measures are being implemented.
A number of Federal Reference or Equivalent PMro monitors are located in Wyoming's Powder
River Basin (PRB) at several large mining operations. Some of the monitors have recorded
exceedances of the 24-hour NAAQS for PMro. Each of the monitored exceedances was
associated with high winds and blowing dust resulting from prolonged periods of low
precipitation and consequential low soil moisture content.
Recognizing the need to protect public health in the Powder River Basin where measured PMro
values exceeded the NAAQS because of wind generated dust, in early 2007 the State of
Wyoming, with the aid of stakeholders, prepared a Natural Events Action Plan based on EPA
Natural Event Policy (NEP) guidance. This plan outlines specific procedures to be taken in
response to future high wind events. In short, the purpose of the plan is to:
o Educate the public about the problem;r Mitigate health impacts on exposed populations during future events; ando ldentify and implement Best Available Control Measures (BACM) for significant,
anthropogenic sources of windblown dust.
Exhibit No.4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 172 of 206
162
All coal mines in the Wyoming PRB employ Best Available Control Technology (BACT). This
Natural Events Action Plan for the Powder River Basin identifies BACT measures in place as the
result of existing permit requirements, additional potential control measures identified as BACM,
and reactionary control measures directed at transient problem sites that may be implemented
during Natural Events. lmplementation of BACT, BACM, and reactionary control measures will
assure that anthropogenic dust emissions from the coal mines in the PRB are controlled to the
greatest extent possible. The goal is to protect public health and to minimize exceedances of the
PMrg NAAQS through the continued implementation of BACT, and implementation of BACM
and reactionary control measures.
The Natural Events Action Plan may be accessed at: http://deq.state.wy.us/aqd/NEAP.asp.
8.2.2 Measures to Mitigate the Impacts of Construction Activities
Chapter 3 of the Wyoming Air Quality Standards and Regulations (WAQSR) establishes limits
on the quantity, rate, or concentration of emissions of air pollutants, including any requirements
which limit the level of opacity, prescribe equipment, set fuel specifications, or prescribe
operation or maintenance procedures. Specifically, Chapter 3, Section 2(f), prescribes measures
to ensure the control of fugitive dust emissions during. construction or demolition activities,
handling, storage and transporting of materials and agricultural practices. Chapter 3, Section 2(f)
was originally adopted by the State of Wyoming on February 22, 1972. The entire section was
restructured on October 29,1999. Section 2(f) was revised on March 30, 2000 and submitted to
EPA on August 13,2001, then resubmitted on September 12,2003 as part of the restructuring of
the rules. Revisions to Chapter 3 were most recently approved by EPA on July 28,2004. The
State believes these regulations address common construction activities.
Wyoming believes point and area sources of emissions from these regulated sources are in part
attributed to impacting regional haze in Wyoming. Wyoming relies on the particulate emission
control measures specified in Chapter 3 to most directly address these sources of fine and coarse
particles known to have a minor, but measured, impact on visibility in Class I areas of the state.
8.2.3 Emission Limitations and Schedules of Compliance
The implementation of BART, as described in Chapter 6, will contain emission limits and
schedules of compliance for those sources either installing BART controls or taking Federally
enforceable permit limitations. The four-factor analysis identifies some additional measures that
are appropriate for this first Regional Haze Plan. The evaluation of non-BART sources as part of
the LTS identifies additional emission reductions and improves visibility by 2018.
8.2.4 Source Retirement and Replacement Schedules
Part of this LTS contains an evaluation of non-BART sources, described in Sections 8.3.4 and
8.3.5. The Division is not currently aware of any specific scheduled shutdowns, retirements in
upcoming years, or replacement schedules, such as planned installation of new control
equipment to meet other regulations or routine equipment replacement or modemization. As the
Division becomes aware of such actions, they will be factored into upcoming reviews.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
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163
8.2.5 Agricultural and Forestry Smoke Management Techniques
Wyoming Air Quality Standards and Regulations (WAQSR) Chapter 10, Smoke Management,
was originally adopted by the State of Wyoming on February 10, 1970. Chapter l0 has been
revised several times, most recently becoming an effective State rule on April 5, 2005. Chapter
I 0 was submitted to EPA on April 23,2004 and is awaiting EPA approval. A smoke
management certification was submitted to EPA on November 17,2005. The last EPA approval
was part of the entire restructuring of the rules, approved on July 28, 2004. Chapter l0 is
utilized in Wyoming to establish restrictions and requirements on specific buming practices.
Section 2 regulates refuse buming; open burning oftrade wastes, for salvage operations, for fire
hazards, and for firefighting training; and vegetative material open burning. Section 2 includes
the permitting of prescribed fires occurring on Federal and State lands, and requires Federal land
and State land managers to perform modeling to determine meteorological conditions under
which burning can occur and maintain compliance with ambient air quality standards. Section 3
specifically regulates emissions from wood waste bumers. Section 4 regulates sources of
vegetative buming for the management of air quality emissions and impacts from smoke on
public health and visibility.
A Smoke Management Program Guidance Document was developed in November 2004, to
assist burners in understanding the requirements and aid in the implementation of Section 4. The
intent of Chapter l0 is to provide an equitable and workable program for all bumers that is
simple to implement and is the least burdensome possible, thereby focusing on the most common
situations rather than extreme or isolated circumstances. Bumers must comply with all local
(city and county), State and Federal laws, regulations and ordinances relating to burning in
addition to complying with the regulatory requirements for air quality.
Division staff actively participate in the WRAP Fire Emissions Joint Forum (FEJF), formed to
address both policy and technical issues concerning smoke effects that are caused by wildland
and agricultural fires on public, tribal, and private lands. The FEJF is guided by the
recommendations contained in the GCVTC Final Report and the requirements of the Regional
Haze Rule regarding fire emissions and visibility. The FEJF has developed several policies for
the WRAP through a stakeholder-based consensus process to assist the WRAP states and tribes
in addressing emissions from fire sources. In these policies, the WRAP seeks to provide a
consistent framework that states and tribes can use to efficiently develop their individual regional
haze implementation plans, long-term strategies, and periodic progress reports.
The WRAP has advanced the following policies developed by the FEJF as viable tools for both
Section 308 and 309 states to meet the requirements of the Rule.
o The WRAP Policy for Categorizing Fire Emissions6 was developed to clarify the
complex relationship between what is considered a natural source of fire and what is
considered a human-caused source, as acknowledged in the Rule. A methodology to
categorize fire emissions as either "natural" or "anthropogenic" is the basis of the Policy;
6 Western Regional Air Partnership, Fire Emissions Joint Forum, Natural Background Task Team, Policy for
Categorizing Fire Emissions, November 15, 2001.
Exhibit No. 4
Case No. IPC-E-13-'16
T. Harvey, IPC
Page 174 of 206
164
thus providing the foundation for fire's inclusion in natural background condition values
and ultimately, the tracking of reasonable progress.
The WMP Policy on Enhanced Smoke Management Programs for VisibiliryT defines the
enhanced smoke management program as smoke management efforts that specifically
address visibility, thereby, going beyond the EPA Interim Policy and the AAQTF Air
Quality Policy specific guidance provided for smoke management programs that address
public health and nuisance concems. The Policy identifies for states/tribes in the WRAP
region the elements of an enhanced smoke management program to address visibility
effects from all types of fire that contribute to visibility impairment in mandatory Federal
Class I areas.
r The WRAP defines the annual emission goal as a quantifiable value that is used to
measure progress each year toward the desired outcome of achieving the minimum
emission increase from fire. lnthe WRAP Policy on Annual Emissions Goals for Fireg,
the WRAP outlines a process by which states/tribes may establish annual emission goals,
based on the utilization of currently available emission reduction techniques, to include in
their Regional Haze SIPs.
o It is the position of the WMP Policy on Fire Tracking Systemse that it is necessary to
track fire activity information in the WRAP region using a fire tracking system, which
will also provide the information essential to create a fire emissions inventory. The
Policy identifies seven essential components of a fire tracking system that represent the
minimum spatial and temporal fire activity information necessary to consistently
calculate emissions and to meet the requirements of the Rule.
The Air Quality Division is required to conduct an Annual Program Evaluation to assess the
adequacy of the design, impact and implementation of Wyoming's Smoke Management
Program. The first Evaluation covered the program implementation during calendar years 2005
and 2006.
8.2.6 Enforceability of Wyoming's Measures
Section 51.308(dX3)(v)G) of the Regional Haze Rule requires states to ensure that emission
limitations and control measures used to meet reasonable progress goals are enforceable.
Wyoming has ensured that all existing emission limitations and control measures, for which the
State of Wyoming is responsible, used to meet reasonable progress goals are enforceable at the
State level through the Wyoming Air Quality Standards and Regulations (WAQSR) or State-
issued permits. Many of the actions included in the SIP are already federally enforceable.
7 Westem Regional Air Partnership, Fire Emissions Joint Forum, Enhanced Smoke Management Task Team, WRAP
Policy on Enhanced Smoke Management Programs for Visibility, November 12,2002.
8 Westem Regional Air Partnership, Fire Emissions Joint Forum, Annual Emission Goals Task Team, WRAP Policy
on Annual Emission Coals for Fire, DRAFT December 16,2002.
e Westem Regional Air Partnership, Fire Emissions Joint Forum, WRAP Policy on Fire Tracking Systems, DRAFT
December 19,2002.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 175 of 206
165
However, BART permit conditions and long-term strategy commitments for the Laramie River
Station and the Jim Bridger Power Plant are currently only enforceable at the State level. Once
EPA approves this SIP, these measures will be federally enforceable. The BART determinations
are summarized in Table 6.4-l and the long-term strategy commitments can be found in Section
8.3.3.
8.3 Additional Measures in the Long-Term Strategy
This section of the LTS identifies new measures being proposed by the Division for achieving
reasonable progress. These reasonable progress measures will be evaluated and discussed in the
next Plan update in 2013.
8.3.1 Future Federal Mobile Programs
A new rule, o'Control of Emissions of Air Pollution from Locomotives and Marine Compression-
Ignition Engines Less Than 30 Liters per Cylinder", was signed on March 14, 2008. EPA
estimates that by 2030, this program will reduce annual emissions ofNO* by about 800,000 tons
and PM emissions by 27,000 tons. Emission reductions are expected to continue as fleet
turnover is completed. These standards are intended to achieve these large reductions in
emissions through the use of technologies such as in-cylinder controls, aftertreatment, and low
sulfur fuel, perhaps as early as 201 l.
In June 2009, EPA announced a rule (Control of Emissions from New Marine Compression-
Ignition Engines at or Above 30 Liters per Cylinder) proposing more stringent exhaust emission
standards for the largest marine diesel engines used for propulsion on oceangoing vessels (called
Category 3 engines). The proposed engine standards are equivalent to the nitrogen oxides limits
recently adopted in amendments to Annex VI to the Intemational Convention for the Prevention
of Pollution from Ships O/IARPOL). The near-term standards for newly-built engines would
apply beginning in 201 l. Long-term standards would begin in 2016, and are based on the
application of high-efficiency aftertreatment technology. By 2030, this strategy to address
emissions from oceangoing vessels is expected to reduce annual emissions of NO* in the U.S. by
approximately 1.2 million tons and particulate matter emissions by about 143,000 tons. When
fully implemented, the coordinated strategy is anticipated to reduce NO* emissions by 80 percent
and PM emissions by 85 percent, compared to the current limits applicable to these engines.
A proposed rule, the Renewable Fuel Standard (RFS2), was signed by Administrator Jackson on
May 5, 2009. EPA is proposing that this rule take effect on January 1,2010; however, this date
is tentative and it could be mid-2010 or January 1,201I before this rule becomes final. This rule
intends to address changes to the Renewable Fuel Standard program as required by the Energy
Independence and Security Act of 2007 (EISA). The revised statutory requirements establish
new specific volume standards for cellulosic biofuel, biomass-based diesel, advanced biofuel,
and total renewable fuelthat must be used in transportation fuel each year. The revised statutory
requirements also include new definitions and criteria for both renewable fuels and the
feedstocks used to produce them, including new greenhouse gas emission (GHG) thresholds for
renewable fuels. The regulatory requirements for RFS will apply to domestic and foreign
producers and importers of renewable fuel. It is estimated that annual GHG emissions from
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 176 of206
166
transportation will be reduced by approximately 160 million tons, the equivalent of the removal
of 24 million vehicles from the highways. In addition, 36 billion gallons of renewable fuel will
displace approximately ll% of gasoline and diesel consumptionin2022. The majority ofthe
reductions are expected to come from reduced petroleum imports.
8.3.2 Efforts to Address Offshore Shipping
As depicted by PSAT results in Chapter 5, offshore marine vessel emissions contribute to
Wyoming Class I areas. Wyoming has no authority to regulate offshore shipping emissions and
must rely upon other states such as California for adoption of regulations. On February 28,2003
EPA adopted emission standards for new marine diesel engines installed on vessels flagged or
registered in the United States with displacement at or above 30 liters per cylinder. Also adopted
in this rulemaking were additional standards for new engines with displacement at or above 2.5
liters per cylinder but less than 30 liters per cylinder. This rule established a deadline of April 27,
2007 for EPA to promulgate a second set of emission standards for these engines. Because much
of the information necessary to develop more stringent Category 3 marine diesel engines
standards has become available only recently, a new deadline for the rulemaking to consider the
next tier of Category 3 marine diesel engine standards has been set for December 17,2009. On
December 7,2007, EPA announced an advance notice of proposed rulemaking regarding the
above-referenced standards, first set in 2003. The advanced notice of proposed rulemaking
stated that EPA was considering standards for achieving large reductions in oxides of nitrogen
(NO.) and particulate matter (PM) through the use of technologies such as in-cylinder controls,
aftertreatment, and low sulfur fuel, starting as early as 201 l.
On July 24,2008, the State of California adopted new strict regulations for marine vessels within
24 miles of shore. The Division expects that implementation of these new regulations for marine
vessels will have benefits in Wyoming.
In October 2008, Member States of the International Maritime Organization (IMO) adopted new
international standards for marine diesel engines and their fuels (2008 Amendments to MARPOL
Annex VI) that apply globally, and establishes additional, more stringent emission requirements
for ships that operate in specially-designated coastal areas where air quality problems are acute.
Under the new global standards, NO" emissions will be reduced, and the fuel sulfur cap will drop
to 5,000 ppm in 2020 (pending a fuel availability review in 2018). Under the new geographic
standards, ships operating in designated areas will be required to use engines that meet the most
advanced technology-forcing standards for NO* emissions, and to use fuel with sulfur content at
or below 1,000 ppm.
On March 27,2009, the United States submitted a joint proposalwith Canada to the IMO to
designate specific areas of our coastal waters as an Emission Control Area (ECA). Compared to
fuels used in ships today, ECA standards will lead to a 96 percent reduction in sulfur in ships'
fuels, as well as a cut in emissions of PM by 85 percent and NO,. by 80 percent. To achieve
these reductions, ships must use fuel with no more than 1,000 parts per million sulfur beginning
in 2015, and new ships will have to use advanced emission control technologies beginning in
20t6.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page177 of206
167
8.3.3 Long-Term Control Strategies for BART Facilities
In addition to the control strategies identified in Chapter 6 (Best Available Retrofit Technology
(BART)) as BART determinations, the following requirements will be established through
permit conditions or orders from the Environmental Quality Council for the individual BART
facilities listed below:
Laramie River Station:
On March 8, 2010, Basin Electric Power Cooperative appealed the BART permit for the Laramie
River Station before the Wyoming Environmental Quality Council (EQC). The Department of
Environmental Quality entered into a settlement agreement on November 16, 2010 with Basin
Electric Power Cooperative to modiff the BART permit. On December 8, 2010, the Division
held a State Implementation Plan (SIP) Hearing on RegionalHaze. The SIP hearing was held in
Cheyenne, Wyoming at the Laramie County Library, 2200 Pioneer Avenue. At that time, the
Division collected public comment on the Regional Haze SIP revisions.
After carefully considering all comments on revisions to the State Implementation Plan to
address Regional Haze, the Division has determined that the following requirements for further
NO* reduction taken from the Settlement Agreement Filed November 16,2010 before the
Wyoming EQC and incorporated into the EQC Order approving the Settlement, shall establish
the NO* reduction requirements under the Long-Term Strategy of the Wyoming Regional Haze
SIP for three units at Laramie River Station with respect to NO* and NO* only.
l. Total NO* emissions from Laramie River Station Units I ,2 and 3 shall be further reduced
to a plant-wide emission limit of 12,773 tons ofNO* per year by December 31,2017 and
continuing thereafter, unless changed pursuant to new regulatory or permit requirements.
2. Basin Electric Power Cooperative shall submit to the Division a permit application for
the 12,773 ton plant-wide NO* emission limit at the Laramie River Station by December
31,2015.
Jim Bridger Power Plant (Units I and 2):
With respect to Bridger Units I and2, PacifiCorp shall: (i) install SCR; (ii) install altemative
add-on NO* control systems; or (iii) otherwise reduce NO* emissions not to exceed a 0.07
lblTvlMBtu 30-day rolling average NO* emissions rate. These installations shall occur, and/or
this emission rate will be achieved, on Unit 2 prior to December 31,2021and Unit I prior to
December 31,2022. These installations shall occur, and/or this emission rate will be achieved,
in conjunction with PacifiCorp's planned overhaul schedule for these units and pursuant to a
construction or other permitapplication to be submitted by PacifiCorp to AQD no later than
December 31,2017 .
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 178 of206
168
Jim Bridger Power Plant (Units 3 and 4):
With respect to Bridger Units 3 and 4, PacifiCorp shall: (i) install SCR; (ii) install alternative
add-on NO* control systems; or (iii) otherwise reduce NO* emissions to achieve a 0.07
lbA{MBtu 30-day rolling average NO* emissions rate. These installations shall occur, and/or
this emission rate will be achieved, on Unit 3 prior to December 3 l, 2015 and Unit 4 prior to
December 31,2016. These installations shall occur, and/or this emission rate will be achieved,
in conjunction with PacifiCorp's planned overhaul schedule for these units and pursuant to a
construction or other permit application to be submitted by PacifiCorp to AQD no later than
December 31,2012.
8.3.4 Evaluation of Control Strategies for Sources Identified in the Reasonable Progress -
Four-Factor Analysis
The previous chapter evaluated certain non-BART sources through a four-factor analysis for
additional controls, as was required by the Federal Regional Haze Rule. This evaluation was
limited, in that no guidance was provided for identifuing "significant sources", and no
contribution to visibility impairment thresholds were established (a potential fifth factor). The
Division applied a "Quantity over Distance" (Q/D) process for screening out the most significant
stationary source contributors, but that was only the first step in identifting control options. The
Air Quality Administrator cannot, per Wyoming Statute 35-ll-202, establish emission control
requirements except through State rule or regulation. Furthermore, the Wyoming statute requires
the Administrator to consider the character and degree of injury of the emissions involved. In
this case, visibility modeling would be required to assess the degree of injury caused by the
emissions. Modeling is not available at this time to determine impacts from emission reduction.
The State believes it has taken a strong and reasonable first step in identifying potential
contributors to visibility impairment, and that the next step of creating an appropriate rule or
regulation will be accomplished in the next SIP revision. The visibility progress was designed as
a long-term program going out to2064.
8.3.5 Oil and Gas
As discussed in Section 7.3.5, oil and gas production, which is not limited to just one area of
Wyoming, is a large, important, and critical component of the State economy. However, the
sources associated with oil and gas production emit NO*, and to a lesser extent, PM. An
extensive fleet of field equipment and an array of processing plants operate continuously
conducting exploration, production, and gathering activities. Exploration and drilling includes
seismic studies, engineering, well testing, drilling operations, and transportation of personnel or
equipment to and from sites. Oil and gas production includes operation, maintenance, and
servicing of production properties, including transportation to and from sites. Sources include
turbines, drill rig engines, glycol dehydrators, amine treatment units, flares and incinerators.
Understanding the sources and volume of emissions at oil and gas production sites is key to
recognizing the impact that these emissions have on visibility. To better understand the
emissions from these sources, the WRAP instituted a three-phase project. One of the issues was
Exhibit No. 4
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r69
to quantiff emission inventories from stationary and mobile equipment operated as part of oil
and gas field operations.
Phase I, which was completed in 2005, was an emission inventory project that estimated regional
emissions from oil and gas field operations. Phase II, completed in late 2007, was an effort to
more fully characterize the oil and gas field operations emissions. Phase III which began in late
2007 with the Independent Petroleum Association of Mountain States (IPAMS) in conjunction
with WRAP initiating a regional oil and gas emission inventory project is underway. The
Division cannot complete the evaluation of oil and gas on visibility until this study has been
completed.
8.3.6 Projection of the Net Effect on Visibility
The WRAP has projected the net effect on visibility from emission reductions by point, area and
mobile sources throughout the WRAP region through 2018. The first emission projection
inventory was compiled in 2006. The inventory was revised in2007 to make preliminary
evaluations of reasonable progress towards Class I areas visibility goals. The 2007 inventory
focused on the most significant point and area sources of visibility impairing pollution in states
and Native American Reservations. This effort included updating projections of electric
generating units and incorporating known and presumed BART emission levels. Then, in the
spring of 2009, the WRAP once again updated emission inventory projections for point and area
sources in the WRAP region to give the most current assessment of reasonable progress towards
visibility goals. Again, the updated projection inventory reflected new information about BART
determinations and projection of future fossil fuel plants needed to achieve 2018 Federal
electrical generation demands. More information on the specifics of the most recent emission
inventory work collected for the 2018 visibility projections is contained in Chapter 4 of the
Wyoming TSD in the April 29,2009 ERG Technical Memorandum.
Chapter 5 of this Plan shows the specific results of the CMAQ modeling which was used to
make all projections of visibility. Those results show anthropogenic emissions sources generally
declining across the West through 2018. However, natural sources such as wildfires and dust,
international sources in Mexico and Canada, globaltransport of emissions and offshore shipping
in the Pacific Ocean all appear to offset improvements in visibility from controls on manmade
sources. In spite of the large number of growing uncontrollable sources in the WRAP region,
however, Wyoming does see a net visibility improvement at the Wyoming Class I areas through
2018. The net effect of all of the reductions in the WRAP region, known at the time of the most
recent model run is demonstrated in the WRAP Class I Summary Tables shown below for each
of the Class I areas in Wyoming.
Exhibit No. 4
Case No. IPC-E-13-16
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Class I Area Visibility Summary: Grand Teton NP, WY: Red Rock Lakes
NWRW, MT: Teton W, WY: Yellowstone NP, WY
Visibility Conditions: Worst 20Yo Days
RRF Calculation Method: Specific Days (EPA)
Emissions Scenarios: 2000-04 Baseline (plan02d) &2018 PRPb (prplSb)
Monitored Estimated Proiected
2000-04
Baseline
Conditions
(Mm-l)
2064
Natural
Conditions
(Mm-l)
2018
Uniform
Rate of
Progress
Target
(Mm-l)r
201 8
Projected
Visibility
Conditions
(Mm-l)
Baseline
to 2018
Change In
Statewide
Emissions
(tons / %o)
Baseline
to 2018
Change In
Upwind
Weighted
Emissions2
(o/"\
Baseline to
2018 Change
In
Anthropogenic
Upwind
Weighted
Emissions'
(o/"\
Sulfate 4.26 0.76 3.35 3.71
-22,794
-l5o/"-260/o -3zYo
Nitrate 1.77 0.63 1.5 1.36
-39,861
-l4o/o -26%-34o/o
Organic
Carbon 13.48 4.61 I 1.02 t2.87
-730
-3%-4o/"-29o/"
Elemental
Carbon 2.48 0.43 1.97 1.,
-1,217
-l5o/o tt%-5OYo
Fine Soil 0.95 t.02 0.97 1.04
5,223
3t%l4o/o 25o/o
Coarse
Material3 2.58 2.99 2.67 Not
Aoplicable
13,394
27o/o l9o/o 42o/o
Sea Salt3 0.02 0.03 0.02
Not Aoolicable
Total
Light
Extinction 34.55 19.47 30.25 32.77
Deciview t1.76 6.44 l0-52 tl.23
Table 8.3.6-1. Class I Area Visibility Summary for YF,LL2 onz0o/o Worst Days
I ) 20 I 8 Uniform Rate of Progress Target for Best 20o/o Days is not defined.
2) Results based on Weighted Emissions Potential analysis using the 2000-04 Baseline (plan02d) & 2018 PRPb (prp I 8b)
emissions scenarios.
3) Visibility projections not available due to model performance issues.
(WRAP TS S - http ://v i sta. cira. co I ostate. edu/tss/)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
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17t
Class I Area Visibility Summary: North Absaroka W, WY: Washakie W, WY
Visibility Conditions: Worst 20Yo Days
RRF Calculation Method: Specific Days (EPA)
Emissions Scenarios: 2000-04 Baseline (olan02d) &.2018 PRPb (nrol8b)
Monitored Estimated Proiected
2000-04
Baseline
Conditions
(Mm-l)
2064
Natural
Conditions
(Mm-l)
2018
Uniform
Rate of
Progress
Target
(Mm-l)l
2018
Projected
Visibility
Conditions
(Mm-l)
Baseline
to 2018
Change In
Statewide
Emissions
(tons / %)
Baseline
to 201 8
Change In
Upwind
Weighted
Emissions2
(%l
Baseline to
2018 Change
In
Anthropogenic
Upwind
Weighted
Emissions2
(o/"\
Sulfate 4.87 0.81 3.8 4.5
-22,794
-l5o/o -llo/o -t2%
Nitrate l.6l 0.75 1.4 1.29
-39,86r
-140/,-22o/o -28%
Organic
Carbon 11.64 4.62 9.75 lt
-730
-3Yo -5o/o -2t%
Elemental
Carbon 1.86 0.44 1.51 1.59
-1,217
-l5o/o -l7o/o -47o/o
Fine Soil 0.85 0.92 0.86 0.95
5,223
3lo/"170/,28%
Coarse
Material3 2.91 3.44 3.03 Not
Aoolicable
13,394
27%20%35%
Sea Salt3 0.01 0.03 0.01
Not Aoolicable
Total
Light
Extinction 32.74 20.02 29.21 31.25
Deciview I 1.45 6.83 10.38 ll
Table 8.3.6-2. Class I Area Visibility Summary for NOAB1 on20oh Worst Days
I ) 20 I 8 Uniform Rate of Progress Target for Best 207o Days is not defined.2) Results based on Weighted Emissions Potential analysis using the 2000-04 Baseline (planO2d) & 2018 PRPb (prp l8b)
emissions scenarios.
3) Visibility projections not available due to model performance issues.
(WRAP TS S - http ://vista.cira.colostate.edu/tssD
Exhibit No. 4
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Class I Area Visibility Summary: Bridger W, WY: Fitzpatrick W, WY
Visibility Conditions: Worst 20Yo Days
RRF Calculation Method: Specific Days (EPA)
Emissions Scenarios: 2000-04 Baseline (plan02d) &2018 PRPb (pml8b)
Monitored Estimated Proiected
2000-04
Baseline
Conditions
(Mm-l)
2064
Natural
Conditions
(Mm-l)
2018
Uniform
Rate of
Progress
Target
(Mm-l)r
2018
Projected
Visibility
Conditions
(Mm-l)
Baseline
to 2018
Change In
Statewide
Emissions
(tons / %)
Baseline
ro 2018
Change In
Upwind
Weighted
Emissions2
lo/"1
Baseline to
20lE Change
In
Anthropogenic
Upwind
Weighted
Emissions2
(o/"\
Sulfate 4.99 0.82 3.89 4.06
-22,794
-l5o/o -3lo/o -32o/o
Nitrate 1.43 0.79 1.27 1.24
-39,861
-14o/o -l9o/o -2lo/o
Organic
Carbon 10.55 4.64 8.98 10.31
-730
-3o/o -4Yo -l8o/o
Elemental
Carbon 1.99 0.39 1.59 t.77
-1,217
-l5Yo -l7o/"-5Oo/"
Fine Soil l.l 1.07 l.l l.l9
5,223
3lY"l3o/o 23%
Coarse
Material3 2.51 2.67 2.55 Not
Apolicable
13,394
27o/o l60/o 39o/o
Sea Salt3 0.04 0.04 0.04
Not Aoolicable
Total
Light
Extinction 3 1.6 19.42 28.23 30.12
Deciview I l.12 6.45 10.03 10.63
Table 8.3.6-3. Class I Area Visibility Summary for BRID1 ot20o/o Worst Days
I ) 20 I 8 Uniform Rate of Progress Target for Best 20Yo Days is not defined.
2) Results based on Weighted Emissions Potential analysis using the 2000-04 Baseline (plan02d) & 2018 PRPb (prplSb)
emissions scenarios.
3) Visibility projections not available due to model performance issues.
(WRAP TS S - http ://v i sta. cira. co lostate. edu/tssO
Exhibit No. 4
Case No. IPC-E-'|3-'16
T. Harvey, IPC
Page 183 of206
t73
Class I Area Visibility Summary: Grand Teton NP, WY: Red Rock Lakes
NWRW, MT: Teton W, WY: Yellowstone NP, WY
Visibility Conditions: Best 20Yo Days
RRF Calculation Method: Specific Days (EPA)
Emissions Scenarios: 2000-04 Baseline (planO2d) &,2018 PRPb (prplSb)
Monitored Estimated Proiected
2000-04
Baseline
Conditions
(Mm-l)
2064
Natural
Conditions
(Mm-l)
2018
Uniform
Rate of
Progress
Target
(Mm-l)r
20 l8
Projected
Visibility
Conditions
(Mm-l)
Baseline
ro 2018
Change In
Statewide
Emissions
(tons / oZ')
Baseline to
201 8
Change In
Upwind
Weighted
Emissions2
(o/o\
Baseline to
2018 Change
In
Anthropogenic
Upwind
Weighted.
Emissions'
(o/"\
Sulfate 1.47 0.33
Not
Aoolicable 1.43
-22,794
-l5o/o -20%-260/o
Nitrate 0.72 0.29
Not
Aoolicable 0.57
-39,86 I
-l4o/o -27%-360/o
Organic
Carbon l.l3 0.48
Not
Aoolicable l.l
-730
-3o/o -3%-28o/o
Elemental
Carbon 0.31 0.07
Not
Aoolicable 0.22
-r,2t7
-l5Yo -10%-5Oo/o
Fine Soil 0.1 0.08
Not
Aoolicable 0. l4
5,223
3lo/o l3o/o 25%
Coarse
Material3 0.24 0.2
Not
Aoolicable
Not
Aoolicable
13,394
27o/o l8o/o 44%
Sea Salt3 0.0r 0
Not
Aoolicable
Not Anolicable
Tot"al
Light
Extinction 12.99 10.45
Not
Aoolicable 12.71
Deciview 2.58 0.43
Not
Applicable 2.36
Table 8.3.6-4. Class I Area Visibility Summary for YELLZ on20yo Best Days
l) 20 I 8 Uniform Rate of Progress Target for Best 20%o Days is not defined.
2) Resuls based on Weighted Emissions Potential analysis using the 2000-M Baseline (plan02d) & 2018 PRPb (prplSb)
emissions scenarios.3) Visibility projections not available due to model performance issues.
(WRAP TS S - http ://vista.c ira. colostate. edu/tss/)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 184 of206
174
Class I Area Visibility Summary: North Absaroka W, WY: Washakie W, WY
Visibility Conditions: Best 20Yo Day s
RRF Calculation Method: Specific Days (EPA)
Emissions Scenarios: 2000-04 Baseline (plan02d) &,2018 PRPb (prplSb)
Monitored Estimated Proiected
2000-04
Baseline
Conditions
(Mm-l)
2064
Natural
Conditions
(Mm-l)
201 8
Uniform
Rate of
Progress
Target
(Mm-l)l
20r8
Projected
Visibility
Conditions
(Mm-l)
Baseline
to 2018
Change In
Statewide
Emissions
(tons / o/o)
Baseline
to 2018
Change In
Upwind
Weighted
Emissions2
(o/"\
Baseline to
2018 Change
In
Anthropogenic
Upwind
Weighted,2trmlsslons
(o/"\
Sulfate l.l I 0.27
Not
Aoolicable l.l
-22,794
-l5o/o -22o/o -24%
Nitrate 0.37 0.23
Not
Anolicable 0.33
-39,861
-l4o/o -28o/o -34Vo
Organic
Carbon 0.8 0.46
Not
Applicable 0.77
-730
-3o/o -60/"-23o/o
Elemental
Carbon 0.16 0.05
Not
Applicable 0.14
-1,217
-l5o/o -21%-50%
Fine Soil 0.12 0.1 I
Not
Aoplicable 0.15
5,223
3lo/o l6Yo 260/o
Coarse
Material3 o.7l 0.49
Not
Aoolicable
Not
Aoolicable
13,394
27%lg%o 40o/o
Sea Salts 0.02 0.02
Not
Aoolicable
Not Aoolicable
Total
Light
Extinction t2.28 10.61
Not
Aoolicable 12.22
Deciview 2.02 0.58
Not
Annlicahle r.97
Table 8.3.6-5. Class I Area Visibility Summary for NOAB1 on20yo Best Days
I ) 20 I 8 Uniform Rate of Progress Target for Best 20% Days is not defined.2) Resuls based on Weighted Emissions Potential analysis using the 2000-04 Baseline (planO2d) & 2018 PRPb (prpl Sb)
emissions scenarios.
3) Visibility projections not available due to model performance issues.
(WRAP TS S - http : //v i sta. c i ra. co lostate. edu/tss/)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 185 of 206
t75
Class I Area Visibility Summary: Bridger W, WY: Fitzpatrick W, WY
Visibility Conditions: Best 20Yo Days
RRF Calculation Method: Specific Days (EPA)
Emissions Scenarios: 2000-04 Baseline (olan02d) & 2018 PRPb (orolSb)
Monitored Estimated Proiected
2000-04
Baseline
Conditions
(Mm-l)
2064
Natural
Conditions
(Mm-l)
2018
Uniform
Rate of
Progress
Target
(Mm-l)l
2018
Projected
Visibility
Conditions
(Mm-1)
Baseline
to 2018
Change In
Statewide
Emissions
(tons / %)
Baseline
to 2018
Change In
Upwind
Weighted
Emissions2
(o/o\
Baseline to
2018 Change
In
Anthropogenic
Upwind
Weighted
Emissions'
(o/o\
Sulfate 1.45 0.28
Not
Anolicable 1.35
-22,794
-15%-3loa -33o/o
Nitrate 0.43 0.25
Not
Aoolicable 0.41
-39,861
-l4o/o -2lo/o -25o/o
Organic
Carbon 0.8 0.41
Not
Aoolicable 0.8
-730
-3o/o -5o/o -23o/o
Elemental
Carbon 0.36 0.08
Not
Aoolicable 0.29
-1,217
-l5o/o -2oo/o -53o/o
Fine Soil 0.09 0.07
Not
Aoolicable o.t2
5,223
3lo/o l3o/o 23o/o
Coarse
Material3 0.2s 0.2
Not
Aoolicable
Not
Applicable
13,394
27o/t l60/o 42o/o
Sea Salt3 0.01 0.0r
Not
Applicable
Not Applicable
Total
Light
Extinction t2.38 10.3
Not
Aoplicable 12.22
Deciview z.t 0.28
Not
Aoplicable 1.97
Table 8.3.6-6. Class I Area Visibility Summary for BRIDI on20oh Best Days
I ) 20 I 8 Uniform Rate of Progress Target for Best 20%o Days is not defi ned.
2) Results based on Weighted Emissions Potential analysis using the 2000-04 Baseline (plan02d) & 2018 PRPb (prpl8b)
emissions scenarios.
3) Visibility projections not available due to model performance issues.
(WRAP TSS - http://vista.cira.colostate.edu/tss/)
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 186 of 206
176
Since the Regional Haze process has proved to be much more complicated than the rule writers
ever imagined, the entire process has taken longer than originally estimated. While most east
coast states accepted EPA's determination that CAIR satisfied BART for electric generating
units, some westcrn states are still going through the difficult case-by-case BART determinations
for each EGU. As a result, the WRAP was not able to model all ofthe emission reductions from
BART and State long-term strategies in the most recent modeling effort. In the State of
Wyoming, significant additional NO* reductions will be made at the completion ofthe BART
and long-term strategy. The overall cumulative NO* reductions from Wyoming sources over
time are demonstrated in the figure below. Any additional future modeling will most likely
demonstrate additional progress towards the 2018 visibility goals.
8.3.G7. Additional Cumulative Reductions From Sources
70,0m
60,0@
50,0m
40,00
30,0m
20,0m
10,0m
0
I l-ong Term Strategy
r Non-EGU BART
r EGU BART
NO* Emission Reductions (tonsl
,et dl dl dP dI d9
"ot
d d'," ,,dP ,&t d| dP
"rtr
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 187 of206
177
CHAPTER 9
ONGOING MONITORING A}[D EMISSION INVENTORY STRATEGY
The State of Wyoming will rely upon a Regional Planning Organization's provision of adequate
technical support to meet its commitment to conduct the analyses necessary to meet the
requirements of 5 I .308(dX4).
The State of Wyoming will depend on the lnter-Agency Monitoring of PROtected Visual
Environments (IMPROVE) monitoring program to collect and report aerosol monitoring data for
long-term reasonable progress tracking as specified in 40 CFR 51.308(dX4) of the Regional
Haze Rule GHR). Because the RHR is a long-term tracking program with an implementation
period nominally set for 60 years, the Division expects that the IMPROVE program will provide
data based on the following goals:
l) Maintain a stable configuration of the individual monitors and sampling sites, and
stability in network operations for the purpose of continuity in tracking reasonable
progress trends;2) Assure sufficient data capture at each site of allvisibility-impairing species;3) Comply with EPA quality control and assurance requirements; and4) Prepare and disseminate periodic reports on IMPROVE program operations.
The State of Wyoming is relying on the IMPROVE program to meet these monitoring operation
and data collection goals, with the fundamental assumption that network data collection
operations will not change, or if changed, will remain directly comparable to those operated by
the IMPROVE program during the 2000-2004 RHR baseline period. Technical analyses and
reasonable progress goals in this Implementation Plan for Regional Haze are based on data from
these sites. As such, the State asks that the IMPROVE program identifu potential issues
affecting RHR implementation trends and/or notiff the State before changes in the IMPROVE
program affecting a RHR tracking site are made.
Further, the State of Wyoming notes that the human resources to operate these monitors are
provided by Federal Land Management agencies. Beyond that in-kind contribution, resources
for operation and sample analysis of a complete and representative monitoring network of these
long-term reasonable progress tracking sites by the IMPROVE program are a collaborative
responsibility of EPA, states, tribes, and FLMs and the IMPROVE program steering committee.
The State of Wyoming will collaborate with the EPA, FLMs, other states, tribes, and the
IMPROVE committee to assure adequate and representative data collection and reporting by the
IMPROVE program.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 188 of206
178
9-1. Links to Site Locations and Monitors
Site
Name Site Location Link
BRIDI VIEWS
WRAP TSS
IMPROVE
http://vista.cira.colostate.edu/views/Web/SiteBrowser/SiteBrowser.aspx
http://vista.cira.colostate.edu/TSS/Tool s/AOI.aspx
httn://vista cira-colostate edu/Datawarehouse/IMPROVII/Data/Photos/BRID/start-htm
NOABI VIEWS
WRAP TSS
http://vista.cira.colostate.edu/views/Web/SiteBrowser/SiteBrowser.aspx
httn ://vi sta -cira.colostate-edu/TSS/Too I s/AOI.asnx
YELL2 VIEWS
WRAP TSS
IMPROVE
http://vista.cira.colostate.edu/views/Web/SiteBrowser/SiteBrowser.aspx
http ://vista.cira.colostate.edu/TSS/Tools/AOI.aspx
httn://vista.cira.colostate.edu./Datawarehouse/IMPROVE/Data./Photos/YELL/stan.htm
Pursuant to 40 CFR 51.308(dx4)(i), the State of Wyoming depends on the following IMPROVE
program-operated monitors at the following sites for tracking RHR reasonable progress:
able 9-1. The W IMPROVE Mo Network
Site Code Class I Area Sponsor Elevation
(MSL)Start Date
BRIDI Bridger Wilderness
Fitzpatrick Wilderness USFS 2627 m
86r9 ft 3/211988
NOAB I
North Absaroka Wildemess
Washakie Wilderness USFS 2483 m
8146 ft v2512000
YELL2
Grand Teton National Park
Teton Wildemess
Yellowstone National Park
NPS 2425 m
7956 ft 71U1996
In accordance with provisions of 40 CFR 5l .308(d)(4)(ii), the State of Wyoming will use data
reported by the IMPROVE program as part of the regional technical support analysis tools found
at the Visibility Information Exchange Web System (VIEWS) and the Technical Support System
(TSS), as well as other analysis tools and efforts sponsored by a Regional Planning Organization.
Wyoming will participate in the ongoing regional analysis activities of a Regional Planning
Organization to collectively assess and verify the progress toward reasonable progress goals, also
supporting interstate consultation as the RHR is implemented, and collaborate with members of a
Regional Planning Organization to ensure the continued operation of these technical support
analysis tools and systems.
Wyoming may conduct additional analyses as needed.
The State of Wyoming will depend on the routine, timely reporting of haze monitoring data by
the IMPROVE program for the reasonable progress tracking sites to the EPA air quality data
systems, VIEWS and TSS as set forth in 40 CFR 5 1.308(dx4)(iv). The State of Wyoming will
collaborate with members of a Regional Planning Organization to ensure the continued operation
of these technical support analysis tools and systems.
Per requirements of 40 CFR 51.308(dx4)(v), the State of Wyoming has prepared a statewide
inventory of emissions that can reasonably be expected to cause or contribute to visibility
impairment in Federal Class I areas. Chapter 4 of this Plan summarizes the emissions by
pollutant and source category.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 189 of206
179
The State of Wyoming commits to updating statewide emissions periodically. The updates will
be used for state tracking of emission changes, trends, and input into a Regional Planning
Organization's evaluation of whether reasonable progress goals are being achieved and other
regional analyses. The inventories will be updated every three years on the same schedule as the
every three-year reporting required by EPA's Consolidated Emissions Reporting Rule.
As a member of a Regional Planning Organization, the State of Wyoming will use the Regional
Planning Organization-sponsored data system(s) to store and access emission inventory data for
the region. The State of Wyoming will also depend upon and participate in additional periodic
collective emissions inventory effons by a Regional Planning Organization. Further, the State of
Wyoming will depend on and use the capabilities of a Regional Planning Organization-
sponsored modeling center to simulate the air quality impacts of emissions for haze and other
related air quality planning purposes. The State of Wyoming will collaborate with members of a
Regional Planning Organization to ensure the continued operation of these technical support
analysis tools and systems.
The State of Wyoming, in accordance with provisions of 40 CFR 5l .308(dx4)(vi), will track
data related to RHR haze plan implementation for sources for which the State has regulatory
authority, and will depend on the IMPROVE program and a Regional Planning Organization-
sponsored collection and analysis efforts and data support systems for monitoring and emissions
inventory data, respectively. To ensure the availability of data and analyses to report on
visibility conditions and progress toward Class I area visibility goals, the State of Wyoming will
collaborate with members of a Regional Planning Organization to ensure the continued operation
of the IMPROVE program and RegionalPlanning Organization-sponsored technical support
analysis tools and systems.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 190 of206
180
CHAPTER 10
COMPREHENSIVE PERIODIC IMPLEMENTATION PLAI\ REVISIONS
40 CFR 5l.308(f) requires the Division to revise its RegionalHaze Implementation Plan and
submit a Plan revision to the USEPA by July 31, 2018 and every ten years thereafter. In
accordance with the requirements listed in Section 51.308(0 of the Federalrule for regional
haze, Wyoming commits to revising and submitting this Regional Haze Implementation Plan by
July 3 l, 20 I 8 and every ten years thereafter.
In addition, 51.308(9) requires periodic reports evaluating progress towards the reasonable
progress goals established for each mandatory Class I area. In accordance with the requirements
listed in 51.308(9) of the Federal rule for regional haze, the Division commits to submitting a
report on reasonable progress to the USEPA every five years following the initial submittal of
the SIP. The report will be in the form of a SIP revision. The reasonable progress report will
evaluate the progress made towards the reasonable progress goal for each mandatory Class I area
located within Wyoming and in each mandatory Class I area located outside Wyoming which
may be affected by emissions from within Wyoming.
The requirements listed in 51.308(9) include the following:
l. A description of the status of implementation of all measures included in the
implementation plan for achieving reasonable progress goals for mandatory Class I
Federal areas both within and outside the state;
Summary of emission reductions achieved thus far;
Assessment of changes in visibility conditions at each Class I area (current vs. baseline),
expressed as 5-year averages of annualvalues for least impaired and most impaired days;
Analysis of emissions changes over the 5-year period, identified by source or activity,
using the most recent updated emissions inventory;
Analysis of any significant changes in anthropogenic emissions in or out of the state
which have impeded progress;
Assessment of the sufficiency of the implementation plan to meet reasonable progress
goals;
Review of the State's visibility monitoring strategy and any modifications to the strategy
as necessary.
2.
3.
4.
5.
6.
7.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 191 of206
l8l
CHAPTER 11
WYOMING REGIONAL H.AZE SIP DEVELOPMENT AI\D
CONSULTATION PROCESS
11.1 State to State Consultation
Pursuant to 40 CFR Section 51.308(d)(iv), the State of Wyoming consulted with other states
through a regional planning organization, the Western Regional Air Partnership (WRAP), in
developing reasonable progress goals. The WRAP is a collaborative effort of tribal
governments, State governments and various Federal agencies to implement the Grand Canyon
Visibility Transport Commission's recommendations and to develop the technical and policy
tools needed by western states and tribes to comply with the U.S. EPA's regional haze
regulations. The WRAP is administered jointly by the Westem Governors' Association and the
National Tribal Environmental Council. WRAP activities are conducted by a network of
committees and forums composed of WRAP members and stakeholders who represent a wide
range of viewpoints. The WRAP recognizes that residents have the most to gain from improved
visibility and that many solutions are best implemented at the local, state, tribal or regional level
with public participation. The following states: Alaska, Arizona, California, Colorado, Idaho,
Montana, Nevada, New Mexico, North Dakot4 Oregon, South Dakota, Utah, Washington, and
Wyoming have agreed to work together to address regional haze in the Western United States.
The goals, objectives, management and decision making structure of the WRAP are described in
Work Plans and a Strategic Plan provided in Chapter I of the Wyoming TSD.
This consultation effort began with all states in the WRAP region contributing information to a
technical support system (TSS) which allows all states to better understand the causes of haze
and the levels of contribution from all sources to each Class I area. This project has involved
many hours of consultation between states on regional emission inventories, monitoring and
modeling to determine the causes of visibility impairment in each mandatory Class I Federal area
in the regional planning area. WRAP forums involved in the technical consultation between
states are as follows:
Air Pollution Prevention Forum
Dust Emissions Forum
Economic Analysis Forum
Emissions Forum
Fire Emissions Forum
Mobile Sources Forum
Sources In and Near Class I Areas Forum
Stationary Sources Forum
Technical Analysis Forum
The next step in state consultation in the development of reasonable progress goals was through
the Implementation Work Group (IWG) of the WRAP. The State of Wyoming participated in
the IWG which took the products of the technical consultation process discussed above and
developed a process for establishing reasonable progress goals in the Western Class I areas. A
description of that process and the determination of reasonable progress goals for each of the
Class I areas in the State of Wyoming is described in Chapter 7. The following states have
agreed to work together through the IWG in the development of reasonable progress goals:
Alaska, Arizona, California, Colorado, Hawaii, Idaho, Montana, Nevad4 New Mexico, North
Dakota, Oregon, South Dakota, Utah, Washington, and Wyoming.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 192 of206
t82
Opportunities for consultation on development of reasonable progress goals provided through the
WRAP Implementation Work Group have been documented in calls listed on the
Implementation Work Group section of the WRAP website at:
http ://www.wrapair.org/forums/iwg/meetin gs.html.
Pursuant to 40 CFR Section 5l.308(dXiv), the State of Wyoming also gave opportunity for
neighboring states to comment on the State of Wyoming's reasonable progress goals for each
Class I area located within the state. Opportunity for comment from other states was offered
through a public hearing on the State Implementation Plan (SIP), held in accordance with 40
CFR Section 51.102. The following states in the WRAP region were notified of the SIP public
hearing: Alaska, Arizona, California, Colorado, Idaho, Montana, New Mexico, North Dakota,
Oregon, South Dakota, Utah, Washington, Nevada, and Hawaii. The following states in the
neighboring Central States Regional Planning Organization (CENRAP) were notified of the SIP
public hearing: Iowa, Kansas, Minnesota, Missouri, Nebraska, Oklahom4 and Texas.
Consultation correspondence between Wyoming and other states will be included in Chapter 1l
of the Wyoming TSD. Comments were received from the following states, on the State of
Wyoming's reasonable progress goals for Class I areas located within the State of Wyoming.
The State of Wyoming took the following actions to resolve the disagreement:
The State of Wyoming did not receive any comments from other states indicating disagreement
on the reasonable progress goals established for the following Class I areas: Bridger Wilderness,
FiCIpatrick Wilderness, Grand Teton National Park, North Absaroka Wilderness, Teton
Wildemess, Washakie Wilderness, and Yellowstone National Park.
Pursuant to 40 CFR 51.308(dx3)(i), the State of Wyoming has participated in regional planning
and coordination with other states in developing emission management strategies if emissions
from within the state contribute to visibility impairment in a mandatory Class I Federal area
outside the state, or if emissions from another state, regional planning organization, country,
tribal area, or offshore location contribute to visibility impairment in any Class I Federal area
within the state. This participation was through the Western Regional Air Partnership (WRAP).
A more detailed description ofthe goals, objectives, management, and decision-making structure
of the WRAP has been included in Work Plans and a Strategic Plan provided in Chapter I of the
Wyoming TSD. The following WRAP forums have provided consultation opportunities betrveen
states on emission management strategies:
Air Pollution Prevention Forum
Dust Emissions Forum
Economic Analysis Forum
Emissions Forum
Fire Emissions Forum
Mobile Sources Forum
Sources In and Near Class I Areas Forum
Stationary Sources Forum
Technical Analysis Forum
Opportunities for consultation on emission strategies provided through the WRAP have been
documented in calls and meetings on the WRAP website at:
http ://www.wrapair.org/callcalendar.php.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 193 of 206
183
A description of the selected emission management strategies for the State of Wyoming is
described in Chapter 8 of this Plan. The State of Wyoming views the development of
coordinated emission management strategies to be a long-term commitment, and therefore, the
State of Wyoming agrees to continue to participate in the WRAP or an alternative Regional
Planning Organization in developing coordinated emission management strategies for SIP
revisions in 2013 and 2018.
Pursuant to 40 CFR 51.308(hX2), the State of Wyoming has determined this first State
Implementation Plan is adequate to ensure reasonable progress for the first planning period of the
regional haze long-term planning effort which extends out to the year 2064. While emissions
from sources outside of the State of Wyoming have resulted in a slower rate of improvement in
visibility than the rate that would be needed to attain natural conditions by 2064, most of these
emissions are beyond the control of any state in the regional planning area of the WRAP. The
emission sources include: emissions from outside the WRAP domain; emissions from Canada
and Mexico; emissions from wildfires and windblown dust; and emissions from offshore
shipping. A more detailed description and quantification of these uncontrolled emissions is
included in the Source Apportionment and Regional Haze Modeling chapter of this SIP.
Additional strategies to address emissions beyond the control of any state in the WRAP under
the jurisdiction of EPA are discussed in the Long-Term Strategy chapter of this SIP.
Through the WRAP consultation process the State of Wyoming has reviewed and analyzed the
contributions from other states that reasonably may cause or contribute to visibility impairment
in Wyoming's Class I areas. Wyoming acknowledges that the long-term strategies adopted by
Colorado, South Dakota, and Idaho in their SIPs and approved by EPA will include emission
reductions from a variety of sources that will reduce visibility impairment in Wyoming's Class I
areas.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 194 of 206
184
Figure Regional Planning Organizations
Regional Planning Organizations
- Regional
Air Planning
Association
Tnbllilu lmrouennnt
Sbb and trtdtAmcUiollh $on[prrt
11.2 State and Federal Land Manager Coordination
40 CFR Section 51.308(i) of the Regional Haze Rule requires coordination between states and
the Federal Land Managers (FLMs). Wyoming has provided agency contacts to the FLMs as
required under 5 I .308(i)( I ). During the development of this Plan, the FLMs were consulted in
accordance with the provisions of 51.308(i)(2).
Numerous opportunities were provided by the Western Regional Air Partnership for FLMs to
participate fully in the development of technical documents developed by the WRAP and
included in this Plan. This included the ability to review and comment on these analyses,
reports, and policies. A summary of WRAP-sponsored meetings and conference calls is
provided on the WRAP website at: http://www.wrapair.org/cal/calendar.pho.
The State of Wyoming has provided an opportunity for consultation, in person and at least 60
days prior to holding any public hearing on the SIP. As required by 40 CFR Section
51.308(iX3), the FLM comments and State responses, as well as email exchanges from the FLM
community to the Division explaining their review preferences ofthe SIP, will be included in
Chapter I I of the Wyoming TSD.
40 CFR Sections 51.308(f-h) establish requirements and timeframes for states to submit periodic
SIP revisions and progress reports that evaluate progress toward the reasonable progress goal for
each Class I area. As required by 40 CFR Section 51.308(D(4), Wyoming will continue to
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 195 of206
185
coordinate and consult with the FLMs during the development of these future progress reports
and Plan revisions, as well as during the implementation of programs having the potential to
contribute to visibility impairment in mandatory Class I areas. The progress and Plan reviews
are to occur at five-year intervals, with a progress report between each required Plan revision.
This consultation process shall provide on-going and timely opportunities to address the status of
the control programs identified in this SIP, the development of future assessments of sources and
impacts, and the development of additional control programs. The consultation will include the
status ofthe following specific implementation items:
L
2.
J.
4.
5.
6.
7.
Implementation of emissions strategies identified in the SIP as contributing to achieving
improvement in the worst-day visibility.
Summary of major new permits issued.
Stafus of State actions to meet commitments for completing any future assessments or
rulemakings on sources identified as likely contributors to visibility impairment, but not
directly addressed in the most recent SIP revision.
Any changes to the monitoring strategy or monitoring stations status that may affect
tracking of reasonable progress.
Work underway for preparing the 5-year review and/or l0-year revision.
Items for FLMs to consider or provide support for in preparation for any visibility
protection SIP revisions (based on a 5-year review orthe l0-year revision schedule under
EPA's RHR).
Summary of topics discussion (meetings, emails, other records) covered in ongoing
communications between the State and FLMs regarding implementation of the visibility
program.
The consultation will be coordinated with the designated visibility protection program
coordinators for the National Park Service, U.S. Fish and Wildlife Service, Bureau of Land
Management, and the U.S. Forest Service. At a minimum, the State of Wyoming will meet with
the Federal Land Managers on an annual basis through the Western Regional Air Partnership or
an alternative Regional Planning Organization.
11.3 Tribal Consultation
Although tribal consultation is not required under the RegionalHaze Rule, the Division views
this as an important part of the consultation process, and actively pursued this during the
development of the Regional Haze Plan. Not unlike the state consultation process, consultation
with tribes involved reviewing major emission sources and regionalhaze strategies to address
visibility issues. Consultation corespondence between Wyoming and tribal contacts will be
included in Chapter I I of the Wyoming TSD.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 196 of206
186
CHAPTER 12
DETERMINATION OF THE ADEQUACY OF TTIE EXISTING PLA}[
Depending on the findings of the five-year progress report, Wyoming commits to taking one of
the actions listed in 40 CFR 51.308(h). The findings of the five-year progress report will
determine which action is appropriate and necessary.
List of Possible Actions (40 CFR 51.308(h)
t.The Division determines that the existing SIP requires no further substantive revision in
order to achieve established goals. The Division provides to the EPA Administrator a
negative declaration that further revision of the SIP is not needed at this time.
The Division determines that the existing SIP may be inadequate to ensure reasonable
progress due to emissions from other states, which participated in the regional planning
process. The Division provides notification to the EPA Administrator and the states that
participated in regional planning. The Division collaborates with states and FLMs
through the regional planning process to address the SIP's deficiencies.
The Division determines that the current SIP may be inadequate to ensure reasonable
progress due to emissions from another country. The Division provides notification,
along with available information, to the EPA Administrator.
The Division determines that the existing SIP is inadequate to ensure reasonable progress
due to emissions within the state. The Division will consult with FLMs and revise its SIP
to address the Plan's deficiencies within one year.
2.
3.
4.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 197 of206
lE7
CHAPTER 13
TECHNICAL INFORMATION AND DATA RELIED UPON IN THIS PLAI\
This chapter describes the information relied upon by the Division in developing this Regional
Haze Plan. The first portion of this chapter describes the Westem Regional Air Pamnership
(WRAP) and the work products of this organization which have been utilized by the Division.
13.1 The WRAP and Technical Support
The WRAP is a voluntary organization of western states, tribes and Federal agencies which was
formed in 1997 as the successor to the Grand Canyon Visibility Transport Commission
(GCVTC). It is a regional planning organization that provides assistance to westem states like
Wyoming in the preparation and implementation of Regional Haze Plans. The WRAP is also
instigating regional planning processes to improve visibility in all Western Class I areas by
providing the technical and policy tools needed by states and tribes to implement the Federal
Regional Haze Rule. The WRAP is administered jointly by the Westem Governors' Association
(WGA) and the National Tribal Environmental Council (NTEC).
The WRAP is comprised of western states, tribes and Federal agencies. The states include
Alaska, Arizona, California, Colorado, Idaho, Montana, New Mexico, North Dakot4 Oregon,
South Dakota, Utah, Washington, and Wyoming. Tribal board members include Campo Band of
Kumeyaay Indians, Confederated Salish and Kootenai Tribes, Cortina Indian Rancheria, Hopi
Tribe, HualapaiNation of the Grand Canyon, Native Village of Shungnak, Nez Perce Tribe,
Northern Cheyenne Tribe, Orutsararmiut Native Council, Pueblo of Acom4 Pueblo of San
Felipe, Pueblo of Zuni, and Shoshone-Bannock Tribes of Fort Hall. Representatives of other
tribes participate on WRAP forums and committees. Participation is encouraged throughout the
western states and tribes. Federal participants include the Department of Interior (National Park
Service and Fish & Wildlife Service), the Department of Agriculture (Forest Service), and the
Environmental Protection Agency.
13.2 WRAP Committees and Work Groups
. Air Managers Committee
The Air Managers Committee (formerly the Northern Air Managers Committee) is made up of
state and tribal caucuses, each representing the interests of state and tribal air managers. The
committee is expected to provide air managers with a forum for discussing WRAP related
matters of concern to them. These matters may cover a spectrum of air quality issues. The
committee also provides a mechanism for communication and guidance to the technical and
policy forums as to what air managers believe is needed to support their regional planning
efforts.
o CommunicationsCommittee
The WRAP Communications Committee facilitates the exchange of information between the
standing committees and forums of the WRAP, and is also charged with developing materials
Exhibit No. 4
Case No.lPC-E-13-16
T. Harvey, IPC
Page 198 of206
188
that help the general public understand the WRAP process and take part in its decision making.
Some ofthe products of the Communications Committee have included outreach materials to
encourage direct participation, the development of internal and external communications plans
and the construction of the WRAP website.
o Planning Team
The Planning Team is convened as needed to address long-term planning and administrative
issues, such as annual WRAP work plans and the WRAP strategic plan. Some of the functions
performed by the Planning Team were previously performed by the Coordinating Group, which
no longer exists.
o Initiatives Oversight Committee
The Initiatives Oversight Committee (IOC) provides general oversight for the coordination and
development of air quality strategies necessary to promote the implementation of the Grand
Canyon Visibility Transport Commission's recommendations. The IOC oversees the
development of other air quality policies and strategies at the direction of the WRAP, refers
issues to forums, reviews recommendations from forums and makes recommendations to the
WRAP.
o Technical Oversight Committee
The Technical Oversight Committee (TOC) provides general oversight to the technical activities
of the WRAP. The TOC identifies technical issues and tasks necessary to support the activities
of the WRAP and refers these issues to the technical forums. The TOC identifies issues to be
addressed by the forums, based on input, priorities, and directions from the WRAP. The TOC
reviews any recommendations made by the forums and subsequently makes its own
recommendations to the WRAP.
. Implementation Work Group
The purpose of the WRAP Air Managers Committee Implementation Work Group is to help
states and tribes prepare their Regional Haze Implementation Plans to meet the requirements of
40 CFR 5 L308 and 401 CFR 51.309(9). The work group is comprised of state and tribal
representatives to accommodate the needs of states and tribes by recognizing the variety of
regulatory and statutory authorities and range of technical and policy expertise.
o Oil and Gas Emissions Work Group
Significant air pollutant emissions come from production of oil and gas from wells located on
state-regulated and tribal lands, as well as from the interconnected gathering networks interlacing
the WRAP region. These emissions result from operation of an extensive fleet of field
equipment and an array of processing plants, operating continuously across the West. These
field operations include exploration, production, and gathering activities.
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 199 of206
189
Historically, emissions from large stationary point sources processing this energy for the oil and
gas fuels markets were pretty well quantified through existing regulatory agency permitting
programs, but quite a number of pieces of smaller oil and gas field equipment (compressor
engines, drill rigs, heaters, dehydrators, flares, etc.) traditionally fell below agency permitting
thresholds. Although individual emissions from this field equipment could be considered minor,
with increasing energy demand and continuing oil and gas field development the cumulative
totals for oil and gas basins, producing states and the WRAP region as a whole were thought to
present an entirely different picture. But prior to WRAP involvement, present and future area
source emissions from western field oil and gas production operations were generally
incompletely quantifi ed.
The WRAP recognized this deficiency and formed the Oil and Gas Emissions Work Group to
look more closely at this industry and take steps to address the deficiencies. In late 2005 the
WRAP completed the Phase I oil and gas emission inventory project to estimate for the first
time, regional emission totals from these field operations. As a "first cut" Phase I had a number
of uncertainties identified, thus the work group subsequently initiated the Phase II project,
completed in fall 2007,to more fully characterize the oiland gas field operations emissions.
These WRAP inventories identified over 100,000 TPY of NO" emissions in the WRAP region
which had not previously been included in regional air quality assessments, as well as significant
totals of other air pollutant species (VOC's primarily) critical in the evaluation of regional haze
and other air quality management issues.
Members of the lndependent Petroleum Association of Mountain States (IPAMS) felt that still
more improvement in the accuracy of these emission estimates was needed and available. So in
late 2007 IPAMS initiated a Phase III regional oil and gas emission inventory project funded by
their organization. The project was undertaken in conjunction with the WRAP to assure that the
products from Phase III were widely distributed among non-industry stakeholders (state/local
agencies, tribal air programs, Federal Land Managers, environmental groups and EPA). This
wider participation was viewed as necessary to assure review and feedback such that the final
inventories were understood and more universally accepted by those parties interested in and
affected by oil and gas development in the Intermountain West.
. Tribal Data Development Work Group
The mission of this work group is to assist and advise WRAP on gathering tribal air quality data
and other air quality issues related to the WRAP mission from tribes in the WRAP area. They
work with the other WRAP forum and non-tribal communities to improve understanding
communities of protocols and processes for obtaining and using tribal data. In addition to
assisting in gathering existing air quality and air emissions data, this work group aids in devising
plans for filling the gaps in the tribal data.
Exhibit No. 4
Case No.IPC-E-13-16
T. Harvey, IPC
Page 200 of 206
190
13.3 WRAP Forums
o Air Pollution Prevention Forum
The Air Pollution Prevention Forum (AP2) was created by the WRAP to examine barriers to use
of renewable energy and energy efficient technologies, identiff actions to overcome such
barriers, and recommend potential renewable energy and energy efficiency programs and
policies that could result in a reduction of air pollution emissions from energy production and
energy end-use sectors in the Grand Canyon Visibility Transport Region.
o Dust Emissions Joint Forum
In the summer of 2002, the WRAP Oversight Committees established a Dust Emissions Joint
Forum to consolidate the WRAP's efforts involving dust. Previously, three forums had worked
on dust issues: the Mobile Sources Forum, the Research and Development Forum, and the
Emissions Forum. The new DEJF concentrates on improving how dust emissions are estimated
and subsequently treated by air quality models. The forum also examines strategies to
effectively reduce the impact of dust emissions on visibility in Class I areas.
o Economic Analysis Forum
The mission of the Economic Analysis Forum (EAF) is to provide the WRAP and WRAP
forums with projections of econometric parameters needed to forecast changes in emissions, and
assessments ofthe economic effects of pollution controls on the region and sub-regions,
including Indian Country. Specifically, the EAF is seeking to: develop a better definition of
what states, tribes and stakeholders expect from the economic analyses provided with WRAP
products; develop a common economic analysis framework, which will include incorporating
existing studies' economic analyses; assist states and tribes as they prepare their Implementation
Plans; and provide overall analytical support and analysis as states and tribes gage the economic
components of their Regional Haze Plans.
o Emissions Forum
The Emissions Forum oversees the development of a comprehensive emissions tracking and
forecasting system which can be utilized by the WRAP, or its member entities, monitors the
trends in actual emissions, and forecasts the anticipated emissions which will result from current
regulatory requirements and alternative control strategies. In addition, this forum is responsible
for the oversight of the assembly and quality assurance of the emissions inventories and forecasts
to be utilized by the WRAP forums.
o Fire Emissions Joint Forum
The Fire Emissions Joint Forum (FEJF) was formed to assist the WRAP in addressing the Grand
Canyon Visibility Transport Commission's (GCVTC) Recommendations on fire. The term fire
refers inclusively to wildfire, prescribed natural fire/wildland fire managed for resource benefits,
prescribed fire, and agricultural fire. The forum addresses a broad definition of smoke effects
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 201 of206
l9l
which includes consideration of public nuisance, public health and visibility/regional haze. The
FEJF follows its consensus based Work Plan which addresses four major topics.
Criteria for implementation of different stringencies of smoke management programs are being
developed as well as specific smoke management program elements. Fire emissions are being
directly assessed in terms of pollutant estimation methods, emission projections and tracking.
An assessment is being done of the potential applicability and utility of non-burning alternatives
to fire. The use of altematives and other emission reduction methods relates directly to the
potential application of annual emission goals.
A public education and outreach program related to fire and smoke effects is being developed.
All recommendations to the WRAP and methods developed by the forum are intended for
Westem U.S. application and represent a consensus of FEJF members. Collaboration and
cooperation with other entities addressing smoke management issues in the West have been
included in the Work Plan of the FEJF.
. Mobile Sources Forum
The Mobile Sources Forum (MSF) investigates and recommends mobile source emission control
measures. Mobile sources includes both on-road sources (e.g., cars, trucks, buses, and
motorcycles) and off-road sources (e.g., aircraft and its support equipment, locomotives,
commercial marine and pleasure craft, and equipment used for construction, logging, mining,
agriculture, and lawn and garden care). Since emission standards for new on-road and off-road
sources can only be set by the U.S. EPA (on-road standards can also be set by California), the
MSF focuses more on the impact and treatment of existing sources, especially off-road sources.
The MSF also participates in technical activities related to mobile sources. During its first
couple of years (2000-02), the MSF led the development of a WRAP-wide mobile source
emission inventory and worked with the Air Quality Modeling Forum to define and analyze the
significance of mobile sources with respect to the requirements of $309 of the Regional Haze
Rule.
o Sources In and Near Class I Areas Forum
The Grand Canyon Visibility Transportation Commission (GCVTC) developed
recommendations to address emissions from sources in and near Class I areas on the Colorado
Plateau. The Sources In and Near Class I Areas Forum (In and Near Forum) helps implement
those recommendations by working with parks and local communities to develop and implement
strategies to minimize emissions and the resulting visibility impacts.
o Stationary Sources Joint Forum
The Stationary Sources Joint Forum (SSJF) was established in January 2004 and replaces the
Market Trading Forum (MTF). The SSJF focuses more broadly on stationary source issues
throughout the WRAP and their relationship to Section 308 SIP requirements. Major topics for
the SSJF include BART, reasonable progress for stationary sources, technical analyses, and
Exhibit No. 4
Case No.lPC-E-'|3-16
T. Harvey, IPC
Page 202 ot 2OG
192
evaluating the effect of and integration with other regulatory and legislative developments at the
national level.
o Technical Analysis Forum
The TAF coordinates and manages the processing, display, delivery, and explanation of technical
data for regional haze planning activities. The TAF assumes responsibility for combining the
participants and maintaining the activities and ongoing projects of the Ambient Air Monitoring
& Reporting Forum, the Air Quality Modeling Forum, and the Attribution of Haze Workgroup.
13.4 WRAP TSS
The primary purpose of the TSS is to provide key summary analytical results and methods
documentation for the required technical elements of the Regional Haze Rule, to support the
preparation, completion, evaluation, and implementation ofthe Regional Haze Implementation
Plans to improve visibility in Class I areas. The TSS provides technical results prepared using a
regional approach, to include summaries and analysis of the comprehensive datasets used to
identify the sources and regions contributing to regional haze in the Western Regional Air
Partnership (WRAP) region.
The secondary purpose ofthe TSS is to be the one-stop-shop for access, visualization, analysis,
and retrieval of the technical data and regional analyical results prepared by WRAP Forums and
Workgroups in support of regional haze planning in the West. The TSS specifically summarizes
results and consolidates information about air quality monitoring, meteorological and receptor
modeling data analyses, emissions inventories and models, and gridded air quality/visibility
regional modeling simulations. These copious and diverse data are integrated for application to
air quality planning purposes by prioritizing and refining key information and results into
explanatory tools. A detailed description of the TSS website, "WRAP Technical Support System
Web Site Description (November 16,2009 Draft)", can be found in Chapter l3 of the Wyoming
TSD.
13.5 IMPROVE Monitoring
13.5.1 Background on IMPROVE Monitoring
The Interagency Monitoring of Protected VisualEnvironments (IMPROVE) program is a
cooperative measurement effort governed by a steering committee composed of representatives
frorn Federal and regional-state organizations. The IMPROVE monitoring program was
established in 1985 to aid the creation of Federal and State lmplementation Plans for the
protection of visibility in Class I areas (156 nationalparks and wilderness areas) as stipulated in
the 1977 amendments to the Clean Air Act.
The objectives of IMPROVE are: (l) to establish current visibility and aerosol conditions in
mandatory Class I areas; (2) to identiff chemical species and emission sources responsible for
existing man-made visibility impairment; (3) to document long-term trends for assessing
progress towards the national visibility goal; (4) and with the enactment of the Regional Haze
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 203 of 206
193
Rule, to provide regional haze monitoring representing all visibility-protected Federal Class I
areas where practical. IMPROVE has also been a key participant in visibility-related research,
including the advancement of monitoring instrumentation, analysis techniques, visibility
modeling, policy formulation and source attribution field studies.
An IMPROVE sampler, depicted below, consists of four separate modules used for collecting the
various pollutant species.
Figure 13.5.1-1. Schematic of the IMPROVE Sampler Showing the Four
Modules With Separate Inlets and Pumps
(http://vista.cira.colostate.edu/improve/Overview/lMPROVEProgram files/frame.htm)
The IMPROVE monitoring network consists of aerosol and optical samplers. The network
began operating in 1988 with 20 monitoring sites in Class I areas. By 1999 the network
expanded to 30 monitoring sites in Class I areas and 40 sites using IMPROVE site and sampling
protocols operated by Federal and State agencies. With the enactment ofthe Regional Haze
Rules the IMPROVE network has been expanded by 80 new sites. Photographs of Wyoming
Class I area IMPROVE monitoring sites are provided in Chapter 2.
13.6 Formula for Reconstructed Light Extinction
The IMPROVE program has developed methods for estimating light extinction from speciated
aerosol and relative humidity data. The three most common metrics used to describe visibility
impairment are:
along a sight path due to scattering and absorption by gases and particles, expressed in
inverse Megameters (Mm-t). This metric is useful for representing the contribution of
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 2M of 206
Module B
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srlto,
ntril8
iror
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Ptle.S
(Tffiil
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oaamorill
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194
each aerosol species to visibility impairment and can be practically thought of as the units
of light lost in a million meter distance.
seen on the horizon, expressed in kilometers (km) or miles (mi).
Rule. The deciview index was designed to be linear with respect to human perception of
visibility. A one deciview change is approximately equivalent to a l0Yo change in
extinction, whether visibility is good or poor. A one deciview change in visibility is
generally considered to be the minimum change the average person can detect with the
naked eye.
The IMPROVE network estimates light extinction based upon the measured mass of various
contributing aerosol species. EPA's 2003 guidance for calculating light extinction is based on
the original protocol defined by the IMPROVE program in 1988. (For further information, see
http://vista.cira.colostate.edu/improve/Publications/GuidanceDocs/guidancedocs.htm.) In
December 2005, the IMPROVE Steering Committee voted to adopt a revised algorithm for use
by IMPROVE as an alternative to the original approach.
The revised algorithm for estimating light extinction is calculated as recommended for use by the
IMPROVE steering committee using the following equations:
b",,= 2.2 x f,(RH) x [Small Amm. Sulfate] + 4.8 x fLGH) x [Large Amm. Sulfate]
+ 2.4 x fi(RH) x [Small Amm. Nitrate] + 5.1 x f1(RH) x [Large Amm. Nitrate]
+ 2.8 x [Small POM] + 6.1 x [Large POM]
+ l0 x [EC]
+ I x [Soil]
+ 1.7 x f,.(RH) x [Sea Salt]
+ 0.6 x [CM]
+ 0.33 x [NOz(pnb)J
+ Rayleigh Scattering (Site Specific)
The revised algorithm splits ammonium sulfate, ammonium nitrate, and POM concentrations
into small and large size fractions as follows:
lE*c"l= tr#lx[roat]
For [Total]< 20pg,'m]i
l$-r,t = [rotar] - [r-arg€]
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 205 of 206
Fo,r [Total] r 20pgimr. [Large] = [rotat]
195
13.7 Wyoming IMPROVE Monitoring Network
In Wyoming there are three IMPROVE monitors which are described in the table below. There
are seven Class I areas in Wyoming; therefore, some monitors serve multiple Class I areas.
Although it is desirable to have one monitor for each Class I area" in most cases one monitor is
"representative" of haze conditions in nearby Class I areas. Locations and descriptions of the
IMPROVE monitors were presented in Chapter 2.
Table 13.7-1. The IMPROVE Monitori Network
2627 m
8619 ft
North Absaroka Wilderness
Washakie Wilderness
Grand Teton National Park
Teton Wilderness
Yellowstone National Park
2425 m
7956ft
Exhibit No. 4
Case No. IPC-E-13-16
T. Harvey, IPC
Page 206 of 206
196
FinalReport
Coal Environmental Compliance
Upgrade I nvestment Evaluation
ldalp Power Company
February8,2013
$ aurEifg5n
6-=-E ZPC
Exhibit No. 5A
Case No. IPC-E-I3-16
T. Harvey, IPC
Page I of 52
5AIE,,
Exhibit No.5A
Case No. IPGE-13-16
T. Harvey, IPC
Page 2 of 52
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Exhibit No.5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 3 of 52
Coal Environmental Compliance Upgrade lnvestment
Evaluation
ldaho Power Company
TrUe of Conbnts
Table of C.ontenu
List of Tables
List ofFigures
Section I BACKGROUNI)
Section 2 ENVIROI\IMENTAL COST AND PERFORMAI\ICE
REYIEW2.1 lohoduction. .........2-L2.2 Jim Bridger.. .........2-l2.3 NorthValmy ........2-3
Scction 3 STITDY DEFINITION AND METHOITOLOGY $t
3.1 Intnoduction. .........3-t3.2 Sscmarios and Sensitivities..........,......... .........3-l
3.2.1 Scenarios..... ..................3-l
3.2.2 Seirsitivities. ..........--...,..3-6
3.3 Analysis Methodology ..-..-.......3-8
3.3.1 Stndy Period and Replace,ment Capacity...... .......... 3-8
3.3,2 Fuel, Start Charges, and Emissions costs.............,..,.................... 3-9
3.3.3 Capital andO&Mcosts................. .....3-9
3.3.4 Net Present Value ('NPV") analysis ..............,.....3-t0
Section 4 OPTIONAL ANALY$S RESULTS 1-r
1-l
2-l
5AIC.
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 4 of 52
Fib: !1532040?
TaUe of Contents
Sectlon 5 CONCLUSIONS........ ...,.......-.....5-l
5.1.1 North Valmy .....,........... 5-2
5.1.2 Jim Bridger. .................. 5-3
5.1.3 Conclusions. ..................5-3
Listof AppendLrcsA Principle Considcrations and Assumptions
Listof Tables
Table 4-l PresentValue of PowerCostby Sceoario ($2013 M)....................,..-.......4-l
Tablo 4-2 Prps€Nrt Value Powcr Cost Dcltas by Sccnario ($2013 M End o/o)....,.......,. $2
Table 4-3 Jim BridgprUnit I -Total Costs NPV ($2013M) ................ +3
Table 44 Iim Bridger Unit 2 -Toal Costs NPV (32013 M) ...........................,........ &5
Table 4-5 Jim BridgerUnit 3 -Toal Cose NPV (S2013 M) .......,.............,..............46
Table 4-6 Jim Bridger Unit 4 - Total Costs NPV ($2013 M) .................................... +8
Table 4-7. North Valmy Unit I - Totrl Costs NPV ($2013 M) ................................. 4-9
Table 4-E. North VaLny Unit 2 - Total Coss NPV ($2013 M) -.............................. 4-l I
List of Fignres
Figurc +1. Jim BridgerUnit I Plaming Case -Total Costs ........... .....4-3
Figure 4-2. limBridger Unit I All Cases - Totd Costs.. ..................... 44
Figurc +3. Jim Bridger Unit 2 Planning Case - Total Costs ........... ....44
Frgure 4-4. Jim Bridgu Unit 2 All Ccs€s - Total Costs........... ..,..,..,...4.5
Figure 4-5. Jim Bridger Unit 3 Pluning Case - Total Costs ....-.......... 4-6
Figure 46. Jim Bridger Unit 3 All Cascs - Total Costs........... ........,,-.4-7
Fignre 4-7 . llm Bridger Unit 4 Plamiqg Case - Total Costs ........... ....4-7
Figure 4-8. Jim Bridger Unit 4 All Cases - Total Costs...... .................4-E
Figure 4-9. North Vahny [Jai[ [ planning Case - Total Costs.................................. 4-9
Figwe 4-10. Nor& Vatny Unit I All Cases - Total Costs............ ..... +t0
Figure4-ll. NorthValmyUnit2PlanningCssc-Tote!Costs..,...........................4-10
Figure 4-12. North Valmy Unit 2 All Cases - Total Costs............ ..... 4-l I
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 5 of 52
Iv SAIC Energy, Enviroonrcat & Infrastructurc, LI,C
Section 1
BACKGROUND
1.1 lntroduction
Like many utilities around the country, Idaho Power Company ("IPC') is frcing
signifrcant decisions regarding its generation portfolio. Recent and pending
Environmental Protection Agency ("EPA') regulations could require substantial
capital invesbrent at the Jim Bridger Plant ('Jim Bridgc/) and North Valmy
Generation Shtion ('North Vatny') ooal-fired power plants to remain in
environmeirtal compliance. IPC decided to conduct a plmning level study of the
relative costs and benefits of cither making sigoificant e,nvironmental investments in
additional emissions control equipment, or retiring affected uniB at the plants and
replacurg thsn with alterna.te geireration capacity. IPC engaged SAIC Energy,
Environment & Infrastmcture, LLC ('SAIC') to conduct this study and identi$ which
options were likcly to be the most cost effective nrd warrant further sMy.
SAIC has a designatod Soup of ecouomists, e.ngineers, analysts, and other
professionals who provide a range of energy resouroe plaming and advisory services.
We have a long history of providing independent e,ngineering sernices to project
dwelopers and finenciers for hrmdreds of power plants in the U.S. and around the
world; our independent cngine€ring tearirs ar€ widely aclnowlcdged in the power
supply industry as being industry leaders in providing unbiased and technically
superior services. SAIC's utilities consulting group has combined financial and
planning insights with robust analytical skills to assist hundneds of utilities with
planning efforts, spanning from individual project decisions to comprehe,nsive
Integrated Resource Plans. SAIC applied ow expertise and experieiroe to rcview and
comment on IPC's inveshsnt decisions rclating to either upgrading its coal units,
convening them to burn natrral gas, pursring a retiremem.t and replacement stategy,
oi somc combination of'rhese options.
1.2 Objectives
In its 20 I I lntegrated Resource Plan ("IRP"), IPC identified a number of pendiag EPA
regulations which may affect the Jim Bridger and Norft Valmy plauts. However, at
the time of the development of the IRP, many of those environme,ntal regulations had
not yct been issued by tbe EPA. While several of the appticabtc environmental
regutations have faced legal challenges, IPC desired a shrdy which examines the costs
of envimnmental upgrades raquired for compliance under the as currently
proposod. Specifically, IPC had the following objeotives for the study:
r Review IPC's assumptions regarding the capital cost assumptions of the
proposed environmental compliance upgrades, including Selective Catalytic
Reduction C'SCR'), Dry Sorbeil lnjectiou ("DSI'J, Wet Flue Gas
5AIE,.
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 6 of 52
Filc:115320200?
Secdon 1
Desulfurization (*WFGD), and other syst€ms, as well as the costs of
rcplacemcnt capacity.
r Review IPC's assumptions regarding ths variable cost assumptions of the
propos€d envirormeirtal compliance upgrades and rcplacanent capacity,
r Develop estimstes of &e costs for each unit going forward, insluding total cosE
reflecting environmental compliance upgade investments as well as btal
replacement oapacity costs.
. Provide conclusions as to the economic feasibility of the environmeatal
cornpliance upgndes and retirement options.
This Coal Envirronmental Compliaace Upgrade Investneat Evaluation Report
(the *Report'') provides the results of the SAIC tudy.
1.3 Approach
At this stagc of thc decision prcc€ssi SAIC felt that due to the uncertrinties involvedh the futur€ envircnnrental regulations, capital , and firel brmasts, a
planning lcvel strdy was ths most appropriatc ryproach. This study examined ttrc
likely ranges of costs involved with th€ relwant o,ptions idcntified for each unit, based
on a simplified analysis of the costs of gene,ration ficr each of those options.
The study idenffied a total of 2l options involving the six Jim Bridger and
NorthValmy rmits, ranging from minimum to enhanced envimnmental compliaoce
rpgrades, fuel swirching to natural gas, and retireme,lrt of the unie. SAIC aflabrz€d the
scenarios under a vari€ty of potential fuel and carton omts, to clomiuc the sensitivity
of each option to changes in future assuurptions. The following fotutasks describe the
sildy approach:
Trrk 1: Scenario and Senritivity ldentlficrdon. SAIC mct with IPC staffto
discuss thc objectives oftte sfirdy and to identi$ the appropriate options to
analyze for each unit. A nrmrber of scenarios were initially idcntified for each
unit, including minimum compliance eovfuonm€ntal Wgrades for atl uaits, and
enhanced oompliance upgrades for the North Valmy units. After oonsidering
several different types of replaccment capacity for both the Jim Bridger and
North Valmy trnits, SAIC and tPC mutr:ally agreed to limit tho replacement
capacity units to natrral gas fired combined cycle units. Furdrcr, to insrease
the analysis to include a wider range of possible outcomeq SAIC and IPC
decided to evaluatc the potantial convemion of all four Jim Bridga Units from
coal fired boilers to nitural gas fired boilers. Eventually the potential natural
ges conversion scenarios were erganded to include &e Nortr Valmy I & 2
units.
The potential envircnme,nhl compliance upgrade, fuel switching, ard
retirement scenarios addressed msny of thc urrcertainties in futur€
environmental regulations, SAIC and IPC also decided to include sensitivities
desigrred to address the uncertainties involved in forecasting natunal gas prices
as well as possible oarbon regulation compliance costs. Ultimately, SAIC
Exhibit No. 5A
Case No. IPC-E-1&16
T. Harvey, IPC
PageT of 52
l-2 SAIC Energy, Environment & hfrs,structulp, LLC
BACKGROUND
subjected each of the scenarios descriH above to nine different combinations
of low case, planning case, and high case projections for both natrual gas
prioes and carton compliance oosts.
Trsk 2: Envlronmentel Cortr end Performance Review. SAIC examined
the emissions profile of each unit, md addresscd the adequacy of proposed
environmental upgrades to address envircngrental corylimce. Additionally,
SAIC reviewed the proposed capital aad variable costs for cach upgnde to
determine whethcr the identified costs wers within the reasonably expected
range for guch costB.
Trsk 3: Options Analysls. [FC's primary goal for this study was to
specific direction regarding upgrading each of the units at Norttr Valrny aod
Jim Bridger. SAIC used qrtansivc forecast and operational data provided by
IPC for each of the units to compile a compreheosive analysis of each option's
total costs for the duration of thc appropriate tirne horizon. Thcse oosts were
then compared to other options for each unit on a net present value basis.
Tlsk 4: Summary. The results and conolusions of the analysis were compiled
in a draft rcport and reviewed intcraally by IPC and SAIC for quality
assurarrcc. Results wcre then compiled and providcd in this Report Results
also have bcsn oommunicated in various conversations betrnreen SAIC tearn
members and IPC.
The Report contains fivc Sections:
Sectlon 1 contains an introduction and background-
Sectlon 2 provides the resulg of the
Review.
Section 3 addresses the Options Alalysis, and describes &e methodology alrd
primary assumptions used in the Analysis.
Section 4 provides the results of the Options Analysis.
Section 5 provides the conclusions of the study.
A detailed Bummary of the assumptions used in the analysis is included in
Appendix A.
This Report suumarizes tlre results of our investigations and analyses up to 0re date of
this Report Changed conditions occuring or becoming lnown after such date could
affect the material presented hcrein to the extcnt of such changes. Nothing contained
in this Report is intended to indicate conditions with respect to safoty or to security
regarding the proposed upgrades or to conformanoe wifi agrocments, codes, pernrits,
rules, or regulations of any party having jwisdiction with respect to the constnrctior,
operatiou, and marnterarce of the Jim Bridger and North Valmy plants, which matters
are outside the scope andpurposes of this Repot
SAIC Encrgy, Environment & Inta$ructure, LLC l-3
Envimnmental Cost and Performmce
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page I of 52
Filc: 31532)200?
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page I of 52
Section 2
ENVIRONMENTAL COST AND PERFORMANCE REVIEW
2.1 lntroduction
Coal-fired as well as other electic power generating units must comply with various
environmental laws and regulations depending on their size, location, and fuel
characteristiss. In the case of the Jim Bridger and North VaLny uniB, these
regulations includc thc Mercury and Air Toxics Rule ("MATS') published by the
Unit€d States Environmental Protection Agency ("USEPA') February 16, 2012, and
the state of Wyoming's rogulations addnessing USEPA's rcgronal haze nrles.
Other proposed or potential environmental regulations that could impact IPC's coa[-
fired generating plants include the Clean Water Act Section 316(b) regulatiors, Coal
Combustion Residuals ("CCR) environmental regulations, and carbon
tegislation/regulation. Such proposed or potential regulations could rcquire additioual
capital expenditures and an increase in thc Fixed and Variable Operatiou and
Maintenance ("O&Ilf') costs of affecrcd generating units.. Compliance with these
environmental regulatory changes could also impact the efficicncy or heot rate of
affccted units.
SAIC reviewed the projected capital and O&M costs for the retrofit of cnvfuonmental
controls io comply with the MATS and regional hrze rules for Jim Bridger nnd thc
projected capital and O&M costs for the retrofit of environmental controls to comply
with MATS for the North Valmy Unit I ("NVl"). Additionally, as a possible
enhanced environmental compliance case, we reviewed the projected capital and
O&M costs associated with possible SCR and WFGD syste,ms for both North Valmy
urits.
2.2 Jim Bridger
Based on information provided by IPC, the Jim Bridger units are currently equrpped
with sulfur dioxide f'SOz") scrubbers for the conhol of SOz and electrostatic
precipitaton ("ESPs") for the contol of particulates. [t is our understanding that the
SO: emission rate during 2010 and 201I was below 0.2 pounds per million Btu
(*lby'MMBtu"), which is the limit set MATS forth in fre rule for compliance with acid
gases (0.18 lbA{MBm for 2010 and 0.15 lb^tMBtu for 20ll). SG: can be used as a
surrogate for meeting acid gas emissions limits.
It is also our understanding that Jim Bridger will require additional controls to comply
with mercury limits as well as SCR systems to rcdrrce the emissions of nitroge,n oxide
("NO*"). PacifiColp, in conjunction with the Wyoming Department of Environmental
Quality, agreed to install SCRs on Units 3 and 4 and potentially Units I and 2 in order
to allow a path for timely submittal of the state's Regional Haze Implenrentation Plan
(RH FIP) in January 201 l. For the purposes of this ReporL the installation of the
5AIE.
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page10of52
File:3153202007
Section 2
SCRs for Unib 3 and 4 are planned for 2015 and 2016, respectively. The EPA
announccd thrt it would re-propose &e plant-specific NOx control provisions of its
RII FIP in March 2013 and would not finalize the RH FIP until Septerrber 2013. At
the present time, an SCR retrofit for Unit 2 is planned for202l and for Unit I in 2022.
IPC provided the following estimated r€tnofit costs for tlrc Jim Bridger SCR retofits;
it is SAIC's understanding &at these estimitc were originally provided to IPC by
PacifiCorp, dre majority owncr of Jim Bridgcr. Note tbrt these figures rcpresent the
total costs for the Jim Bridger upgrades in nominal dollars; the tPC shar€ of these
costs is 33 perceat. The btal costs including Allowaoce Ftmds During Constnrction
C'AFUDC') arc discussed below for the purposes of evaluating their reasonsblcness,
while the IPC share of the costs were used in the anatysis os desc,ribed in Section 3 of
the Report.
! unitteozz)--
r Unitz(zozD-I
. unit3(2ols)-fr Unit4(2016)-I
The above cosB are in the range of apprcximarcly
The estimates appoar to be adequatc for the
the trp,per end of the range of retrofit costs for similar unie with which wc are frmiliar;
without performing deail€d, line itqn engineering reviens of the IPC estimates, SAIC
camot refine that opinion firrther. Based on SAIC's ercperieoce in Foviding
independent and owner's engineering services for a wide varicty of similu retrofit
5i:},"*;-'#f ,.iffi'T".,"ffi tll.?ff ',ilT"#,,f.l*ffi';:-Greplacecrent costs every two !o three years). Ths IPC cost estimat$ for variable O&M
associated with the SCRs fatl within the range of I[tdWh. Bascd on the
information provided by IPC, in SAIC's opinion the SCR instillations for Jim Bridger
should be suffrsient to oonEol the plant's NOx emissiotrs to a lwel consistent with
Wyoming's regional haze implementation plan.
A control systcm (scnrtiber additives with calcium bromide and possibly powder
acdvated carbon) is proposed for the cornpliance of mercury ernissions rilift MATS
regulations. The system is proposed for all four units, to be insalled in 2014. An
estimate of I (2015 dollars) rekofit capital cost was presurted by
PacifiCorp for all four rmits. This estimato appears adequate fior the installation of the
systerns and is in the t4rper mnge of retrofit cosb for similar uniB with which SAIC is
familiar O&M costs for the s]rstem are ostimated by SAIC ", I The
mercury control syst€,ln conterryletod for the Jim Bridger plant shofikffffiicient to
control the plant's mercury eraissions to a level consistcnt with the MATS rule.
In addition to the SCR and mercury control costs, certain other environmental retnofit
costs have been idcntified for the plant site, including costs for landfill closrurs,
catalyst replacements, and new pond constnrction for solid waste disposal. SAIC did
not perfomr any plant sirc visits as paft of this studS and as such, SAIC docs not have
enough information to address the adequacy of these costs (approximat"lyl
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 1 l of52
2-2 SAIC Energy, Environmont & tnfiastnrcturc, LLC
EiIVIROiIMEiITAL COST AND PERFORiIIATICE REVIEW
from 2013 to 2019), or thair ability to eunre compliance witr their applicable
rogulation.
2.3 North Valmy
Based on information obtained &rom IPC, a DSI systcm is contenrplated for NIVI to be
installd by 2015 for compliance with MATS. Norttr Valmy Unit 2 (*t.I\/2') is
already €qurppd with a SOz scrubber syst€m. No additional contols re
contemplated for acid gases, mercury or particulates for either unit. Both units are
equtpped with baghouses for partioulates contnol. Using hydrarcd lime as a reagent for
use in a DSI system should €trsur€ compliance with the lv[ATS rule on NVI for
controlling hydrochloric acid (HCl) as a surogate for acid gascs.
SAIC estimates approximarcly $13 million in capital costs (total Unit 1 oose) for the
installation of the DSI using hydratcd limc as a reagent. This compares favorably with
the approxirnatcly I in cryital costs estimst€ provided by tPC. SAIC
beliwes the IPC projections app€sr to be adequate assuming continued operation at a
level similar to recent htory; without performing detailed, line item engineering
reviews of the IPC estimates, SAIC cannot refiae that opinion further.
IPC also provided oost estimates for the possible installation of SCR aod WFGD
systerns on both North Valmy units, for use in examining a possible 'Bnhenced
Compliancer sce,nario for the North Valmy plant. The figures below represent &e
total capital costs for the North Valmy upgrades in nominal do[ars; the IPC *rare of
thcse costs would be 50 percent, based on IEC's ownership share.
. Unit I scR(2olE)--
r UnirtwFcD(2018)--
. unit2scR(2018)_-
r unit2wFcD(2018)--
These estirnates appear adequate for the ir$tallation of tre systerns and are in ihe
upper range of retrofit costs for similar units with which we are familiar. Becausc
meroury emissions at North Valmy are already below required levels for MATS
compliancg no additional controls are required.
SAIC Ener5r, Environment & Infrastnrcturc, LLC 2-3
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 12 ol 52
Fib:3tJ1202007
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 13 of52
Section 3
STUDY DEFINITIOIII AND METHODOLOGY
3.1 lntroduction
SAIC applied a stnrchued, consistent approach to snalyzing the projected costs for
each unit under the various configurations described in Section 2 ofthis report. The
analysis was conductod to provide planning level comparisons of various options IPC
is facing for each ofthc six coal fircd units in this analysis. This approach provides
IPC with the relative costs of each sc€nario for each unit, which will guide IPC's
management and system planners in their decisions rcgardrng the investment decisions
they must make, particutarly identiffing which invcshents warrant a further, more
detailed analysis.
3.2 Scenarios and Sensitivities
SAIC worked with iPC staffto identi$ key scenarios and sensitivities to be analyzed.
Scenarios involve a particular unit's given sihration, and generally include one or more
environmental compliance upgrades, as well as a retirc and replace option. The retire
and replace scenarios examine the relative costs of rptiring the given unit and
developing a similarly sized, natural gas fired combined cycle combustion trubine
("CCCT) unit in its place. Sensitivity cases involve oxamining the effects of a
change in natural gas pricing, or a change in the assumption regarding possible carton
regulations.
3.2.1 Scenarios
Following is a cornprchensive summary of the range of scc,narios analyzed:
ttlorth Valmy Unit 1 Upgrade (lnvall DSll
NVI requircs the installation of DSI for compliance with the acid gases section of the
MATS rule. This requires an initial capital expenditure of f (2015
dollars) IPC shar€ in 2015.
llorth Valmy Unit 1 Enhanced Upgrade (nstallation of DSl, SCR & UUfcD)
Although Valmy is not required by any culrent or proposed environmental regulations
to install a SCR and WFGD system, SAIC evaluated the costs and be,nefits associated
with installing these syste,ms on both Valmy units. In addition to the above
instatlation of DSl, the analysis assumed an SCR installed by lanuary 1,2018 with a
projected cost off (2018 dollars). The WFGD system was assruned to
beiustal1edbyJanuaryl,2018withaprojectedcapitalcostoff(2018
dollars).
5AIE,"
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 14 of 52
Fik;111320200?
Section 3
t{ofth Valmy Unit I 2015 ttlatural Gas Conversion (SCR & IIFGD not toistalled)
SAIC exanrined the costs and beirefis of switchi4g the unit to burn nahral gas instead
of coal, reducing the amount of investnent requircd for snvirounental cornpliance.
The fuel conversion was assumed to occur in ttre same time that the SCR installation
would have for NVl, January l, 2015, ad assumd a six-month outage in 2014 to
allow for the conversion to burning natural gas. After the eonversio& the malysis
assumed a Datural gas heat rate of 10,904 British thermal units per kilowatt- hour
[,BffiXil?;H"^$i?tn'ff #,ffi*,tifi,T$gii,tiltG
the associated natrrral gas pipeline.
Nuth Valmy Unit 1 2018 ilrtual Gas Cmversion (SCR & U,FGD not installed)
SAIC exaurined the costs and benefits of switohing the unit to bum natural gas instead
of coal, reducing the omount of investucnt rcquired for envimnrnental compliance.
The fuel conversion lvas assumed b occur in tlre same time that thc SCR instrllation
would have for NVl, January 1,2018, and assumed a six-month outage :m2fr17 to
allow for the conversion to burning nattral gas. Aftq the conversioq the analysis
assuned a natural gas heat rate of 10904 British thennal units per kilowatt- hor:r
('Btu/kWh'). The fuel conversion assumed a projected capital cost of J(201E dollars) for NVl, and a projected capital cost ofI (2018 dollars]Er
the associated natural gas pipeline.
I{orth Valmy Unit 1 2015 Retire/Replace urlh CCCT (SCR & WFGD not instrlled)
The NVI retiremcnt scemario assumes that &e I.[\/I unit is retired D€c€mber 31,2014
and re,placed with a similarly sized CCCT beginning operation on Jsouaf,y l, 2015.
For the purposes of this analysis, for the NVI retirement and all other unit retirement
analyseq the assrmrption is that the new CCCT would be sited in a rogion with access
to the Surras hub natural gas pricing, with additional gas transportatiotr charges and
capacity to a genoric Idaho City gate. Additionally, the assumption is that the uait
would be sized to exactly replace the megawatts ("MW") for the given unit, assumed
to be 122 MW in the case of NVl. The daa provided for a new CCCT unit assuare a
size of 300 MW, at a projected capital cost of $1,336/kW (2012 dollars), For this
analysis, SAIC assumed that IPC would eitter constnrct the full size unit and sell the
oxha capacity, or possibly purchase he 122 MW of NVl capacity at the givcn pricing,
which produces a projected capital cost of $17E.2 million in 2015 assuming an annual
escalation rate of 3 percent. For modeling puqposcs, the full capital cost was proratcd
for the fiftecn years remaining in the sfirdy period, resulting in a cost of $106.9 million
(2015 dollars) applied to this scenario in 2015. The new CCCT assumptions include
annual cryital and O&M costs. Complete details on the assumptions for a new CCCT
are provided in the list of assumptions in Appendix A.
North Valmy Unit 1 2018 Retire/Replace with CCCT (SCR & WFGD nd installed)
The NVt retirement scenario assumes that the I.IVI unit is retired December 3l,2Ol7
and replaced with a similarly sized CCCT begiming operation on January 1, 2018.
For the purposes of this analysis, for the NVI retirement and all other unit retire,rrent
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 15 of52
3-2 SAIC Enerry, Environmeirt & lnfrastructurc, LLC
STUDY DEIIilMOil A]{D I' ETHODOLOGY
analyses, the assumption is that the new CCCT would be sited in a region with aocess
to the Suuras hub natural gas pricing, with additional gas transportation charges and
capacity to a generic Idaho City gate. Additionally, the assumption is that the unit
would be sized to exactly replace the megawatts ("lvffD for the givur unit, asstrmed
to be 122 MlV in the case of NVl. The dau provided for a new CCCT unit assume a
size of 300 MW, at a projected capital cost of $1,336/kW (2012 dollars). For this
analysis, SAIC assumed that IPC would either construct the full size unit and sell the
exta capacity, orpossibly purchase the 122 MIV of NVI capacity at the given poicing,
which produces a projected capital cost of $L94.72 million in 2018 assuming an
annual escalation rate of 3 percent. For modeling pwposes, the full capital cost was
pmrated for the fifteen years rcmaining in the study period, resulting in a cost of S97.4
million (2018 dollars) applied to this scenario in 2018. Tho new CCCT assumptions
inElude annual capital and O&M costs. Complete details on the assumptions for a nerr
CCCT are provided in the list of assumptions in Appendix A.
North Valmy Unit 2 Enhanced Upgrade (mtallation of SCR A WFGD)
NV2 is not expected to require any additional modifications to be compliant with
curront environmental regulations. Although Valmy is not rquired by the curreNrt
regulations !o install a SCR and WFGD system, SAIC and tPC decided to analyze the
costs and benefits associated with installing these systems ou both Valmy units. The
analysis assumed an SCR installed by January l, 2018 with a projected cost ofJ
I (2018 dollrs). The WFGD systcm was assumed to be installedby January l,
2018 with a Foje.cted capital cost of- (20t8 dollan).
I{orth Valmy Unit 2l{atuml Gas Coruersion (SCR & lrrFGD mt installed)
SAIC examined the costs and benefie of switching ttre unit to bum natural gas instead
of coal, reducing the amount of investnre,nt required for environme,ntal compliance.
The fuel conversion was assunred to occw in the same time that the SCR installation
would have for NV2, Ianuary 1, 2018, and assumed a six-month outage in 2017 to
allow for the conversion to bunring natual gas. After the conversion, the analysis
assumed a naf,riral gas heat rate of f. The fuei conversion assumed a
projected oapital cost ofJ (2018 dollars) for l.IV2, and a projected capial
cost ofI (2018 dollars) forthe associatednatural gas pipetine.
ilorth Valmy Unit 2 RetirdRephce with CCCT (SCR & MGD not installed)
The NV2 retirement scenario ,rssumes 0rat the NV2 unit is retired December 3l,2OL7
and replaced with a similarly sized CCCT beginning operation on January l, 2018.
The NV2 137 MW replacement capacity was assumed to have a projected capital cost
of $218.7 million (2018 dollars), including AFUDC. For modeling purposes, the full
capital cost was proratd for the fifteen yesrs r€rnaining in the snrdy perio4 resulting
in a cost of $109.3 million (2018 dollars) applied to this scenario in 2018.
Jim Bridger Unit 1 Upgrade (lnstall SCR)
To achieve environmental compliance, Jim Bridger Unit I ("JBl") requires a variety
of pollution control systems. The systems include:
SAIC Energy, Environment & lnfrastructurc, lJ-C, 3-3
Exhibit No. 5A
Case No. IPC-E-13.16
T. Harvey, IPC
Page '16 of 52
FiIe:3153202007
Section 3
! a mersury conhol system in2014, with a projected capltal *tt ofI
(2015 dollars) including AFUDC;
r an SCR system in 2022, with a total projected capital cost of
-
(2022 dollars) includiqg AFUDC. For modeling puposes, fte full capital cost
was proratod for thc eleven years remainfurg ia the study perioq rcsulring in a
cost off (2022 do[srs);
r c Clean lVater Act compliance system in 2017 , with a projected capital cost of
I (2017 dollars) inchding AFUDC; and
I a CCB compliance system wifi expenditules in 201.4,2015,2019,2023,2025,
and 2031. This system had a total projccted capital cost ofJ (sun of
nominal dollars in 2014-2031) including AFLJDC.
Jim Bruger Unit 1 RetirelReplace rifi CCCT (SCR not instalho
The JBI retirement scenario assunes that the JBl unit is raircd Decembcr 31,2022
and replaced with a similarly sized C€CT beginning operation on January 1,2023.
The JBI 175 MW replacement capacity was assumed to have a projected capital cost
of $323.79 milliou (2023 dollars), including AFUDC. For modcling pttrpos€q thc fuIl
capihl cost was prorated for the tcn years r€msining in the study perio4 resulting in a
cost of $107.9 million (2023 d/ollars) applid m dris scenario 1n2023.
Jim Bridger t nft 1 ilaturd Gas Comrcrsbn (SCR mt insulbtfi
SAIC examined the costs and benefits of switching ttre unit to bum natural gas instead
of coal, reducing Se amotrnt of invcstment required for environmental compliance.
The fuel conversion assumd a sixaonth outage ifl2022 to allow for the conversion
to bundrg natural ga& wift nafiual gas operation commencing lanuary l, 2023. After
the conver:ion, the analysis asstrmed a natural gas heat rale of
fuel conversion assumed a projected capital cost of
JBt, md a projected cepital cost of J (20tfiE associated
natural gas pipeline.
Jim Bddger Unit 2 Upgrade $nstall SCR,
Similar to JBl, to achieve environmental eompliancc, Jim Bridger Unit 2 (*lB2')
requires a variety of pollution control systcms, including:
r & m€rcury control system im2014, with a projected capital cost ofJ
(2015 dollars) including AFUDC;
I an SCR system in 2021, with a projeCIed capital cost of I(2021 dollars) including AFUDC. psl meflqling purposeq the frilI oapiE[ cost
was prorated for thc twelve years remaining in the shrdy period, resulting in a
cost off (202 1 doltars);
r a Clean Water Act compliance system in 2017, with a projected capital cost of
I (2017 dollan) including AFUDC; and
The
) for
Exhibit No.5A
Case No. IPC-E-I$16
T. Harvey, IPC
Page 17 of 52
34 SAIC Energy, Environmcnt & [rfrastructure, LLC
STUDY DEFNMOil AiID ITIETHODOLOGY
r a CCR compliance system with orpe,ndihues in 2014,2015,2019,2023,2025,
and 2031. This system had a total projected capial cost of f (sum of
nominal dollars in 2014-2031) including AFUDC.
Jim BdQer Unit 2 Natural Gas Conversiot (SCR not inst lh$
SAIC examined the costs and benefits of switohing the unit to burn natural gas instead
of coal, reducing the amorurt of investue,nt required for environmeatal compliance.
The fuel conversion assumed a six-month outage in 2021 to allow for the conversion
to buming natural gas, with natural gas operation commcncing January t, 2022. After
the conversion, the analysis assumed a nahual gas heat rate of J. The
fuel conversion assumed a prcjected capital cost of f (2022 dollars) for
fB2, md a pmjected capital cost of J (2022 dollars) fcr the associated
nahual gas prpeline.
Jim Bridger Unit 2 RetlrelReplace with CCCT (SCR not imtalled)
The JB2 retirement scenario assumed that the JB2 unit is retired December 31,2021
and replaced with a similarly sized CCCT beginning operation on January 1,2022.
The JB2 175 MW replacement capacrty was assumed to hrve a projected capital cost
of $314.36 million (2022 dollars) including AFUDC. For modeling purpolres, the firll
capital cost was prorated for the cleven years remaining in the study period, resulting
in a cost of $l15.2 million (2022 dollars) applied to this scenario n2O22.
Jim eidgrUnit 3 Upgrade (nstall SCR)
All the Jim Bridger units require a variety of pollution control systems to achieve
compliance. Jim BridgerUnit 3 ('J83") rygrades include:
r a mercury contnol system in 2014, with a projected capital cost of f(2015 dollan) including AFUDC;
r an SCR system in 2015, with a projected capital cost of f (2015
dollars) including AFUDC;
r a Clean Water Act ssmpliance system i^2017, with a projected capital cost of
I (2017 dollars) inctuding AFUDC; and
r a CCR compliance system witt expenditures in 2014, 2015, 2019, 2023,2025,
ad 2031. This syste'm had a total projected capital cost off (sum of
nominal dollars i$ 20L4-203 l) including AFUDC.
Jim ffidger Unit 3 Natural Gas Conversion (SCR not installd)
SAIC examined the costs and benefiits of switching the unit to bum natural gas instead
of coal, reducing the amount of investment requirod for environmental compliance.
The fuel conversion assumed a six-month outage in 2015 to allow for the conversion
to buming nahral gas, with nabral gas operation comme,ncing January 1, 2016. After
the conversion, the analysis assumed a nahual gas heat rate of J. The
fuel conversion assuned a projected capital cost of f (2016 dollars) for
JB3, and a projected capital cost ofI (2016 dollars) for the assooiated
natural gas pipeline.
SAIC Energy, Environment & Infrastructure, LLC 3-5
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 18 of52
rik:3151202007,
Sec{on 3
Jim Bridger Unit 3 RetirelRephoe with CCCT (SCR rpt installed)
The JB3 rctirement scenario assurnes that the JB3 unit is retired Decembsr 31, 2015
and replaced with a similrly sized CCCT beginning operation on January L,2Al6.
The JB3 175 MW rcplacernent capacity was assumed to have a projected capital cost
of $263.3 million (2016 dollars) including AFUDC. For modoling purposes, thc full
capital cost was pmratd for the sevortoqr years rcmaining in the shrdy period
resulting in a cost of $149,2 million (2016 &llars) applied to this sccoario in 2016.
Jim Bridger Unit I tpgrade flnsull SCR)
All thc Jim Bridgcr units require a variety of pollution control systems to rchiwe
compliance. Jim Bridger Unit 4 ('JB4') upgredes include:
r a mcrcury control system in 2014, with a projocted capibl cost of f(2015 dollars) includitrg AFUDC;
I an SCR syst€m in 2016, with a projected capital cost of
-
(20 I 6 dollars) including AFUDC;
r a Clcan Water Act compliance Byst€iln lm2017, with a pmjectod capital cost of
I (2017 dollars) insluding AFUDC; and
. a CCR complimce syst€Nn wi6 expenditras in2ol4,20l5, 2019, 2023,2025,
and 2031. This system had a total projected caprtal cost rfl (sum of
nominal dollars in. 2Al4-203 l) including AFUDC.
Jim &idger Unftl l{a0ral Gas Conuerslon (SCR notirstdled}
SAIC examined the costs and benefits of switching tre unit to burn natural gas instead
of coal, reducing the amount of investrrent required for environmental compliaace,
The fuel conversion assurned a six-month outage in 2016 to allow for the conversion
to buming natural gas, with natural gas operation commencing January 1, 2017. After
the conversion, the qnnl).sis assumed a natual gas heat rate of The
fuel conversion assumed a projectod capial cost of 200I ,) for
JB3, ard a projected capitat cost olf (for the associated
natural gas pipeline.
Jlm Bridger Unit 1 RetirdReplaae with CCCT (SCR nd lnstalled)
The JB4 retirement scenario assurnc that the JB4 unit is naircd December 31,2016
and replaced with a similarly sized CCCT beginning operationon January 1,2017,
The JB4 175 MW replacernent capacity was assumed to have a projected capihl cost
of S27l.l rnillion (2017 dollars) including AFUDC. For modeling purpos€xl the full
capital cost was prorarcd for the scvent€en, years remaining in the surdy period,
resulting in a cost of $144.6 million (2017 dollars) applied to this sccnario in 2017.
3.2.2 Sensitivities
Each of tbe unit scenarios w€re analyzed trsing I range of inputs pertainiag to the cost
of natual gas, and possiblc carbon legislation" By usirry these ranges of inputs, IPC
can gain insight into the drivers behind the costs involved in either upgrading or
Exhibit No. 5A
Case No. IPC-E-I$16
T. Harvey, IPC
Page '19 of 52
3{ SAIC Encrgl, Environmcnt & hftastructure, LLC
STUDY DEFINITION AND METHODOLOGY
retiring a given unit, and to what extent the variation of those drivers affects the final
results, Following is a description of the nine aensitivities analpcd:
Planning Case Gas, Planning Case Carbon
This sensitivity used the planning case gas price and plamning case carbon
assumptious. The planning case gas price forecast used in the analysis was provided
by IPC, and corresponds to the price forecast IPC used for is 2013 IRP. Details
regarding the gas price forecast may be found in the list of assumptions in Appendix
A.
The planning case carbon assumption was provided by IPC staffand rrprosents IPC's
view of likely carbon legislation. Thc assurrytion is that there would be a projccted
carton compliance cost, €xpress€d in terms of $/MWIU ap,plied to the coal fired
gencration, This cost is projected to begin in 2018, at a level of S14.64lMWh,
escalating at 3 percent annually.
Lor Gas, Plannhg Case Carbon
This sensitiv$ used the lovy gas price and planning case carbon assumptions. The
low gas price used was provided by IPC, and corresponds to the price forecast IPC
wed for its 2013 IRP. D€tails regarding the gas price forecast msy be found in the list
of assumptions in Appendix A.
High Gas, Planning Case Carbon
This sensitivity used the high gas price and planning case carton assurytions. The
high gas price used was provided by IPC, and correspods to the pricc forecast IPC
used for its 2013 IRP. Details regarding the gas price forccast may bc found in the list
of assumptions in Appendix A.
Planning Case Gas, Low Carbon
This sensitivity used the planning case gas pricc and low carton assumptions. The
low carbon assumption was provided by IPC, and assumes that no carbon legislation
will develop during the study period and assumes a $0/MWh carbon compliance cost
for all years.
Plannirg Case Gas, High Carbon
This sensitivr$ used the planning case gas prioe and high carbon assrmrptions. The
high carbon assumption was provided by IPC, and assumes that carton regulation will
occur earlier and at a higher rate than the base carbon assumption, begirning in 2018
at a level of $35[\{Wh, escalating at 9 percent annually.
Low Gas, Lorru Carbon
This seositivity used the low gas price and low carbon assumptions. The low gas price
used was provided by IPC, and corresponds to the price forecast IPC used for its 2013
IRP. Details regarding the gas price fotrcast may be found in tte list of assumptions in
Appendix A. The low carbon assumption was provided by IPC, and assurnes ttrat no
SAIC Energy, Environmsnt & Infrastruoturg LLC 1-7
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 20 of 52
Filq 11J3202007
Section 3
carbon legislation will dcvelop during the study perio4 and uses a $O/MWh carton
compliance cost forall ycars.
High Gas, Lmv Crrbon
This sensitivity used thc high gas price and low carbon assumptions. The high gas
price used was provided by IPC, and corresponds to the price forecast IPC used for its
2013 IRP. Details rcgurding the gas price forecast may be formd in the list of
aszumptions in Appendix A.
LowGas, High Garbon
This seuitivity used the high gas pricc and low carton assumptions.
H[h Gas, High Crrbon
Ttis sensitivity used the high gas price and high ca6on assunrptions.
3.3 AnalysisMethodology
The strdy approach exacrined tbc costs end bcnefits of oach unit's upgrade or
retirement decision scparately. This means trat the effects of ths given unit's sc€nario
was isolated, and considered no interaction with any other uoits on the IPC systc,m.
This methodology, while liniteq p'rovides a planaing level look at the economics of
the qgrade or retirement dccision.
For each scenario and for each sensitivity, SAIC uscd the annual gcneration amouns
for each uit provided by IPC. For purposes of this screening o"alysis, tte samc
annual generation amount for each unit for each year was used before and after the
potential environmental irnprovernents or fuel s\ilitching, and for the replrconrernt unit
in the case fte coal unit was assnrmed to retire. This has the effect of isolating 6e
costs of the upgradc, allowing IPC to dctermine the relative beircfits of the upgrade or
retirement without any effect of an altered dispatoh on fuel and O&M expeirses. The
generation forecasts provi&d by IPC exrcnded through 2032.
The fucl, O&M, start charges, carbn costs, and SOz allowance prices were forecastod
for each unit for the duration of the study period. Additionally, the ongoing capital
and O&M expeurcs were included in the analysis, to ultitutely forecast the total cost
of generation, botr fixed and variable, for each trnit under each scenario and
sensitivity.
The costs of thc envircnmental upgrades applicablc to eaoh unit werc also ircluded
IPC provided total capital oosts including AFUDC for cach upgrade rcquireq as well
as the ongoing incremental O&IvI costs associated with each upgradc. 1[s timiqg of
the capital expendiftnes varied according to the schedule ofthe given unit's upgrades.
3.3.1 Study Period and Replacement Capacity
The study period used in the analysis was 2013 to 2032.
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page21 ot52
3-8 SAIC Energy, Environrrcnt & Infrastr.rcturc, LLC
STUDY DEFII{]TION AI{D METHODOLOGY
In the retirement sceuarios, SAIC assumed that eaoh unit was replaced with generic
CCCT capacity and energy at the end of its life. fire generic rrplacement capacity
was, as in the retirernsnt scenarios, assumed to be similar in size to the given coal unit.
Section 3.2 above desoribes the specific costs associated with each NV or JB unit. For
the retirement scenarios, the total projectcd cost is idontified above. The analysis used
a proratcd cost for the replacemcnt CCCT units, based on how msny yers remained in
the sflrdy period for a given unit. The proration was calculated bae€d on a 3O-year life
for the replacemcnt CCCT. For example, the Jim Bridger I replacement CCCI was
assumed to begin operations m 2023, with ten years remaining in the study period.
The full cost of the nplacement CCCT was prorated by a flctor of 10/30,
conesponding to 10 yean in the study period out of the 30 year life of the CCCT.
3.3.2 Fuel, Start Charges, and Emissions costs
Each unit's fuel costs werc estimated using the average heat rates pmvided by IPC.
The dispatch amount of ge,neration was fixed according to the annual projected
gene,ration provided by IPC, allowing SAIC to use the average heat rates to calotrlate
the amount of coal burned and total fuel costs.
Similarly, the strrts for cach rrnit were also providod by IPC, as well 8s costs P€r start.
SAIC calculated the total start charges for each year of the study period.
SOz emissions allowance costs wel€ calculatod using the totel fuEl consumption
estimates for each year, combined with the lbs/tvlMBtu data provided by tPC for each
unit, to obain the total tons of SQ. The SOz allowance prices were assumed to be
S0.50/ton in 2012 dollars, and such costs wer€ escdated at 3 percent annually. IPC has
suffrcient allowances to cov6r SO2 ernissions for these plants, althoug[ they were
included in the study to be conseivative.
Carbon costs were calculated according to the given carbon price for each seositivity.
IPC provided catton costs in tsrms of $AdWh for the coal fired generation. To
account for possible carbon costs for thc gas fired replacement capaoities, SAIC
assumed that 50 p€rcetrt of the $/MWh price for coal would apply to the gas fired
generation- For example, the base carbon sceirario calls for coal fired carbon costs of
$16/MWh rm2021dollars. For the gas-fired generation, SAIC assumed this would be
$8/MWhin202l dollars.
3.3.3 Capital and O&M costs
Each rurit has ongoing capital expendifires and O&M costs related to the operation of
thc unit, separate from any capital or O&M costs associated with the e,nvirort'ne,ntal
upgrad€s. IPC provided a forecast through 2A32 for base capital and O&M
expenditrnes. Bascd on disoussions with IPC, the average base O&M €xperules were
escalated at 3 percent annually. The average capital expenditures were escalated at 3
perce,nt aonually,
The increm€ntal O&M cxpenses associated with the upgrades were also provided by
IPC through 2032.
SAIC Energy, Environment & Infrastructure,LLc 3-9
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 22 ot 52
Fib: 315320200?
Ssction 3
3.3.{ Net msent Value ("iln 1analysis
Ths armul md sumulative projcotod powc cosh for this Report arc gescntcd on a
NPV basis for each s€nario. Based ou dirusion with IPC, totel aonrnl costs for
each year wcre discounted to 2013 dollars using a disoouff valuo of 6.77 perccnt,
which rcpreeeos IPC's Waightod Avcraga Costof Cryital CWACC).
Exhibit No. 5A
Case No. IPC-E-1&16
T. Harvey, IPC
Page 23 of 52
3-10 SAICEncrgy, Environucnt& htumdurq LLC
Section 4
OPTIONAL ANALYSIS RESULTS
{.1 lntrduction
This scction presents the results of the aaalyais for each of the six coal units.
Conclusions and recornrrendations follow in Seotion 5.
4.2 Summary Results
Table 4-1 contains the summary results for all scenarios. For eech unig the option
with the lowast projected cumulative pr€$nt vahre power cssts b highlighted- Dollan
are shown in millioos of dollars and discourtod to the year 2013. Table 4-2 contains
the comparison of the coets of the emircnmartal compliance upgrades to the
Retire,ment scenarios for emh unit, both in do[ars and perccntage.
TSbt-l
Present Value d Pwer Cmt by Scenario ($2013 H)
5AIE.
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 24 ol 52
Flls !lJ!202007
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Section {
Ta0h +2
Present Ualue Poucr Cost lhlhs by Scenario (SZOtg M and %)
assumptions, the projected cumulative prescnt value power costs associated wifr the
Upgrade (Instatl DSD scenario is projected to bc the lcast cost option. This holds true
for the mojority of the various cases for the North Valmy uni8, with thc exce,ption of
the Low Gas/Planning and High Carton cases, ad, the Planning Gas/tligh Carbon
case. In these instances, the lower fuel costs associatcd with the low gas prices, and
&e highcr carbon compliance costs associatod with the high cErbon cost assumption,
led to the Natural Gas Conversion cases luvirg the lowest ptojectod cumulative
prcsent value power costs.
The anelysis for thc Jim Bridger units indicates thot for all four Jim Bridgcr uni6, fr€
prcjected cumulative present value power costs associatcd with the environmentol
upgrades r€presert the least cost option. For all fourrmits, similar to the North Valmy
aualysis, tlrere was one case in which the projected cumulative pres€nt valuc power
costs associated with the Naural Gas Convenion option represenEd tbe least cost:
the Iow Gas, High Cafton scerfiio.
4,2.1 Jim Bridger Unit 1
The JBI unit was exemined for tkee scenarios: Upgnde (Install SCR), Nahnal Gas
Conversion (SCR not instslled), and Retirc/Replace with CCCT (SCR rct insallcd).
The planning case results indicate ttrat the projocted cumulative prrsent value power
costs associated with the Upgrade option is the least cost option. The projected
cumulative present value power costs associated with the Upgrade option is lower by
$291 million when cornpared to the R€tire/Replace option, aad lower by $332 million
when comparcd to the Nafiral Gas Conversion option.
Exhibit No. 5A
Case No. IPC-E-1$16
T. Harvey, lpC
Page 25 of 52
4-2 SAIC Encrgy, Environmant & htashrcturs, LLC
OPTIONAL AT{ALYSIS RESULTS
I3
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As with all the Jin Bridger units, the projectcd crmrulativa prcsent value power costs
associated with the cases wene gcncrally hrghsr as carbon cornpliance oosts increased.
There was a similar trend with rcgards to gas prices. Th€ NG Conversion option was
similar to the Retire/Replace option. With one excqrtion, thc cumulative presont
valuc power costs associatod with the Upgrade option were projocted to be lower
when compared to &e projected cumulative pr€seot valrrc power coSs associated srith
the NG Conversion and Retire/Rcplace options.
Table 4-3 and Figure 4-2 contain the results for the nine JBl casos:
TrUe 4.3
Jim Bddger Unit 1 - Totd Co6B llPU ($2013tr0
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SAIC Encrggr, Environmot & Intastructurc, LLC 4-3
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 26 of 52
Fih: 3153202007
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Filpre +e Jfrn Br*lgef Unit 1 AI Cases - Tca| Ccts
Seotion I
4.2.2 Jim Bridger Unit 2
The JB2 unit was examined for &e same thrpe scenarios as Unit l: Upgrade (Instail
SCR), Natural Gas Conversion (SCR not hstalled), and Retire/Replace wi6 CCCT
(SCR not installed).
The planning case regults indicate that the Upgrade option ig the least cost option. The
cumulative pnesent value power cost for the Upgrade option is projected to be
$305 million lower than thc Retire/Replace sceaario, and $350 million lower than fte
Natural Gas Convcrsion option -
Figue l-3. Jim Br@er Unit 2 Plannirg Case - Tdal 0osb
As with all the Jim Bridgor units, the projected cunulativc present value power costs
associated with thd cases were generally high€,r as carbon compliance cost increasd,
and a similar tend is projected with regards to higher gas prices. The projected
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page27 ot 52
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4-4 SAIC Eneqgy, Environment & hfrastructure, LLC
OPTIONAL ANALYSIS RESULTS
cumulative present value power costs associated with the Retire/Replace option were
generally lower than the projected cuurulative present value powcr costs associated
with the Natural Gas Conversion option, with the exception of two Low Gas cases.
The Upgrade option was forecasted to have the lowest projected cumulative present
value power costs in all but ore case, the Low GayHigh Carton case.
Table 4-4 and Fignre 4-4 contain the results for the JB2 cases:
Tabletl4
Jim Bridgc unir 2 - Total costs f{Pl/ ($2013 M)
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Figure {-4. Jim Bridgr Unit 2 All Cases - Tdal Costs
4.2.3 Jim Bridger Unit 3
All Jim Bridger units were examined for the same tlree scenarios: Upgrade (Install
SCR), Netural Gas Conversion (SCR not installed), and Retire/Replace with CCCT
(SCR not installed).
The planning case results for JB3 indicate ttut the projected cumulativc present value
power costs associated with the Upgrade option is the least cost option. The projecled
cumulative present value power costs associated with the Upgrade option is
$446 million lower than the projecrcd cumulative present value power costs associated
with the Natural Gas Conversion scenario, and $371 million lower than the
Retire/Replace optiou-
Exhibit No. 5A
No. IPC-E-I 3-16
T. Harvey, IPC
Page 28 of 52
rilq ,15!202007 SAIC Enerry, Environment & hfrastructure, LLC +5
Section I
The projected cumulative prarcnt valuc power costs associated with thc
Retire/Reptace option indicate this is the most expensive option for thc majority of tlrc
cases, mone so even than the Natuxal Gas Convcrrsion option. This is primarily due to
the constuction costs for tho Replacement CCCT being signiftantly higher &an tre
ca,pitrl costs assciated with the fuel convomion,
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s
to I
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Figue &5. Jim Bidger Ufi 3 Planfrg Case - Totd Costs
Table 4-5 and Figure t1-6 contain fte results for the JB3 cases:
faUc G5
The gene,ral trend of higher carbon and higter gas prices making the Upgrade option
the most economioal option occun elso withJB3 and JB4.
Exhibit No. 5A
Case No. IPC-E-I3-16
T. Harvey, IPC
Page 29 of 52
Jim Bddgc Unit 3 - Tobl CosE I{H/ 6At3 O
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+6 SArc En"rg, Environment & Infraetruchrc, LLC
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F(;ure &6. Jim Bridger ttrtft 3 All Cases - Total Costs
OPTIONAL AI{ALYSIS RESULTS
4.2.1 Jim Bridger Unit 4
The projected cumulative pr€sent value power costs associated with the planning case
results for JB4 indicate similar results as with JB 3. The projected cumulative present
value power costs associated with the Upgrade option is the least cost option. The
projccted cumulative pres6.t value power sosts associated with the Upgrade option is
$393 million lower than the pmjeoted cumulative pr€setrt value power costs associated
with the Natural Gas Conversion option, and $332 million less tban fte Retire/Replace
option. The projected relative resulB of the sensitivities scenarios for JB4 are similar
to the relative results for the JB3 sensitivity scenarios.
Ct
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SAIC Encrgy, Environment & hfrasfructure, Lrc 4-7
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 30 of 52
Filc: !153202007
Section tl
As with JB3, the projected cumulative presetrt value power cosb associated with the
Retire/Replace optiou indicate this is the most e:peirsive option for the majority of &e
cases for JB4, more so even than the Natural Gas Conv€rsion option. This is primadty
due to the construction costs for the Replacemcnt CCCT being significantly higher
than the capital cosE associated with the fuel conversion.
Table G0
Jim BriQr thit r - roH cosrs t{PV ($2fi3 nl
4.2.5 ltlorth Valmy Unit 1&2
The NVI aoalysis ircluded an Upgrade caso involving just frc DSI instaUatioq and an
Enhanced Upgrade case including the installation of SCR ond WFGD systems. NV2
was evaluated for tte Enhancod Upgrade case. Both North Valmy units were also
evaluated for a potential Natural Gas Convcrsion scenario, and botr were compared to
a Retire/Replace option.
4.2.6 North Valmy Unit 1
The planning case results for NVI indisat€ that thc projected eunulrrtive prese,nt value
power costs associated with the Upgrade (DSI Installed) option is the least cost option.
The projected cumulative present value power costs associated with the Retirement
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 31 of52
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t-::111rllisq'*'E
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! 16 ce€r$n (xo scnl r r?&e/lrcth. lr5 ri)
Figure 1{. Jim Br5ger t nit { A[ Cases - Total Costs
4-8 SAIC Enerry, Environmcot & Inftastrucurc, LLC
OPTIONAL AT{ALYSS RESULTS
option is lower by $138 million when cooipared to the 2015 Nafiual Gas Conversion
optiorq and lower by $76 million whcn compared to the 2015 Retire/Replacc option.
Iail
flI
tre
t0
fD
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l0
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r I0l! llc crirrhn 0a. 3cr r rrrFool
r liha!.dtrfi*
.lfil .l0llld.tlllhti$rt
Figure l-9. ilorth Valmy Unit 1 Phnning Case - Total Costs
The NVl analysis results indicatc that for fte majority of cases, the Upgnde @SI
Installed) case is the least cost option. The Low GaslPlanning Case Carbon, tow
Gas/High Carbon, and Planning Case Gas/High Carbon oases indicate tbat undar low
firel cost oonditions, or a high carbon compliance cost condition, the Natral Gas
Conversion options would likcly rcsult in the lowest cumulative pt€sent value power
costs.
Table S7.
lhrth ualmy unit 1 - Total cos,ts t{PV ($2013 ltl)
SAIC Encrgr, Enviroument & hftaltrucfiIre, LLC 4-9
Exhibit No. 5A
Case No. IPC-E-'|3-16
T. Harvey, IPC
Page 32 ol 52
Filc ,15t20200?
I-d
EI
lltc
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Lil(t.. tdo.r ldB tLraac [mftr thUrlll lthc.. lthcr lt!ra..ic$.rt *dg tl$Orta hC h.(- €rS Xoolt..l llllrt tflrc..fcC.r.Oltfi lloeil.e fr.nnt $!hc.icr c-Oil'r
. t!! |r cotctbi 0rottl r wfrol . lGllG CoEnaal Fro$r rffiDl.loStrttmL.rlltIrl .lorlE.ffi (rb tEa lrttd
Figre 1.10. North Valmy Urit I Nl Cases - Toul Costs
Section 1
4.2.7 North Valmy Unit 2
The planning oase rcsults for NV2 indicate &at &e projected cumulative present value
power costs associatcd with tLe Rctire/Replace option is the least cost option, though
tte oosts associated with dre Nauual Gas Conversion option arc very similar. The
plojeoted cumulative present value powcr costs associated with the Retire,/Rcplace
option are lower by $2 million whcn coryarcd to the Natuml Gas Conversion option,
and lower by $66 million wten compared to the Eohance<l Upgrade option"
Iilcst-
sr.e
,no
$IU
$o
9aao
9aao
Sazo
r HG€.nt rtlon (l{oSCBtttfcDl Aft.sdthat d.t r.tt /i.phc.|il. tcn O $rfGD,
Flgure 4.11. lttorth Valmy Unit 2 Planning Case - Tohl Costs
Thc NV2 analysis results indicate that for thc majority of cases, the Natural Gas
Conversion case is the least cost option. The Planning Case Gas/tow Carbon, and
Planning Case Gas/Planning Case Carbon cases indicats that under planmng case fuel
cost conditions and low and planning case carbon compliance oost conditions, the
Exhibit No. 5A
Case No. IPC-E-I3-16
T. Harvey, IPC
Page 33 of 52
+10 SAIC Energy, Environmcnt & Infrastruc'trne, LI.C
OPIIONAT ANALYSIS RESULTS
Retire/Replace option would likely result in the lowest cumulative present value
power costs.
Table &8.
ibr$ valmy unit 2 -Total cosrs l{Pv ($zmr u1
tror urr Arrrat lffGr
tlrlrf,Caer
llana{
car(bilrrl{thtliorar rtt0.HUiOrtlrilr3 r{loc.3
ll. Ctrtlrltatlctlrfmtfurrautlra 6arrawr0allra1.a*BrbEa@i
9s 9r.gr
q $15 t€st 3?'il qtr
Blt2 tlfi lt tt tlx tE
hlll
i.ml( rLilllt tt|t8l. lUrA.. ltl3..tu tu C..G.. lloortcr ?lnn}| l{thO,t€lrtLiltaC ll|hcdolt Cr.c.rtqrC.rt6on
. Eli.fr,rp?.c rrncner-.tudirriraot
tl.0tm
TT
tiloifiltrl
lc6u Lr6.a lrio.a tbncirltlo$rl tlf,rrlrt Hl|hcr.to.i fia6..C.Ct,l toca.ta.r
t rrrromillxoGiltg _
Figue l-12. t{or$ Vakry Unl 2 All Cases - Total Costs
SAlCEnogr,Environmcnt&InfrastructureLlC 4-11 O
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 34 of 52
Filcr llJ32{12007
Exhibit No. 5A
Case No. IPC-E-1$16
T. Harvey, IPC
Page 35 of 52
Section 5
CONCLUSIONS
Ther€ are a variety of foctors causing the increasing number of coal-fired gcneration
retirement studies and actual rrtirements, including a significant docrtase in natural
gas prices, increasingly stingent environmental rcstrictions, and steadily increasing
amounB of renewable generation. [n IPC's casc, the potential cnvironmental
restrictions and their associated significant investsnents requircd for compliance are of
panicular concertr. Complicating factors for the total systefir and especially for the
North Valmy tmits is the combination of recent wind installations and the traditionally
heavy spring hydro generation; these two factors have combined to result in a
significant decrease of North Vatny generation in the March to June months of rece,nt
ye8rs.
Ano&er challenge facing coal ganeration owneni is the possibility of some form of
carbon/greenhouse gas (*GHG) regulation in the future. This possibility leads to
subshntial uncer0rinty when attempting to forecast the future of any asset, and
coal-fired assets in particular. A recent studyr by the Detrtsche Bank Group identifiod
thag wen though natural gas is widely viewed as a less-carbon intensive alteflrative to
coal as a power sector fuel, when considering the entire life cyclas of both coal and
natural gas, it is possible that the natural gas GHG advantage would either be reduced
or eliminated. The study discusses how shale gas production, with is associated
hydraulic fracturing, leads to increased GHG e,missions relative to conventional
natural gas production. The Deutsche Bank Group r€port ultimately concluded that, on
avetrage, natural gas-fued clectricity generation does in fact emit significantly less
GHGs than coal, on a source to use basis. However, the Report highlights the fact that
methane is still a conc€rn as a GHG, and requires further attention. For IPC's
purposes, this is significant as it underscores the importanc€ of cousidering the issuos
of carbon and GHG when evaluating coal-fired resourc€s, even though the momenhrm
for some form of national cartc,nr/GHG legislation has cooled recently.
SAIC was retained by IPC to conduct this study which addresses these concerns when
evaluating the upgrade invesfrrents required to keep tlre North Valmy and Jim Bridger
plants in eirvironmeirtal compliance with recent and pending EPA environmental
requirements. In collaboration with IPC, we identified a methodology which
incorporates the uncertainties IPC is facing, particulady with respect to natural gas
pricing and possible GHG regulations. This section provides SAIC's planning level
conclusions regarding the economics of those upgradc investments relative to simply
retiring the plants and replacing them with natural gas-fired generation. IPC should
consider conducting additional detailed analysis to evaluats the most promising
altematives considered in this preliminary shrdy. Such studies should consider both
annual and cumulative projected present value power costs, production costing
simulation with and without the various proposed alternative conversions/retirement
scenarios and sensitivity cases and a review ofthe O&M expenses under scenarios and
I Comparing l.ife-Cyclc Greenhousc Gas Emissions &om Nanral Gas and Coal
5AIE,.
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 36 of 52
Fite I t5!202007
Section 5
sansitivity cases where a major shift in the operation of generation resources might be
expected.
5.1.1 North Valmy
The planning case results for NVI indioate that ths projected cumulative prese'nt value
power costs associated with the Upgradc (DSI Installed) option is fte lcast cost option.
The Upgrade option has the lowest projecrcd prEsent value power costs, with the
differcnce betwcen the Upgnde option and the Natural Gas Conversion and
Retire/Replace options mging benpeen $76 and $l3E million.
The NV2 analysis indicated that the Natural Cas Conversion optioa is projected to
have the lowest projected cumulative pr€s€nt value power cosb. [n the case of NV2,
the Natural Gas Convetsion option and the Retire/Replace options are both very
similar in tsrrs of presant value power costs.
The North Valmy nnelysis atso indicated that tho Upgrade option for NVI and the
Enhanced Upgradc option for NV2 have the lowest projected cumulative present rralue
power oosts in nearly all of the High Gas scenarios, the exception being the High
GaYHigh Cafton case for NV2.
The potential for some tlpe of carbon conrpliance regrrlations have a lesser irnpact on
ths relative costs and benefits b€fivesit the various North Valmy scenffios, due to the
lower generation dispatch forecasts used in the analysis. The lowest projected
cumulative preseot value power costs over the Sudy Period for all the sce,narios and
saser ane the Natural Gas Conversion options under the Low Gas, High Carbon cases.
These results indicate that the economic decisions regarding North Valmy I are more
seositive to gas price incrcases than potential carbon compliance costs.
The difterences betw€en tho Upgrade and Natural Gas Conversion options relative to
the Retire/Replace option in the Planniag Case, and the lower projected sumulative
pres€nt value power costs for those options in the High Gas cases indicates that IPC
should carefully consider its options regarding Norftr Valmy. Natural gas prices are
currently so low that in mary arcas of the U.S., gas-fued generation is economically
displacing coal-fued generation for increasing periods of time. Thcse low prices,
combined with the cunent and pending environmedal compliance regulations, make
many coal-fired gencratiag plants less cost effective relative to gas-fired generation.
However, SAIC belicves that IPC should consider the High Gas cases when making
any decisions regarding the North Valmy plant. This study indicates that under
Plaming Case conditions, upgrading NVI and r€tirfurg NV2 and rcplacing it with a
combined-cycle plant are the nrost cost effective options; these results also hold in the
event that gas prices rise, although the IrIV2 Enhanced Upgrade case is cost effective
under fuigh gas prices as well. These indications offer an opportunity to IPC to
consider retaining tte North Valmy units as coal-firpd to help IPC mitigate potential
fuhrrc gas price increases. The potential value of these units would decrease in the
event of significant carbon compliance costs, howerrer.
Because the relative differences betrreen the projected cumulative present value power
costs for the Upgrade, Retire/Replace, and Natural Gas Conversion options for Noah
Exhibit No. 5A
Case No. IPC-E-'|3-16
T. Harvey, IPC
Page 37 of 52
5-2 SAIC Energy, Enironmcnt & Infrastucurc, LLC
coircLUSroNs
Valmy are relatively small, in SAIC's opinion IPC strould consider further analysis on
North Valmy before making a final decision. SAIC has ide,ntified that the North
Valmy options are materially sensitive to possible carbon compliance costs.
5.1.2 Jim Bridger
The analysis of the cost cffectiveness of the Upgrade options for the Jim Bridgcr units
results in more definitive conclusions than with thc North Valmy units.
Under the Planning Case assumptions regarding natural gas pricing and potential
carton compliance costs, the Jim Bridger Upgrade options have the lowest projected
cumulative present value power costs over the Study Period for all four units. For all
Iim Bridger options and for all the gas and carbon cost assumptions, tttc Natural. Gas
Convenion options and the Retire/Replace options are relatively simila,r to each other,
ditrering mainly by the increased fuel costs in &e Natral Cas Conversion cases due
to a higher heat rate than the generic CCCT in the RetireiReplace option. This is
offset by the increased capital e:cpenditurcs associated with constnrcting the new
CCCT.
5.1.3 Conclusions
IPC decided to conduct a sttrdy which examines the costs of environmental upg:rades
requircd for compliance as currently proposed, and to provide conclusions regarding
the economic feasibility of the environmental compliance upgrades and the retirement
options for the six units at the North Valmy Generating Station and the Jim Bridger
Plant.
Based upon the principal considerations and assumptions summarized in Appendix A,
and upon the studies aud analyses as summarized and discussed in this Report, which
Report should be read in its e,ntirety in coujwrction with the following, we provide the
following conclusious :
The North Valmy Upgrade and Retire/Replace options for tWl and NV2,
respectively, are projected to have the lowest projected cumulative preseut value
power costs over the Study Period of the options studied herein for the North Valmy
units, but the costs for the Natural Gas Couversion case for NV2 ale exfremely close
to the Retftt/Replace option. Furthermore, the High Gas case is projected to indicate
that maintaining the North Valmy on coal fuel offers a potential opportunity for IPC to
mitigate potential gas price increases. In SAIC's opinion, the difference between the
projected costs of retirtment and replacing the North Valmy units, combined with the
potential benefit of continuing to bum coal at the Norttr Valmy plant in the event of
high"r natural gas prices, result in the need for further analysis of the North Vabny
options.
The Jim Bridger upgmde options are projected to have the lowest projected
cumulative pr€sent value power costs over the Study Period, of the Jim Bridger
altematives studied herein, including the Retire/Replace alte,r:rative. SAIC examined
the Jim Bridger upgrade, nahrral gas conversiou, and retirement and replacement
alternatives under a variety of market conditions, and with the limited exceptions
SAIC Energy, Environmcnt & Infrastructure, LLC 5-3
Exhibit No. 5A
Case No. IPC-E-1 3-1 6
T. Harvey, IPC
Page 38 of 52
t'ilc:315f202007
Seclft,n 5
notd, tho ryg;rade options are pmjcotod to be the most cost effoctive. Basod on our
results and thc assumptions dcssriM abovg in SAIC's opinion &o inrrsErcnt in
cnvironmontal compliance upgrrdcs ue rcasonable and pndert Should my material
chmge oocur to the upgrade ceitrl cmts or fucl price p,rojcctions prior to insblfug
the tpgrades, SAIC bolieves &it IPC should rcevcluat€ the Wg[d€s at tbrt time.
Exhibit No.5A
Case No. IPC-E-1$16
T. Harvey, IPC
Page 39 of 52
54 SAIC Enegy, Ervironmcot & Infrastuctmc, LLC
Appendix A
ldaho Power Company Principle Considerations and
Assumptions
In the preparation of the preliminary projected power plant cos6, we have made
certain assumptions with respect to conditions that may occur in thc future. While we
bclieve these assumptious arc reasonable for the purpose of this analysis, they are
dcpendent upon future events ond actual conditions may differ from those assrmed.
In addition, we have used and relied upon cerEin information and assumptions
provided to us by others including ldaho Power Company C'IPC"). While we believe
the sources to b€ reliable, we have not independently verified the infonnation and
offer no assuranc€s with respect thereto. To the extent that actual futurc conditions
differ from those assumed herein or provided to us by oth€rs, the acttul rcsults will
vary from those forecast. The principal considerations and assunptions made by us in
peparing the preliminary projected power plant cose over the study period begiming
on lanuary 1,2013 are srunmarizcd below.
A.1 GlobalAssumptions
L
2.
1
4.
The snrdy period for the analysis is the 20-year period from January l,
2013 to f,lccember 31, 2032 C'Study Period").
Annual inflation rate of 3.0 percent over the Snrdy Period.
Present value power cost \f,erc disconnted to the year 2013 at an annual
discount faotor of 6.77 percent which is equivalent to IPC's weighted
average cost ofcapital
We have assumed that the IPC generation uuits will operate and be
available over the Sndy Period as projected by IPC.
SO2 emissions allowances were assumed at a cost of $0.50 p€r ton un20l2,
escalating a"rually at 2.5%.
A.2 Generation Unit Assumptions
l.IPC provided the pmjected annual €lne,rgy generation dispatch (MWh) for
each of the six North Valmy and Jim Bridger generation units, which was
modified by IPC for each sensitivity case (High and low Gas and High and
Low Carbon Costs). The generation dispatch was not modifred for the
scenarios assuming (i) environmental upgrades, (ii| fuel switching or (iii)
unit retirement/replacement.
Each generation unit was considered independently, without consideration
of the IPC system impacts or interactions.
)
5AIE,.
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 40 of 52
Fibr 3153202007
Appendh A
Table A-l below provides assumptions for each unit including size, heat
rate, SO2 emissions rate and start costs.
Tabb A-t
Generating Unit Assumptiors
For each scenario and for each sensitivity, SAIC uscd fte annual
ge,neration brecast for each unit pmvided by tPC. Tablc A26 providcs the
annual gensration forccast for cach unit and each sensitivity. Note: The
fuel switchi'g scaarios included r 6 month outage in the year that thc fuel
switching occuned; for ftose scenarios, the geae'ration forecast wrs
deoreased by 50% for those units in the given year,
Projected fixed costs for the North Valmy and Jim Bridger units were
provided by IPC and assume fte following:
a. Base fixed O&M and capital improveinents costs, inclusive of
AFUDC, for each of the units was based on each uuit's currqrt
configrration.
b. lncremenal environmental upgrade O&lvt and capital costs, inclusive
of AFUDC, for each of the units were exp€ns€s in the year of
installation.
c. Projected costs included in the analysis reflected IPC's share of the
total cosB, and do not reflct the lotal costs prcjeoted for ach unit.
IPC is responsible for 33 perccqt ofJim Bridg€r costs, and 50 pcrcent
of North Valmy costs.
d. Tables A3 through A22 provido the assumed Fixed O&N,t, Variable
O&M, and Capital Cost projcotions fior all scenarios.
The Retirement and Replacement scenarios assume the gven unit would be
retired on Dece,mber 3l of fre indicatcd t€tiremeNil year, and replaced with
a natural gas fired oombined cycle combustion turbine unit. For the
purposes of this analysis, the assumption is that the new CCfi' would be
sited in a region with access to the Sumas hub natural gas pricing, with
additional gas transportation charges and capacity to a generic Idaho City
gate. Additionally, the assumption is that the unit would bc sized to
exactly replace tlre megawatts (*MW'') for the given unit. Thc replacement
3.
4.
5.
6.
Exhibit No. 5A
Case No. IPC-E-1$16
T. Harvey, IPC
Page 41 of52
Unit Si:o (HUU)Asrgptle.tRrb
(mnBtrtWttl
S02 Emissim Rrc
(lbstnmBul
Stst Co6t(t)
ilorfiV*rythft 1 122 I 0.00t5 1e610
iloffiVrythft2 137 I 0.15{r 12,610
.lim &itger Unl I 175 I 0.15 15,760
Jim Brldger Unit 2 175 I 0.2705 15,760
Jim Bddser Unlt 3 175 I 0.a03 15,760
Jtm Bfi&rUnit4 175 I 0,ml 't5.760
A-2 SAIC Energy, Environment & Infrastrushre, LLC
ldaho Pouuer Company Principle Considerations and Assumptions
CCCT units have an assumed heat rate of 6,990 Btu/kWh, an assumed
2,616 mmBtu start firel requiremen! and an assumed SO2 emission rate of
.001 lBs/mmBtu. Replacornent unit capital costs, inclusive of AFUDC,
were anortized at an annual rate of 6.77 percent over the remaining years
of the Snrdy Period bcginning one year prior to the assumed replacement.
Table A1 below provides the retirement years for each unit of the study,
and their replacement units' sizo and total cryital costs. Annual O&Ivl and
capital costs are provided in the Rotire and Replace scenario tables for each
unit in Tables A-3 through A-22,
Table A-2
7. No transmission costs and losses werc assumed.
Replacement Unit Capitrl Coets rnd Size
Unit RetlcmartD&RcplaccnHltcapit lCost
Oofl*dtkWl
Size0ii0
Norfi Valmy Unit't 2015 1,161 122
Norlh Valmy Unit I 201E 1,596 122
Norfi Valmy Unlt 2 201E 1,596 137
Jim Bddger Unit 1 20n 1.n6 176
Jim Bridg€rUnit 2 2021 1,74 175
Jim Bridger Unit 3 m15 1,(,1 175
Jlm Bddger unit 4 20r6 1,501 175
A.3 FuelAssumptions
We have assumed projected coal and natural gas costs in $rMMBTu and over ihe
Stttdy Period based on infornration provided by IPC. Table A-23 provides projected
coal prices by unit, and Table A-24 provides projected natural gas prices.
4.4 Carbon Compliance Cost Assumptions
The base carbon compliance cost assumption was provided by IPC staffand represents
IPC's yiew of likely carbon legislation. The assumption is that there would be a
projected carbon compliance cost, expr€ssed in terms of $/IvlWlr, applied to the coal
fired generation. Table A-25 provides projected carbon compliance costs in $A,{Wh
for both coal fired generation and gas fired generation.
SAIC Energy, Environment & lnfrastructure, LLC A-3
Exhibit No. 5A
Case No. IPC-E-13-16
T. Harvey, IPC
Page 42 ol 52
Fil€: 1153202007
Appendir A
The projections of electric power and energy roquircmeots are bad on the
assumptious tbat the State of Idaho will continuc to oxperierce economic conditions
oomparable to ffrose of recent years and that no significant clrangcs will occur in the
electric utility industry 0rrcugh the year 2032. Dnc to unccrtaintics causod by varirble
factors, such as cbanges in cosB, tecbmlogy, legislation and rcgu}rtion, the
coosidenrtions ard assumptions set forth herein could be affectsd. For insbnce, tlre
considcratioas and assumptions could be affcctcd by rogulatory, t'echnotogicd rnd ffrcI
cost chmgps leading 16 significant chaages in thc cosb of elcctrie powcr aod cne46r.
Iu part becarse of evolving chaoges rffecting the clcotric utility infusay, potential
adverse dwelop,nrents in these, and pot€ntially other, arcas cannot bc prodicod or
determircd at this time.
Exhibit No.5A
Case No. IPGE-I$16
T. Harvey, IPC
Page 43 of 52
A4 SAIC Energy, Environrncnt & Infrasfructruc, t,LC
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aOTL IRP UPDATE
Coal Unit Environmental lnvestment Analysis
For The
Jim Bridger and North Valmy
Coal-Fired Power Plants
Coal Unit Environmental Analysis Page 1
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 1 of30
TABLE OF CONTENTS
Executive Summary...
Financial and Economic Assumptions..................
Description and Existing Major Environmenta! lnvestments in Coal Units.............
Recent Environmental Regulations....
lnvestment Alternatives.
Base Alternatives...
Compliance Timing Alternatives.
Enhanced Upgrade Alternatives
Conclusions and Recommendations.
North Valmy Unit #1.
North Valmy Unit #2.
North Valmy Units #1 and #2.
Jim Bridger Unit #1...
Jim Bridger Unit #2...
Jim Bridger Unit #3
Jim Bridger Unit #4.
Jim Bridger Units #3 and #4.
Review Process and Action Plan.
5
5
5
5
6
7
7
7
8
11
11
13
13
74
74
15
77
t7
19
19
22
23
25
25
28
30
Coal Unit Environmental Analysis Page2
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 2 of 30
Executive Summarv
The Coal Unit Environmental lnvestment Analysis (Study) examines future investments required for
environmental compliance in existing coal units and compares those investments to the costs of two
alternatives: (1) replace such units with Combined Cycle Combustion Turbine (CCCT) units or (2) converting
the existing coal units to natural gas. ldaho Power used a combination of third-party analysis, operating
partner input and an ldaho Power analysis to assure a complete and fair assessment of the alternatives.
This Study consists of two parts:
1. A unit specific forecasted (static) annual generation analysis performed by Science Applications
lnternational Corporation (SAIC). ldaho Power conducted a competitive procurement process to
select SAIC.
2. An economically dispatched (dynamic)total portfolio resource cost analysis performed by ldaho
Power using the SAIC study results.
The SAIC analysis included a review of ldaho Power's estimated capital costs and variable costs associated
with the proposed environmental compliance upgrades, coal unit replacement with CCCTs and naturalgas
conversion. SAIC developed the cost estimates for replacing the coal units annual generation, under three
natural gas and three carbon futures. These estimates served as the foundation for SAIC's capital investment
analysis which allowed assets with different lengths of operation as well as different implementation dates to
be compared equitably. The results of the SAIC analysis served as planning recommendations regarding the
three investment alternatives to be used in the second part of the comprehensive Study.
The second part of the Study performed by ldaho Power utilized the AURORAxmp'Model (AURORA) to
determine the total portfolio cost of each investment alternative analyzed by SAIC. The total portfolio cost is
estimated over a twenty-year planning horizon (2013 through 20321.
The Key Assumptions section of this report provides additional details on the carbon adder assumptions and
natural gas price forecasts.
Analvsis Results for North Valmv
Currently, the only notable investment required at the North Valmy plant is to install a Dry Sorbent lnjection
(DSl) system for compliance with the Mercury and Air Toxic Standards (MATS) regulation on Unit #1. North
Valmy is not subject to Regional Haze (RH) Best Available Retrofit Technology (BART) regulations; therefore,
no additional controls will be required for compliance with this regulation. No other notable investments in
environmental controls at the North Valmy plant are required at this time.
lnstallation of DSI was the lowest cost result for most of the sensitivities analyzed by SAIC including the
planning case scenario (planning case natural gas/planning case carbon). The AURORA analysis, performed
by ldaho Power, shows installing DSI as the least cost option in four of the nine sensitivities analyzed
including the planning case scenario (planning case naturalgas/planning case carbon). The scenarios in which
Coal Unit Environmental Analysis Page 3
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 3 of 30
DSI was not the preferred option are the extreme low natural gas and high carbon cases, which have a lower
probability of occurring.
ldaho Power's conclusion is that installing the DSI system is a low cost approach to retain a diversified
portfolio of generation assets including the 125 MW's of Unit #1's capacity for our customers benefit. The
continued operation of Unit #1 as a coal-fired unit will provide fuel diversity that can mitigate risk associated
with high naturalgas prices.
ln the event that North Valmy requires significant additional capital or operation and maintenance costs
(O&M) expenditures for new environmental regulations, both the SAIC and the ldaho Power analyses advise
further review to justify the additional investment.
Analvsis Results for Jim Brideer
Jim Bridger is currently required to installSelective Catalytic Reduction (SCR) on all four units for RH
compliance and mercury controls for compliance with MATS. Both the SAIC and ldaho Power evaluations
identify additional investments in environmental controls on allfour Jim Bridger units as prudent decisions
that represent the lowest cost and least risk option when compared to the other investment alternatives.
ldaho Power recommends proceeding with the installation of SCR and other required controls on Units #3
and #4 and including the continued operation of all four Jim Bridger units in ldaho Powe/s future resource
planning.
Comoliance Timing Alternatives
ldaho Power also evaluated the economic benefits of delaying coal unit investments required under the
emerging environmental regulations. To perform this evaluation ldaho Power assumed that it could
negotiate with state and federal entities a five-year period where no additional environmental controls are
installed in exchange for shutting the unit down at the end of the five-year period. These compliance timing
alternative cases are strictly hypothetical. ldaho Power may not have any basis under current regulations to
negotiate this delay and the relevant regulatory authorities have not offered any such delay. These
alternatives are included in the alternatives summary table.
Unit Ownershio and Ooeration
It should be noted that, although a partial owner of the Jim Bridger (one-third) and the North Valmy (one-
half) coal plants, ldaho Power does not operate any of the coal-fired units and ldaho Power does not have
the sole rights to alter the compliance plan in place for these units. Any decision regarding environmental
investments, plant retirement or conversion to natural gas must be coordinated and agreed to by the other
owners/operators of the plants and their regulators.
Coal Unit Environmental Analysis Page 4
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 4 of 30
Kev Assumptions
The undertaking of any analysis of this nature requires that assumptions be made regarding uncertain costs
and regulations that may impact the economics of the coal plants. ln fact, two of the most influential inputs
to the analysis are also among the least known over the long-run and are related to future carbon regulation
and future natural gas prices. ln order to evaluate these uncertainties ldaho Power has used low, planning
and high case natural gas and carbon adder futures. These forecasts provide a range of outcomes to assess
the impact of natural gas price and carbon adder uncertainty on the economic evaluation of the investment
alternatives.
ldaho Power is currently preparing its 2013 IRP covering the 2013-2032 planning horizon. As that process is
well underway, key assumptions for this Study are aligned with the 2013 IRP assumptions.
These key assumptions include:
Natural Gas Price Forecast - For the purpose of being consistent with ldaho Case No. GNR-E-11-03, Order No.
32697 (December 78,2}t2l,ldaho Power is using the Energy lnformation Administration (ElA) Annual Energy
Outlook (Henry Hub spot price) for the 2013 IRP planning case natural gas price forecast. The high and low
cases are +/-3O%from the planning case forecast. All cases were adjusted to reflect an ldaho citygate
delivery price. These forecasts are provided in Figure 1.
Figure 1. NaturalGas Price Forecast
Natural Gas Price Forecast
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Coal Unit Environmental Analysis Page 5
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 5 of 30
load Forecast - The 2013 IRP load forecast is ldaho Power's most current load forecast and was used in the
preparation of this Study.
Financial and Economic Assumotions - The 2013 IRP financial and economic assumptions were also used for
this Study.
Carbon Adder Assumotions - For the 2013 lRP, three carbon adder assumptions have been developed and
include a low case of no carbon tax, a planning case with a 2018 start date at 514.54 per ton of COz emitted
escalated at 3% and a high case with a 2018 start date at 535.00 per ton of COz emitted escalated at 9%.
These forecasts are provided in Figure 2.
Figure 2. Carbon Adder Assumptions
Carbon Adder Assumptions
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-High
Carbon
Coal Unit Environmental Analysis Page 6
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 6 of 30
Description and Existins Maior Environmental lnvestments in Coal Units
Jim Bridser
The Jim Bridger coal-fired power plant consists of four units and is located near Rock Springs, Wyoming.
ldaho Power owns one-third of Jim Bridger with the other two-thirds owned by PacifiCorp. PacifiCorp is the
operator of the Jim Bridger plant.
These units have the following current net dependable capacity ratings:
Jim Bridger unit #1(JB1) 531MW
Jim Bridger unit #2 (JB2) 527 MW
Jim Bridger unit #3 (JB3) 530 MW
Jim Bridser unit f4 (JB4) 523 MW
Total Plant -2,111MW 1703.7 MW ldaho Power Share)
The following major emission control equipment has been previously installed on each unit at the Jim Bridger
plant:
Pollutants
NO,
Opacity
Soz
North Valmv
The North Valmy coal-fired power plant consists of two units and is located near Winnemucca, Nevada.
ldaho Power owns one-half of North Valmy with the other one-half owned by NV Energy. NV Energy is the
operator of the North Valmy plant.
These units have the following current net dependable capacity ratings:
North Valmy unit #1 (NV1) 252 MW
North Valmv unit #2 (NV2) 272 MW
Total Plant -524 MW (252 MW ldaho Power Share)
The following major emission control equipment has been previously installed at the North Valmy plant:
Controls
New Generation Low NO, Burners
Electrostatic Precipitators
Wet Scrubbers
Current Emission Limits
0.26|blMMBtu
20% Opacity
0.15|b/MMBtu
Current Emission Limits
0.45 lblMMBtu (averaged)
20% Opacity
70% removal
Pollutants ControlsNO, Early Generation Low NO, Burners
Opacity Baghouse
SO2 (Unit 2) Dry Lime Scrubber
Coal Unit Environmental Analysis PageT
Exhibit No. 6
Case No.lPC-E-13-16
T. Harvey, IPC
Page 7 of 30
Recent Environmental Resulations
The new regulations that have been proposed by the Environmental Protection Agency (EPA) over the last
few years have caused great concern among utilities that own coal-fired generation. The impact of the
proposed regulations will require extensive installation of emissions controls in a short period of time. ln
addition, these proposed regulations often override state decisions relating to control requirements. The
effectiveness of the regulations on health and visibility is controversial and highly debated.
Finol Mercury ond Air Toxic Standards (MATS) RuIe: ln April 2010, the U.S. District Court for the District of
Columbia approved, by consent decree, a timetable that would require the EPA to finalize a standard to
control mercury emissions from coal-fired power plants by November 2011. ln March 2011, the EPA released
the rule to control emissions of mercury and other Hazardous Air Pollutants (HAPs) from coal- and oil-fired
Electric utility steam Generating Units (EGUs) under the federal Clean Air Act (CAA). ln the same notice, the
EPA further proposed to revise the New Source Performance Standards (NSPS)for fossilfuel-fired EGUs.
Both the proposed HAPs regulation and the associated NSPS revisions were finalized on February 76,2072.
The regulation imposes maximum achievable controltechnology and NSPS on all coal-fired EGUs and replaces
the former Clean Air Mercury Rule. Specifically, the regulation sets numeric emission limitations on coal-fired
EGUs for total particulate matter (a surrogate for non-mercury HAPs), hydrochloric acid (HCL), and mercury.
ln addition, the regulation imposes a work practice standard for organic HAPs, including dioxins and furans.
For the revised NSPS, for EGUs commencing construction of a new source after publication of the final rule,
the EPA has established amended emission limitations for particulate matter, sulfur dioxide, and nitrogen
oxides. Utilities have three years for compliance, with a one year compliance extension for any utility or
plant that cannot feasibly install the pollution controls during the three year compliance window. ldaho
Power does not need nor can ldaho Power qualify for the one year extension, so all controls were assumed to
be completed within the three year time frame.
Notional Ambient Air Quoltty Stondords (NAAQS): The CAA requires the EPA to set ambient air quality
standards for six "criteria" pollutants considered harmful to public health and the environment. The six
pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide, and sulfur dioxide. States
are then required to develop emission reduction strategies through State lmplementation Plans (SlP) based
on attainment of these ambient air quality standards. Recent developments related to three of the
pollutants - PMz.s, NO,, and SOz are relevant to ldaho Power.
. Particulor Motter (PM. ). ln 1997, the EPA adopted NAAQS for fine particulate matter of less than
2.5 micrometers in diameter (PM2.5 standard), setting an annual limit of 15 micrograms per cubic
meter (pg/m3), calculated as a three-year average. ln 2005, the EPA adopted a 24-hour NMQS for
PM2 5. of 35 pglm3. All of the counties in Nevada, Oregon, and Wyoming have been designated as
"attainment" with these PM2 5 standards. However, on December 14,20L2, the EPA released final
revisions to the PM2.5 NAAQS. The revised annual standard is 12 pg,/m3, calculated as a three-year
average. The EPA retained the existing 24-hour standard of 35 pg/m3. Now that the PM2.5 NAAQS
has been finalized, states will make recommendations to the EPA regarding designations of
attainment or non-attainment. States also will be required to review, modify, and supplement their
SlPs, which could require the installation of additional controls and requirements for ldaho Power's
coal-fired generation plants, depending on the level ultimately finalized. The revised NAAQS would
Coal Unit Environmental Analysis Page 8
Exhibit No. 6
Case No.lPC-E-13-16
T. Harvey, IPC
Page 8 of 30
also have an impact on the applicable air permitting requirements for new and modified facilities.
The EPA has stated that it plans to issue nonattainment designations by late 2014, with states having
until 2020 to comply with the standards.
rer ln 2010, the EPA adopted a new NAAQS for NO, at a level of 100 parts per billion averaged over
a one-hour period. ln connection with the nu*;14AQS, in February 2012 the EPA issued a final rule
designating all of the counties in Nevada, Oregon, and Wyoming as "unclassifiable/attainment" for
NO,. The EPA indicated it will review the designations after 2015, when three years of air quality
monitoring data are available, and may formally designate the counties as attainment or non-
attainment for NO,. A designation of non-attainment may increase the likelihood that ldaho Power
would be required to install costly pollution control technology at one or more of its plants.
5O2. ln 2010, the EPA adopted a new NMQS for SOz at a level of 75 parts per billion averaged over a
one-hour period. ln 2OLl, the states of Nevada, Oregon, and Wyoming sent letters to the EPA
recommending that all counties in these states be classified as "unclassifiable" under the new one-
hour S02 NMQS because of a lack of definitive monitoring and modeling data.
Cleon Water Ad Section 376(b): ln March 2011, the EPA issued a proposed rule that would establish
requirements under Section 315(b) of the federal Clean Water Act for all existing power generating facilities
and existing manufacturing and industrial facilities that withdraw more than two million gallons per day
(MGD) of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively
for cooling purposes. The proposed rules would establish national requirements applicable to the location,
design, construction, and capacity of cooling water intake structures at these facilities by setting
requirements that reflect the Best Technology Available (BTA) for minimizing adverse environmental impact.
ln June 2012, the EPA released new data, requested further public comment, and announced it plans to
finalize the cooling water intake structures rule by June 2013.
New Source Perlormance Stondards (NSPS) lor Greenhouse Gas Emissions lor New EGUs.' ln March 2012,
the EPA proposed NSPS limiting Carbon Dioxide (COz) emissions from new fossilfuel-fired power plants. The
proposed requirements would require new fossil fuel-fired EGUs greater than 25 MW to meet an output-
based standard of 1,000 pounds of COz per MWh. The EPA did not propose standards of performance for
existing EGUs whose CO2 emissions increase as a result of installation of pollution controls for conventional
pollutants.
Clean Air Act (CAA) - Regional Haze Rules: ln accordance with federal regional haze rules under the CAA,
coal-fired utility boilers are subject to RH BART if they were permitted between 1962 and 1977 and affect any
Class I areas. This includes all four units at the Jim Bridger plant. However, North Valmy is not subject to the
regulation as it was permitted afler L977. Under the CAA, states are required to develop a SIP to meet
various air quality requirements and submit them to the EPA for approval. The CAA provides that if the EPA
deems a SIP submittal to be incomplete or "unapprovable," then the EPA will promulgate a federal
implementation plan (FlP)to fill the deemed regulatory gap. ln May 20t2, the EPA proposed to partially
reject Wyoming's regional haze SlP, submitted in January 20tt, for NO, reduction at the Jim Bridger plant,
instead proposing to substitute the EPA's own RH BART determination and FlP. The EPA's primary proposal
would result in an acceleration of the installation of Selective Catalytic Reduction (SCR) additions at JB1 and
Page 9
Exhibit No. 6
Case No. IPC-E-13-'16
T. Harvey, IPC
Page 9 of 30
Coal Unit Environmental Analysis
J82 to within five years after the FlP, or a SIP revised to be consistent with the proposed FlP, is adopted by
the EPA. The EPA had stated that it planned to adopt the FlP, or approve the revised Wyoming SlP, by late
2012. However, in December 2012 the EPA announced that it would re-propose the plant-specific NO,
control provisions of its RH FIP in March 2013 and would not finalize the RH FIP until September 2013.
Coal Combustion Residuols (CCR): The EPA has proposed federal regulations to govern the disposal of coal
ash and other CCR's under the Resource Conservation and Recovery Act (RCRA). The agency is weighing two
options: regulating CCR's as hazardous waste under RCRA Subtitle C, or regulating them as non-hazardous
waste under RCRA Subtitle D. EPA is not expected to issue a final rule sometime in 2013.
As a result of recent environmental regulation, ldaho Power's coal-fired plants will require additional
investment in environmental control technology as described below:
Jim Bridger will require the installation of the following controls to meet the RH BART and MATS regulations:
Unit
JB1
JB2
J83
J84
AllUnits
Pollutants Controls Reeulation
NO, SCR (2022) RHNO* SCR (2021) RH
NO, SCR (2015) RH BARTNO, SCR (2015) RH BART
Mercury CaBr2, scrubber MATS
additive, activated
carbon injection (2015)
Regulation
MATS
New Emission Limits
0.07|blMMBtu
0.07|blMMBtu
0.07|blMMBtu
0.071blMMBtu
1.0lbI'Btu
New Emission Limits
0.00201b/MMBtu
North Valmy will require the installation of a DSI system, for controlling HCL for acid gas compliance, to meet
MATS regulations:
Unit Pollutants ControlNV1 HCL DSr (201s)
Coal Unit Environmental Analysis Page 10
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 10 of30
Investment Alternatives
Base Alternatives
The Study analyzes three base alternatives for each unit. Each alternative is analyzed under the three carbon
and three natural gas sensitivities.
The alternatives include:
1l lnstall environmental upgrade - lnstall the required environmental controls to comply with a current,
proposed or reasonably anticipated regulation. For Jim Bridger this includes cost for compliance with
RH, MATS, CCR and the Clean Water Act Section 316(b). For North Valmy this includes the cost for
compliance with MATS
2l Retire the unit and replace with a CCCT - The capital cost estimate for the CCCT capacity used to
replace the retired coal-fired capacity in this Study was based on the installed cost of ldaho Power's
Langley Gulch plant that became commercially operational in June 2012.
The CCCT's are sized to replace the capacity of ldaho Power's share of the coal unit being replaced.
For example, if a 100 MW coal-fired unit is retired, it is replaced with 100 MW of CCCT capacity at a
Langley Gulch cost per kW. Of course, actual costs may be different, but for this Study however, we
believe that using the Langley Gulch cost per kW is a reasonable assumption. The CCCT units are
assumed to be located within the ldaho Power service territory.
3) Conversion of the unit to burn natural gas - Natural gas for Jim Bridger is assumed to be provided by
a pipeline approximately two miles from the plant. Natural gas for North Valmy is assumed to be
provided by a pipeline located approximately 13 miles north of the plant. The naturalgas conversion
capital and O&M costs used in this Study included installing a pipeline to the plant, modifications to
the boiler, and changes in heat rate or capacity due to firing with natural gas instead of coal.
The following table summarizes the base alternatives that were analyzed. lncluded are the potential
compliance deadlines for installing environmental controls and effective dates for the retirement and
replacement with CCCT and natural gas conversion alternatives:
Coal Unit Environmental Analysis Page 11
Exhibit No. 6
Case No.|PC-E-13-16
T. Harvey, IPG
Page 11 of30
Environmental
Compliance
Deadline
Retire/Replace {CCCT
& Natural Gas Conversion
Effective Date
North Valmy Unit #1
lnstallDSl
Retire/Replace with CCCI (DSl not installed)
Naturalgas conversion (DSl not installed)
Jim Bridger Unit #1
lnstall SCR
Retire/Replace with CCCI (SCR not installed)
Naturalgas conversion (SCR not installed)
Jim Bridger Unit #2
lnstall SCR
Retire/Replace with CCCT (SCR not installed)
Naturalgas conversion (SCR not installed)
Jim Bridger Unit #3
lnstall SCR
Retire/Replace with CCCT (SCR not installed)
Naturalgas conversion (SCR not installed)
Jim Bridger Unit #4
lnstall SCR
Retire/Replace with CCCT (SCR not installed)
Natural gas conversion (SCR not installed)
3l37l2O1s
12/3t12022
72/3Ll2O2t
L2l3Ll2OLs
t2l37l2Ot6
4lLl2ots
4ltl2O7s
tltl2023
tlu2023
Llu2O22
tlu2022
rlLl2016
Ll7l2016
71u2077
uu2077
ln addition to the base alternatives, ldaho Power was directed in Order No.72-177, issued by the Public
Utilities Commission of Oregon (OPUC or Commission) in Action item 11 as follows:
"ln its next IRP Update, ldaho Power will include an Evaluation of Environmental Compliance Costs
for Existing Coal-fired Plants. The Evaluation will investigate whether there is flexibility in the
emerging environmental regulations that would allow the Company to avoid early compliance costs
by offering to shut down individual units prior to the end of their useful lives. The Company will also
conduct further plant specific analysis to determine whether this tradeoff would be in the ratepayers'
interest."
ln accordance with the Commission's directive ldaho Power analyzed hypothetical scenarios including
compliance timing and the enhanced upgrade alternatives described below.
Coal Unit Environmental Analysis Page 12
Exhibit No. 6
Case No. IPC-E-I3-16
T. Harvey, IPC
Page 12 of 30
Compliance Timinc Alternatives (CTAI
ln addition to the base alternatives, ldaho Power analyzed avoiding the installation of required or reasonably
anticipated emission controls by delaying the compliance requirement by five years in exchange for shutting
the unit down at the end of the five year period. A negotiated delay is not an option that currently exists but
the Study quantifies the financial results of these alternatives.
ldaho Power co-owns all of its coal-fired generation, and ldaho Power is not the operating partner for any of
the coal-fired plants. Not being an operating partner removes flexibility that other utilities may have for
regulations allowing emission totaling, substitution or reductions at one facility to compensate for lower
reductions at another plant, or the option of shutting down a unit or plant in place of reductions at another
plant, or delaying installation of environmental controls for a guaranteed early shutdown. As IPC is not the
operating partner of Jim Bridger or North Valmy, it is highly unlikely ldaho Power would have the ability to
negotiate alternative scenarios as described above.
The following table summarizes the CTA alternatives that were analyzed. lncluded are the potential
compliance deadlines for installing environmental controls and effective dates for the retirement and
replacement with CCCT and natural gas conversion alternatives:
Enhanced Alternatives
The enhanced upgrade alternative was included for North Valmy which takes into account the possibility of
future environmental regulations that would require the installation of SCR and Wet Flue Gas Desulfurization
(WFGD) for compliance. At this time, there are no regulations requiring the installation of the emission
controls that are included in the enhanced upgrade alternative. Any future regulations are expected to have
at least a five- year compliance period. A five- year compliance window would require any investment or
replacement to be installed and in-service by 2018. The following table summarizes the enhanced
alternatives:
Page 13
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 13 of30
Compliance Timing Alternatives (CfA)
Environmental
Compliance
Deadline
Retire/Replace VCCCT
& Natural Gas Conversion
Effective Date
North Valmy Units #1& #2
Retire both units
Retire/Replace with CCfi (SCR & WFGD not installed)
Natural Gas Conversion (SCR & WFGD not installed)
Jim Bridger Units f3 & #4
Retire both units
Retire/Replace with CCCT (SCR not installed)
Natural Gas Conversion (SCR not installed)
t2l3u2022
L2l3u202O &1213u2027
tlu2o23
uu2o23
Llu2l2t&tlu2o22
Llu202t&t1u2022
Coal Unit Environmental Analysis
Enhanced Alternatives
Environmental
Compliance
Deadline
Retire/Replace dCCCT
& Natural Gas Conversion
Effective Date
North Valmy Unit #1
Enhanced Upgrade (installation of SCR & WFGD)
Retire/Replace with CCCT (SCR & WFGD not installed)
Naturalgas conversion (SCR & WFDG not installed)
North Valmy Unit #2
Enhanced Upgrade (installation of SCR & WFGD)
Retire/Replace with CCCI (SCR & WFGD not installed)
Naturalsas conversion (SCR & WFGD not installed
Lltlzots
Results
SAIC lndividual Unit Analvsis
The SAIC analysis included the following objectives:
r Review ldaho Power's assumptions for capital costs of the proposed environmental compliance
upgrades, including SCR, DSl, WFGD, and other systems, as well as the costs of replacement capacity.
Review ldaho Power's assumptions for variable costs of the proposed environmental compliance
upgrades, coal replacement with CCCT's and natural gas conversion. ldaho Power provided SAIC
forecasted generation output for each unit from AURORA. ldaho Power also provided plant
operational data obtained from the coal unit's co-owner and operator; PacifiCorp for the Jim Bridger
units and NV Energy for the North Valmy units.
Develop cost estimates for replacing the coal units annual generation, under three natural gas and
three carbon futures, with three investment alternatives: (1) installing environmental compliance
upgrades, (2) retiring the unit and replacing with CCCT or (3) converting the unit to natural gas. These
total costs include capital costs, O&M, decommissioning costs and unrecovered investments of the
existing coal units.
r Develop a capital investment analysis allowing assets with different lengths of operation as well as
different implementation dates to be compared equitably.
I Provide planning recommendations regarding the three investment alternatives.
The following table summarizes the results from the SAIC analysis. The left column groups each unit with the
investment alternatives. The columns to the right show the net present value (NPV) of operating and capital
costs over the twenty-year period 2Ot3-2O32 in 2013 dollars. The green highlighted cell indicates the least
cost option for the unit under each scenario. SAIC's investment recommendations, which can be found in
their report Coal Environmental Compliance Upgrade lnvestment Evaluation Section 5 Conclusions.
The SAIC results are summarized in Figure 3 below:
Page L4
Exhibit No. 6
Case No. IPC-E-'I3-16
T. Harvey, IPC
Page 14 of 30
Coal Unit Enyironmental Analysis
Flgure 3. SAIC Analysis Summary Results by Scenario for the 2013-2032 Forecast Perlod ($ZOfg Mllllons)
ldaho Power Portfollo Analvsis
ldaho Power utilized the AURORA modelto determine the total portfolio cost of each investment alternative
analyzed by SAIC. The total portfolio cost is estimated over a twenty-year planning horizon (2013 through
20321. ldaho Power used the simulated operational performance of each investment alternative relative to
the existing resource under varying future naturalgas price forecasts and carbon adder assumptions. ldaho
Power conducted the simulation using the AURORA model. The AURORA model applies economic
assumptions and dispatch cost simulations to modelthe relationships between generation, transmission, and
demand to forecast future electric market prices. AURORA is ldaho Powe/s primary tool used to simulate
the economic performance of different resource portfolios evaluated in the !ntegrated Resource Planning
(lRP) process.
The fixed costs used by SAIC are incorporated into the ldaho Power Study. SAIC reviewed the fixed costs of
each investment alternative and scheduled the costs annually for the various investment alternatives for the
twenty-year study period. These annual costs included environmental capital investments, ongoing capital
expenditures, unit replacement capital and the fixed O&M costs for the specific unit configuration. The ldaho
Power Study combines the Net Present Value (NPV) of the fixed costs from the SAIC model; with the NPV of
Page 15
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey,lPC
Page 15 of 30
Coal Unit Environmental Analysis
the twenty-year Aurora generated total portfolio cost to form the basis for the quantitative evaluation of the
investment a lternatives.
Figure 4, below, summarizes the combined NPV results of ldaho Powe/s Aurora analysis and SAICs fixed
costs analysis for each investment option under varying carbon and natural gas futures. The planning case
(planning case carbon/planning case naturalgas) is denoted in bold.
The left column groups each unit with the investment alternatives. The columns to the right show the NPV of
the total portfolio costs over the twenty-year period (2013-2032) in 2013 dollars. The green highlighted cell
indicates the least cost option for the unit under that scenario. The preponderance of least cost outcomes
and the relative cost difference between alternatives helps determine the investment recommendation.
Figure 4. Total Portfolio Costs
ldaho Power Company
Coal Environmental lnvestment Modeling Results
Total Portfolio Costs (Aurora Portfolio Cost + SAIC Fixed Costs )
Forthe 20 year forecast period 201+2032
NPV in 2013 SMillions
NPV of the Total Portfolio Cost for the 3 natural ras and 3 carbon adder futures
lnvestment Alternatives
NG High
3o, So
NG High
3O2 s14
NG HiSh
lor 53s
NG Low
lo, S0
NG Low
:o, S14
NG Low
lo, S3s
NG
,lanning
30, S0
NG
Planning
co, s14
NG
)lanning
:O, S35
/almy 1(V1) DSI
/1 2015 retire/replace with CCCT
/1 2015 natural Bas conversion
6,805 3,955
3,922
d800 6,889 6,879
1,079
3,869
4,800
4,681
4,O32
3,927
1,719
4,7126,775 4,722 6,786 5,797
/1 V2 Enhanced Upgrade (SCR & WFGD) 2018
/1 V2 retire/replace with CCCT 2018
/1 V2 natural gas conversion 2018
5,167
5,,-24
7,38E
6,951
4,580
4.281
5,372
4,983
7,439 4,474
4,379
5,332
5,096
7,428
4,403
4,335 6,969 6,979
fA - V1 V2 Enhanced Uptrade (SCR & WFGD) 2023
:TA - Vl v2 retire/replace with CCCT 2023
fA - V1 V2 natural Eas conversion 2023
5053 7,3t5 4,512 5,315 7,370 4,373 5,255 7,371
4,256
4,301 5,093 7,U7 4,275 5,000 7,O75 4,335 5,113 7.toa
im Bridg€r 1 (JBl) lnstall sCR
81 retireteplace with CCCT 2023
B1 natural cas conversion 2023
4,O54
4,0u
4,479
4,911
5,952
7,005
4,156
4,155
4,942
4,955 6,943
4,149
4,167
a,966
4,ru
6,943
7,072
im Bridger 2 (J82)lnstall SCR
82 retire/replace with CCCT 2022
82 natural gas conversion 2022
4,117
4,105
4,935
4,928
7,O09
7,008
4,198
4,162
4,981
4,969 6,935
4,20r
4,179
5,015
a_992
6,980
7,049
im Bridger 3 (JB3) lnstall SCR
83 retire/replace with CCCT 2016
83 natural gas conversion 2016
4,237
4,207
5,016
4,989
7,O22
7,O20
4,207
4.1\t
4,91.7
1,927 6,853
4,253
4,210
5,030
a-tlt
6,931
6.95q
im Bridger 4 (JB4) lnstall SCR
84 retire/replace with CCCT 2017
84 natural gas conversion 2017
4,205
4,180
4985
4,961
6,984
6 qat
/1,189
a lar
4,935
4,915 6,825
4,235
4,195
5,000
&erl
5,903
6,934
ITA - JB3 JB4 lnstall sCR
lfA - JB3 JB4 retire/replece w CCCI 2O2O-21
:TA -l83 J84 natural tas conv€rsion 2020-21
4,895
4.980
5,576
q 6qn
7,357
7.545
4,539
4.572
5,209
q lno
4,742
4.4O7
5,126
q tt27.086 7.354
Coal Unit Environmental Analysis Page 16
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 16 of30
Conclusions and Recommendations
North Valmv Unit #1
North Valmy is a critical facility for the reliability of the electric system in northern Nevada.
With the exception of the installation of DSI for MATS compliance, under current and proposed regulations
further environmental investment is not required for the continued operation of NV1. lnstallation of DSI was
the lowest cost result for most of the sensitivities analyzed by SAIC. The SAIC results show installing DSI as
the least cost option in six of the nine sensitivities analyzed including the planning scenario (planning natural
gas/planning carbon).
The AURORA analysis, performed by ldaho Power, shows installing DSI as the least cost option in four of the
nine sensitivities analyzed including the planning scenario (planning natural gas/planning carbon). The
majority of scenarios not supporting the installation of DSI are the extreme low natural gas and high carbon
cases which have a lower probability of occurring.
ldaho Power's conclusion is that the option to make the DSI investment represents a low cost approach to
retain a diversified portfolio of generation assets including the 125 MW's of NVl capacity for our customers
benefit. The continued operation of NV1 as a coal-fired unit will provide fuel diversity that can mitigate risk
associated with high natural gas prices. While noting that ldaho Power does not recommend the
retire/replace with CCCT option orthe conversion of the unit to naturalgas, it is also important to recognize
that such replacements and conversions do not happen instantaneously. Conversion to naturalgas could
require from three to six years for permitting, installation of the natural gas pipeline, and boiler
modifications. Permitting and construction of a CCCT would require approximately four years.
Based on these results, ldaho Power recommends installing DSI and continuing to include NV1 in its
generation portfolio for the 2013 IRP and future resource planning.
Figure 5 illustrates the results of the Study for installation of DSI at NVl and Figure 6 contains a comparison
of the costs of the DSI investment to the retire/replace with CCCT and natural gas conversion alternatives:
Coal Unit Environmental Analysis Page 17
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 17 of30
Figure 5. NVl DSI lnstallation Results
North Valmy Unit #1
Sg,ooo
E s7,ooo
= s6,000
6hH ss,ooo
:g* S4,ooo
oi s3,ooo
oE s2,ooo4e sl,oooz
SO
---;y5,1.:::3$'-5.i5$1..:;::\ji;i$5ffi ""'-'
etF$
Sensitivities
Figure 5. NV1 DS! lnstallation Cost Deltas
Hirh Nc Hish NG Hlah NG Low NG Low NG Low NG Pl.nnlnt NG
tdw CO,
PLAI{]{ttc ltc Pl.nnln! l,lc
Hi.h CO'
lnltrll DSI s6.805 93.965 34-8oo S8.889 S6-879
R.tl rc/R€pl a c.
s4.079 34-800 s3.922 34.032 Sa.7a9
Nrtural Gas
Convarsion (i a6g s4.581 s6.775 s4.722 s5.785 s3.927 s4.732 s6.797
lnstall DSI-
Rltirc/R!pl.c! CCO t1201 l2s2l 154 4 177 3L7 l17Sl lltl 2te
lnstall DSI-t{G
convdsion 1210)(1321 30 45 7e 1O/t {71t 12l a2
Coal Unit Environmental Analysis Page 18
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 18 of 30
North Valmv Unit #2
At this time, under current and proposed regulations, further environmental investment is not required for
the continued operation of NV2. Additional analysis will be performed if future regulations require significant
environmental investments in NV2.
ldaho Power recommends including NV2 in its generation portfolio for the 2013 IRP and future resource
planning.
North Valmv Units #1 and #2 (Combined Analvsisl
The assumption in the North Valmy Enhanced Upgrade alternative is both units are upgraded, replaced or
converted to burn natural gas at the same time. The Enhanced Upgrade alternative includes installation of
SCR and WFGD. Consequently, a combined investment analysis is made for both units.
Under both the SAIC and AURORA analyses, proceeding with the Enhanced Upgrade environmental
investments at NV1 and NV2 are not supported. However, as there are no current or proposed regulations
requiring this investment, ldaho Power recommends including NVl and NV2 in its planning and as part of
ldaho Power's generation portfolio.
Figure 7 illustrates the results of the Study for the Enhanced Upgrade at NV1 and NV2 and Figure 8 contains a
comparison of the Enhanced Upgrade costs to the retire/replace with CCCT and natural gas conversion:
Page 19
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 19 of 30
Coal Unit Environmental Analysis
Figure 7. NVl and NV2 Enhanced Upgrade Results
North Valmy Units #1 and #2
uco
=(rt
oNv!
6
6oIo=oEoc
oz
s8,ooo
57,000
s6,ooo
s5,ooo
S4,ooo
s3,000
s2,000
s1,000
SO
I lnstall SCR & WFGD
I Retire/Replace w/CCCT
r Natural Gas Conve6ion
--.;y*$""1:-."-I*-:$"55l""1gl-11;;i$1ffi ""'-"
ttl'
Sensitivities
Hlrh NG
Low CO,
Hith NG
Pl a nni nr COr
High NG Low NG
Low COr
Low NG tflNG
Hlrh COr
Pl.nning NG
Low COr
PLAI{TTING ]{G
DI Af,ilNA TG
Pl.nniry NG
Hl.h ad-
lnst ll SCR & WFGD s5.r57 37,388 s4,580 ss.372 s7.439 s4.474 3s332 s7.428
Reti lelRepl. c!
wlccrr S,l.4o3 s5.124 s6,961 s4.283 34.983 s4,379 ss.095
lnst ll SCR & WFGD
Rdi../Rml,..ls12Al 343 3,1a7 s2qa s3a9 (s36 s9S 32:t6 S4so
lnstall SCR & WFGD-
NG convcrsion ls60l S1o9 S4Go 3!16 sltq3 (a7o (1a?3ira Saso
Figure 8. NVl and NV2 Enhanced Upgrade lnstallation Cost Deltas
Additional analysis was performed using the compliance timing alternative. The results of delaying the
implementation date do not support proceeding with the Enhanced Upgrade environmental investments on
NV1 and NV2.
ln the event additional environmental controls are required for NV1 and NV2, the compliance requirements
and available control technologies will be analyzed to determine whether installing the environmental
controls are the least cost/least risk option.
Page 20
Exhibit No. 6
Case No.|PC-E-13-16
T. Harvey, IPC
Page 20 of 30
Coal Unit Environmental Analysis
Figure 9 illustrates the results of the Study for the Enhanced Upgrade compliance timing alternative at NV1
and NV2 and Figure 10 contains a comparison of the compliance timing alternative Enhanced Upgrade costs
to the retire/replace with CCCT and natural gas:
Flgure 9. NVl and NV2 Enhanced Upgrade Compliance Timing Alternative Results
North Valmy Units #1 and #2
0co=
=nt
oN{,}
UI
0o(,
o
o
or
4z
s8,000
s7,000
S5,ooo
s5,ooo
s4,000
S3,ooo
s2,ooo
51,000
So
r tnstall scR & WFGD
r Retire/Replace w/CCCT
I Natural Gas Conversion
--.;55$"::."$*":Tl1;;*$.\$"];i$iffi ""'-'
ttfi
Sensitivities
Figure 10. NVl and NV2 Enhanced Upgrade Compliance Timing Alternative Cost Deltas
HiEh NG
Low CO2
High NG High NG LowNG low NG Low NG Plannlnt NG PTAilT{ING]IG
dANIM'G
Planning t{G
lnstall scR & wF60 s5,053 s7.316 s4,s12 ss.31s s7.370 s4,373 s52s5 s7.371
Natural Gas
Convats i on s4-301 s5.093 s7.O47 s4.27s s5.oo0 s7.o75 s4,335 ss.r13 s7.108
lnstall SCR & WFGD
edr. P.hl,..(s801 S21 s339 s248 s332 5411 S66 3r7a S35{
rnst ll scR & WFGD.
NG convcrsion (51241 (3311 5259 s237 531s s294 s38 Srr2 S253
Coal Unit Environmental Analysis Page21.
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 21 of30
Jim Brideer Unit #1
Under both the SAIC and AURORA analyses, proceeding with environmental investments at J81 is the lowest
cost option for the majority of the carbon and natural gas scenarios. ln the most probable scenario, the
ldaho Power planning scenario which identifies a planning carbon and planning natural gas future, the
environmental upgrade option is overwhelmingly the least cost option.
The installation of SCR, which is the most significant of the environmental investments analyzed, is far
enough in the future to make the forecast assumptions highly speculative. As ldaho Power nears the actual
SCR investment decision point, a more detailed analysis will be performed with updated assumptions.
Based on these results, ldaho Power recommends continuing to include JB1 in its generation portfolio for the
2013 IRP and future resource planning.
Figure 11 illustrates the results of the Study for installation of required environmental controls at J81 and
Figure 12 contains a comparison of the installation of required emission controls to the retire/replace with
CCCT and natural gas conversion options:
Figure 11. JB1 Results
Jim Bridger Unit #1
6co=
=nl
or{{,}
0
oIo
o
oA
a-z
Se,ooo
s7,000
S6,ooo
S5,ooo
S+,ooo
S3,ooo
s2,000
S1,ooo
So
r lnstall Controls
I Retire/Replace w/CCCT
I Natural Gas Conversion
--.;y-$.:;:I.:$'.:Tli-$":giilii$5ffi ""*
ttF'
Sensitivities
Coal Unit Environmental Analysis Page22
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 22 of 30
Figure 12. JBl installation of Emission Controls Cost Deltas
High NG
Low COr
High NG
Planninc C0'
High NG
Hirh CO'
tow NG
Low COr
low NG
Plannim CO,
Low NG
Hirh aO,
Planning NG
Low COr
PIAT{III{G ilG
PLAI{[{ING COr
Planning l,lc
ltirh afl,
Retire/Replace
wlca?T s4.054 s4.879 s6.962 s4.1s6 sl-912 s4-1a9 sa356 s6.941
Natural Gas
Conversion s4.084 s4.911 s7.00s s4.16s s4.95s s6.943 s4.167 3a.98a s7.012
lnstall controls-
R€tire/Replace CCCT ts429)ts35st (s191)ls22s)(s177)s8 (s325t 132701 ls9E)
lnstall conttols- NG
convssion (s4s9)(s3971 ls2lSl (s234t ls200l ls88t (s34s)t3217t ts167)
Jim Bddeer Unit #2
Under both the SAIC and AURORA analyses, proceeding with environmental investments at JB2 is the lowest
cost option for the majority of the carbon and natural gas scenarios. ln the most probable scenario, the
ldaho Power planning scenario which identifies a planning carbon and planning naturalgas future, the
environmental upgrade option is overwhelmingly the least cost option.
The installation of SCR, which is the most significant of the environmental investments analyzed, is far
enough in the future to make the forecast assumptions highly speculative. As ldaho Power nears the actual
SCR investment decision point, a more detailed analysis will be performed with updated assumptions.
Based on these results, ldaho Power recommends continuing to include J82 in its generation portfolio for the
2013 IRP and future resource planning.
Figure 13 illustrates the results of the Study for installation of required environmental controls at J82 and
Figure 14 contains a comparison of the installation of required emission controls to the retire/replace with
CCCT and natural gas conversion options:
Coal Unit Environmental Analysis Page23
Exhibit No. 6
Case No. IPC-E-I3-16
T. Harvey, IPC
Page 23 of 30
Figure 13. JB2 Results
Jim Bridger Unit #2
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oa
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--tX$T."':*T"-$15:$-:lTffi ll**y*;T"e*
9r!
Sensitivities
Figure 14. J82 installation of Emission Controls Cost Deltas
Hith ilG Hith NG Hirh NG Low NG
tow CO'
Low NG Iow NG Pl.nnina NG PIA'IilIilG I{G
?LANNI'IG COb
Pl.nnint NG
Hirh aO.
R.ti rdRcpl . c.
wlcccl S4.117 34.93s S7.oo9 S4.19r S4.981 s4.201 35r15 q6 gao
Naturrl Gal
Conv6rlon 34-ios s4.928 E7.oo8 51.162 S4-969 S6.935 34.u9 3a392 s7.009
l.tlr./R€!|.c. cCCl 1s462)1s391)ts209)(s238t ts187l S2s (3349t 132891 1410rl
lnstall controls-NG
convaa!ion rsasot lsr8al 132081 t3202t l(174t a3so)rs327t 132551 lsl3S)
Coal Unit Environmental Analysis Page24
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 24 of 30
Jim Brideer Unit #3
Under both the SAIC and AURORA analyses proceeding with environmental investments at J83 is the lowest
cost option for the majority of the carbon and natural gas scenarios. ln the most probable scenario, the
ldaho Power planning scenario which identifies a planning carbon and planning natural gas future, the
environmental upgrade option is overwhelmingly the least cost option. Based on these results ldaho Power
concludes that making the environmental investments in J83 is the most prudent action and provides the
lowest cost and least risk option.
Based on these results, ldaho Power recommends proceeding with the installation of all identified
environmental controls (including SCR) and continuing to include J83 in its generation portfolio for the 2013
IRP and future resource planning.
Figure 15 illustrates the results of the Study for installation of required environmental controls at J83 and
Figure 15 contains a comparison of the installation of required emission controls to the retire/replace with
CCCT and natural gas conversion options:
Figure 15. JB3 Results
Jim Bridger Unit #3
0to
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00oIo
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4z
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s7,000
s6,ooo
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t lnstall controls
r Retire/Replace w/CCCT
r Natural Gas Conversion
--.;y5;::::$$'.:::i5;:::ffi (l:,::::h""*"
,.F'Sensitivities
Coal Unit Environmental Analysis Page 25
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 25 of 30
Hiah NG High NG High NG
Hl.h ad-
Low NG Low NG Low NG PlanninX NG Ptat{I{ll{G xG Pltnni nl NG
Rcti.e/Rcpl!cc W/CCC s4,231 55,016 97,O22 S4.201 s4,947 s4,253 s5rl0 s5,931
Natural Gas
Convrsion 54,2O7 s4,989 s7,020 s4,1s4 s4,92t s6.853 s4,210 343r8 s5.969
lnstall cont ols-
Rdi rrlRrph c. CCCT (ss58)(54et (s214)(32331 {s1441 s13s (s393)ts295t {s491
lnst ll controls-NG
convdsioh lSs,14)(s4371 ts211)(31851 (s1241 S3e (s3501 ts250 lsETl
Flgure 16. JB3 installataon of Emlssion Controls Cost Deltas
Jim Bridger Unlt #4
Under both the SAIC and AURORA analyses proceeding with environmental investments at J84 is the lowest
cost option for the majority of the carbon and natural gas scenarios. ln the most probable scenario, the
ldaho Power planning scenario which identifies a planning carbon and planning natural gas future, the
environmental upgrade option is overwhelmingly the least cost option. Based on these results ldaho Power
concludes that making the environmental investments in J84 is the most prudent action and provides the
lowest cost and least risk option.
Based on these results, ldaho Power recommends proceeding with the installation of all identified
environmental controls (including SCR) and continuing to include J84 in its generation portfolio for the 2013
IRP and future resource planning.
Figure 17 illustrates the results of the Study for installation of required environmental controls at J84 and
Figure 18 contains a comparison of the installation of required emission controls to the retire/replace with
CCCT and natural gas options:
Page26
Exhibit No. 6
Case No.|PC-E-13-16
T. Harvey, IPC
Page 26 of 30
Coal Unit Environmental Analysis
Jim Bridger Unit #4
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-"g:;*\5l-,1:l.i$,}\:$1i:i$5ffi '-'
ttll
Sensitivities
Figure t7.lU Results
Figure 18. JB4 installation of emission controls Cost Deltas
HlSh Nc
Low COz
Hlgh NG
Pl.nnlhr CO'
High NG Lotil NG Low NG !ilNG
Hlrh CO,
Planning NG
tow CO,
PtAilTITG XG
PLATf,I{GCO"
Planning N6
Hetlre/Replace
w/cccr s4.205 s4.98s s6.984 s4.189 s4.935 s4.235 ss.009 s5.903
Natural Gas
Conrrersion s4.180 s4.951 s5.983 s4.141 s4.915 s6"825 s4.19S 3{371 s5.934
lnstall controls-
Rltire/R€place CCCI (ss42l (s4331 (917st (s221 (s1321 s1s7 (s37st ts275t {s21}
lnstall con&ols- NG
conversion (s5181 (s409)(s175)(s173)(s112 S68 (s33sl ls237l (ss2)
Coal Unit Environmental Analysis Page27
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 27 of 30
Jim Bridser Units #3 and ,r4 (Combined Analvsisl
The assumption in the compliance timing alternative is both J83 and J84 are not upgraded and are replaced
or converted to burn natural gas with a five year delay. Consequentially, a combined investment analysis is
made for both units.
As shown in the figure above, the results of the compliance timing alternative still support the installation of
emission controls on J83 and J84.
Figure 19 illustrates the results of the Study for the installation of controls compliance timing alternative at
J83 and JB4 and Figure 20 contains a comparison of the compliance timing alternative costs to the
retire/replace with CCCT and natural gas conversion options:
Figure 19. J83 and J84 Compliance Timing Alternative Results
Jim Bridger Units #3 and #4
Compliance Timing Alternat:ves
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0
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I Retire/Replace W/CCCT
I Natural Gas Conversion
--15$*.$"-i$1"55'l-1::\5ff 5ffi ""'"-
Sensitivities
Coal Unit Environmental Analysis Page 28
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 28 of 30
Figure 20. JB3 and JB4 Compliance Timlng Alternative Cost Deltas
Hlfh NG
16w CD'
HlSh NG Hlth NG tilNG Low NG
ot
Low NG Pl.nnint NG PfA]IililG ]{G Pl.nninS NG
x4trl/Eaplaca
w/ccfr s4.895 ss.s76 37.3s1 s4.539 s5.209 s{-712 ssr25
Natural Gas
ConvFsion s4.980 s5.598 (7 SiiS 94.s72 ss.300 s7.086 s4.807 s5512 s7.354
lnstall controls-
Rctrt/RlDlac. CCCT 131.oor (s7931 1s312)ls339l ls17St S339 (36501 l3a60l 3s
ln3t!ll controls-NG
convgsaon a31-086t (s9151 (ss0st as373l ts266l S38 (371s1 r3sail ts240t
Coal Unit Environmental Analysis Page29
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 29 of 30
Review Process and Action Plan
The objective of this Study is to ensure a reasonable balance between protecting the interests of customers,
meeting the obligation to serve the current and reasonably projected future demands of customers, and
complying with environmental requirements, while recognizing that the regulatory environment is uncertain.
ln a commitment to honor these goals ldaho Power intends to perform systematic reviews, similar to this
analysis, whenever certain triggering events occur. These triggering events include:
o A significant change in the current state of environmental regulation
o A significant change in the estimated cost of anticipated environmental controls
o Within a year of committing to a major environmental upgrade
o Whenever ldaho Power files an lntegrated Resource Plan
ln conclusion, this Study shows the economics of incremental environmental investments is highly dependent
upon the assumptions for both naturalgas and carbon adders. This Study highlights the challenge in making
investment decisions today in the face of significant uncertainties. Despite these uncertainties, certain
environmental control equipment investment decisions must be made in the near-term. ldaho Power will
continue to work with regulatory agencies and stakeholders to analyze these major investment decisions
prior to commitment and implementation.
Coal Unit Environmental Analysis Page 30
Exhibit No. 6
Case No. IPC-E-13-16
T. Harvey, IPC
Page 30 of 30
-T-
I
I
rrelii,t posiion
Don C. Reading
I Vice President and Consulting Economist
i 8.S., Economics C Utah State University
M.S., Economics C University of OregonI Ph.D., Economics c Utah State University
t-
I
:
I
I
iI
I
Education
Honors and
Auards
Professiondl
and Business
History
Firm F.xpeience
o*iiro" b.lta bpsilon, NSr r.tto*rt"rip
Ben Johnson Associates, Inc.:
1989 -- Vice President
1986 -- Consuhing Economist
Idaho Public Utilities Commission:
1 9 8 1-86 Economist/Director of Policy and Administration
Teaching:
1 980-8 1 Associate Professo r, U niversity of Hawaii-Hilo
1970-80 Associate and Assistant Professor, Idaho State University
1968-70 Assistant Professor, Middle Tennessee State University
Dr. Reading provides expert testimony concerning economic and regulatory
issues. He has testified on more than 45 occasions before utility regulatory
commissions in Alaska, California, Colorado, the District of Columbia,
Hawaii, Idaho, Nevada, North Dakota, North Carolina, Oregon, Texas,
Utah, \(yoming, and Vashington.
Dr. Reading has more than 30 years experience in the field of economics. He
has participated in the development of indices reflecting economic trends,
GNP growrh rates, foreign exchange markets, the money supply, stock marketi
levels, and inflation. He has analyzed such public policy issues as the minimumi
wage, federal spending and taxation, and impon /expon balances. Dr. Reading j
is one of four economists providing yearly forecasts of statewide personal
1
income to the State of Idaho for purposes of establishing state personal income I
tax rates.
In the field of telecommunications, Dr. Reading has provided expert testimony
on the issues of marginal cost, price elasticity, and measured service. Dr.
Reading prepared a state-specific study of the price elasticity of demand for
local telephone service in Idaho and recently conducted research for, and
directed the preparation of, a report to the ldaho legislature regarding the
Reading, Di
Exhibit 201
Page I
status of telecommunicatio:rs competition in thal s1a19.
forecasting, long-range planning, price elasticity, marginal and average cost
i
pricing, production-simulation modeling, and econometric modeling. Among I
his recent cases was an electric rate design andysis for the Industrial Customersl
of Idaho Power. Dr. Reading is currently a consultant to the Idaho
Legislature=s Committee on Electric Restructuring.
Since 1999 Dr. Reading has been affiliated with the Climate Impact Group
(CIG) at the Univenity of Vashington. His work with the CIG has involved
an analysis of the impact of Global Iilarming on the hydo facilities on the
Snake River. It also includes an investigation into water markets in the
Nonhvrest and Florida. In addition he has analyzed the economics of
snowmaking for ski area's impacted by Global \fiarming.
Among Dr. Reading's recent projects are a FERC hydropower relicensing
srudy (for the Skokomish Indian Tribe) and an analysis of Northern States
Power's North Dakota rate design proposals affecting large industrial
customers (forJ.R. Simplot Company). Dr. Reading has also performed
analysis for the ldaho Governor's Office of the impact on the Northwest
Power Grid of various plans to increase salmon runs in the Columbia River
Basin.
Dr. Reading has prepared econometric forecasts for the Southeast idaho
Council of Governments and the Revenue Projecrion Commirtee of the Idahc>
State Lrgislature. He has also been a member of several Nonhwest Power
Planning Council Statistical Advisory Committees and was vice chairman of
the Governor's Economic Research Council in ldaho. He is currently a Public
Vorks Commissioner for the City of Boise.
\(hile at Idaho State University, Dr. Reading performed demographic studies
using a cohort/survival model and several economic impact studies using
input/output analysis. He has also provided expert testimony in cases
concerning loss of income resulting from wrongful death, injury, or
employment discrimination. He is currently a adjunct professor of economics
at Boise State University (Idaho economic history, urban/regional economics
and labor economic.)
Dr. Reading has recendy completed a public interest water rights transfer case.
He has also just completed an economic impact analysis of the 2001 salmon
season in Idaho.
Reading, Di
Exhibit 201
Page2
rlit
I
Publications i
I
iThe Economic Impact of a Restored Salmon Fishery in Idaho, Idaho Fish and
Mildlife Foundation, April, 1999.
I
ffhe Economic Impact of Steelhead Fishing and the Return of Salmon Fishing
in Idaho, Idaho Fish and \flildlife Foundation, September, 1997.
1
ACost Savings from Nuclear Resources Reformr An Econometric ModelG
.(with E. Ray Canterbery and Ben Johnson) Southem Econornic Journal, Sprtng
:L996.
:
;.4, Visitor Analysis for a Birds of Prey Public Attraction, Peregrine Fund, Inc.,
November, 1988.
1
II
[nvestigation of a Capitalization Rate for I&ho Hydroelectric Projects, Idaho
State Tax Commission, June, 1988.
Il"Post-PURPA Views," In Proceedings of the NARUC Biennial Regulatory
Conference, 1983.
lAn Input-Output Analysis of the Impact from Proposed Mining in the Challis
pA,rea (with R. Davies). Public Policy Research Center, Idaho State University,
february 1980.
ilpbosphote and. Soutbeast: A Socio Econornic Analyszs (with J. Eyre, et al).
lGorer.rn errt Research Institute of Idaho State University and the Southeast
ldaho Council of Governments, August 1975.
ilEstimatingGeneral Fund Retxnues of the State of ldaho (with S. Ghazanfar and
D. Holley). Center for Business and Economic Research, Boise State
iUniversity, June 1975.
i |}*No1e oqtb€ Q!_s1rib$iol o{ Fgderll.flpen-{!ry9ry A4"r,tq$31g
Reading, Di
Exhibit 201
Page 3
Reading, Di
Exhibit 201
Page 4
5. Planning Period Forecasts ldaho Power Company
Average Monthly Energy Planning
Average-energy surpluses and deficits are determined using 70ft-percentile water and
7Oth-percentile average load conditions, coupled with tdaho Power's ability to import energy
from firm market purchases using a reserved network capacity. Figure 5.4 shows the monthly
average-energy surpluses and deficits with existing and committed resources. The energy
positions shown in Figure 5.4 also include the forecast effect of existing DSM programs,
the current level of PURPA development, existing PPAs, firm Pacific Northwest import
capability, and the expected generation from all Idaho Power-owned resources, including the
Shoshone Falls upgrade when it is available. Figure 5.4 illustrates there are no energy deficits
through the planning period.
OFNOiO@NOOO-NNNNNNNNNNN('lOOeaee&AeeeeaAeo6666GG60GO66a-------a----
Figure 5.4 Monthly average-enelgy surpluses and deficits with existing and committed resources
and existing OSU FOt--percentile water and 70tr-percentile toad)
Energy deficits are eliminated by designing portfolios containing new resources analyzed in the
IRP. However, ldaho Power's resource needs have historically been driven by the need for
additional summertime peak-hour capacity rather than additional energy. Peak-hour capacity
continues to be the resource need in the 2013 IRP.
Peik-Hour Planning
Peak-hour load deficits are determined using 90th-percentile water and 95th-percentile peak-hour
load conditions. In addition to the peak-hour criteria, 70h-percentile average load conditions are
analyzed for the average-energy load and resource balance. The hydrologic and peak-hour load
criteria are the major factors in determining peak-hour load deficits. Peak-hour load planning
criteria are more stringent than average-energy criteria because Idaho Poweros ability to import
additional energy is typically limited during peak-hour load periods.
Idaho Power's customers reach a maximum energy demand in the summer. Idaho Power's
existing and committed resources are insufficient to meet the projected peak-hour growth,
and the company's customers in Oregon and Idaho face significant capacity deficits in the
summer months if additional resources are not added.
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Idaho Power - About Us - Company Information - Facts - Typical Fuel Mix Page I ofl
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ah.a ld$o Fqf,rrd6 rot fi! lrt. R.n lrdac Elo[!il Ca(ffial.| (REC!) a..odabd $ft il
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b*!g dalr,larrt b oir iltd qltbrt;t. For,ltqr hfioandon m [ra an a!! trvqldb ourlrt o,.bmal! ree Electricity Delivered lo Custofl|ers.
2 lfilro Pqfi€/s lu/drod.ctlo oan nllm b b6ad oo 201 1 lnleoraled Resourco Plan medan
wfr. 6nd[dla l-ongFbrm por€t Fftll.so3 rtd Anfo lrtny tugrrblo.y Pofcbr
^d(PtnP )ootre.cbluft loov''l lir€l.olrr.n lfinfl.d by 0r. tusl lype snd gqlofrlor ts.em. d on 2010 (bL. grorl'liln ,nrLd Frctra h.u. lcm altnud and .rabn d !r.
a,3t!Ce of lia Northwosl Pow6r Pool l,lel sydglr l,S. ftr Al(l7 tmugh 2009.
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'CuslomeG. ldaho Power-owned
Generalion Res&rces. Enerqv Sourc€s. Fuel lvtx" Eloctridlv Oeliveredlg
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CO: Emissions
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Site Map I Energy Efisgency I Tems - Condilions I Privacy Policy I FoBard-Looking Stalemenls I IDACORP
@ 1995'20.l3 ldaho Powsr Company
Servar: CRA
SRA
https://www.idalropower.com/AboutUs/EnergySourpeslFuelMix/typical_fuelMix.cfim
flGI *
EXHIBff,ml
Pegc 1 of1
nl4n0,3
Presidential Memorandum -- Power Sector Carbon Pollution Standards I The White House Page I of 2
Cet Errril L l.,lat(,s C,,nti,l t -
E-iEIk=-J.'u
Il'ttr,' , BriLli.;g F, -' . r'..ir l.nli,rl.-l-li , - ' Presrilcrttul iledrord,rdo
The White House
Office of the Press S€crelsry
For lmmediate Release June 25,2013
Presidential Memorandum -- Power Sector Carbon
Pollution Standards
ENVIRONMENTAL PROTECTION AGENCY
SUR,ECT: Power Sector Carbon Pollulion Standards
With every pssing day. lhe urgency ol addressing climate change intensilies. I made clear in my State of the Union
address lhat my Adminiskation is committed to r€ducing carbon pollulion lhal. causes climate change, preparing our
communities for lhe consequences of climate change, and speeding the lransition to more sustainable sources of
ene19y.
The Environmenlal Protection Agency (EPA) has already undertaken such action with regard to carbon pollution
from the lransportation sector, lssuing Clean Air Act standards limiting the greenhouse gas emissions of new cars
and light trucks through 2025 and h€avy duty trucks lhrough 20'18. The EPA standards were promulgated in
conjunctjon with the Depadmenl of Transportation, which, at the same time, established fuel eflidency standards for
cars and trucks as part of a harmonized national program. Both agencies engaged construclively with auto
manufaclurers, labor unions, States, and olher stakeholdeE, and the resulting standards have received broad
support. These slandards will reduce lhe Nalion's carbon pollution and dependence on oil, and also lead to greater
lnnovation, economic grov/lh, gnd cost savings for American families,
The United States nov/ has lhe opportunity to address carbon pollulion from the povr'er sector, which produces
nearly 40 percent of such pollution. As a country, we can continue our progress in reducing polver plant pollution,
lhereby improving public health and protecting the environment, while supplying the reli6ble, affordable pov/er
needed for economic growth and advancing cleaner energy technologies, such as efficienl natural gas, nuclear
power, renewables such as wind and solar energy, and clean coal technology.
lnvestmenls in these technologies rvill also strengthen our economy, as the clean and efficient production and use
of eleciricity will ensure that it remains reliable and affordable for American businesses and ,amilies.
By lhe authority vested in me as President by the Constitulion and the laws of the United States of America. and in
order to reduce power plant carbon pollution, building on actions already undemay in States and the power seclor. I
hereby direct the following:
Section 1.
eE0!9. On April 13, 20'12, the EPA published B Notice oF Proposed Rulemaking cntitled "Standards of Performance
for Greenhouse Gas Emissions for New Stationary Sources: Eleclric Utllity Generating Units," 77 Fed. Reg. 22392.
ln light of lhe informalion conveyed in more than two million commenls on lhat proposal and ongoing developments
ln the industry, you h€ve Indicated EPA'S intenlion lo issue a new proposal. I therefore direcl you to issue a new
proposal by no later than September 20, 2013. I lurther direct you to lssue a tinal rule ln a timely fashion after
considering all public commenls, as appropriate.
Io ensure continued
progress in reducing harmful carbon pollulion, I direct you to use your authority under sectlons 1 1'l(b) and 1 1'l (d) of
the Clean Air Act to issue slandards, rcgulations, or guidelines, as apprcpriate, that address carbon pollulion from
modified, reconstructed, and existing power plants and build on State efforts to move lov/ard a cleaner power
seclor. ln addilion, I request that you:
(i) issue proposed carbon pollution slandards, regulalions, or guidelines, as appropriate, for modilied,
reconstructed, and exisling power plants by no later lhao June 1, 2014;
(ii) lssue final slandards, regulations, or guldelines, as appropriate, for modified, reconstructed, and existing po\r€r
plants by no later than June 1, 201 5; and
(iii) include in the guidelines addressing existing power plants a requirement that States submil to EPA lhe
implemenlation plans required under seclion 'l 1 1(d) of the Clean AirAct and its implementing regulations by no
later than June 30. 20'16.
(a)
Search UJhileHcuse. go,,
ffirIE XOUSE SXriAOtt5
BLOG POSTS ON TIIIS ISSUE
flovonrher06 2013 3 15 Plrl EST
San Atttonio I\la-lrt Jrtlir'ur Cast ro: [-et's
Stop Dcnriug Tex:i ns l.lr.rlth In. rrrrn, i
liec;ruse of Politics
Under lhe Affordable Care Acl, states can choose
whether or not lo expand Medicaid to cover more
of its citizens. lf Texas chose to expand, il would
cover more lhan one million of citizens, and save
lhe state's taxpayers $1.7 billion over the next
decade in unpaid hospital bills.
iiovtsrnbGr 06 20 13 2 28 Pl:l EST
\irur ('lrrrl, to $'eigh irr on D.rlrt (irllrtti,lr
Inrt irc:
We're issuing an Advance Nolice of Proposed
Rulemaking (ANPR)-and what lhalmeans ls thal
we are considering issuing rules for lhe debt
collection industry, bul lirst we v/ant to hear from
you so we can learn more about lhe debl collection
system.
troY€.,be' 06 2013 12 50 Pnl EST
('lrief ol Staff Deni.; Irlcltonorrgh l)i:t rr:,sts
['rt'sident Obaura's Plnn to Cron thc
Econtnt-r and Bttild a Strorrg Iliddl, ( l.rs.
Chief of Stall Denis Mcoonough sddresses lh?
Chamber of Commerce Board of Directors Meeling
in Washlngton, D.C. and discusses the President's
plan to grow lhe economy and build s strong
middle class.
VIEW ALT R€LATEO ELOG POSIS
(b)
Facebook
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Llnkedln
SRA EXHIBIT 403
Page 1 of2
http://www.whitehouse.gov/the-press-office/20l3l06l25lpresidential-memorandum-power-... lll6l20l3
$
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q03
Presidential Memorandum -- Power Sector Carbon Pollution Standards I The White House Page2 of 2
ln developing sladards, regulatims, or
guidellnes pursuant to subsection (b) of this sectlon, and comBtent wilh Executive Orders 12866 of September 30,
1993, ss amended, and 13563 of January ,l8, 201 1, you shall ensure, to lhe greatest 6xt6nt posslbls, lhat you:
(i) launch lhis effort thrcugh direct engagement with Slates, as lhey witr play a central role h establishing and
lmplementing standards for existing power plants. and, at lhe 3ame lima, wilh lsdars ln lhe pfl€r sectff, lsbot
lEdeE, non-govsrnm€ntal organizations, other €xperls, tribsl officlals, otherstakshold€rs, and memb€6 of lh6
public, on lssu€s informlng lhe design of the program;
(li) consBtenl with schieving regulatory obiectivs and tahing into 6c@unt olher .elevsnl envircnmenlal regulations
and policies lhal aflect the porrer sector, tailor tegulatims and guldelin€s to teduce costs:
(lii) develop approaches that all& the use ot ma*el+ased instruments, performancg standards, and other
regulatory fl exibilities;
(lv) ensure thal lhe standards enable conllnu€d rellanco on a range ot energy sources and tshnologies;
(v) ensure lhat lhe standards ars dewloped ard implement€d in a manner conslslent wilh the continued provision
ofreliable and atfordablo eleclric power tor coNumers and businesses; and
(vl) work with the Department of Energy and other Federal and SIate agencies to promole lhe reliablo and
affordable provlsion of electric p@er lhough lhe continued development and deployment of cleaner lechnologies
and by increasing energy efficiency, including lhrougLh strcnger appliarce efliciency standards and other measures.
Sgg.2. General Prcvisions. (a) This memorandum shall be lmplemented consistenl with applicable law, including
internalional trade obligauons, and subject to the availabllity of appropliations.
(b) Nolhing in this memorandum shall be @nstrued to impairor otheruise affect:
(i) the authtrity granted by law to a departm€nl, agency, or lh€ head thereot; or
(li) lhs funclloos ot tho Dlrector of the Ofllce of Management 6nd Budget relating to budgetary, administrative, or
legislalive proposals.
(c) This memorandum ls not intended lo, and does not, cteate any right or benelit, subslantive or procedural,
enfsceable at law or in equity by gny pBrty against the United Slates, its deparlments, agencies, or entilies, ils
olficeE, employees, or agents, or any other p€rson.
(d) You a(e hereby aulhorized and directed to publish this m€morandum in the FoderarFsgrbler
EAMCKOBAMA
Learn more:
. View the Full PDF of the Presidsnt's Climat3 Action Plan
. \/atch President Obama's Climate Change Speech
\' \ rtl'l lrll)l ,l ,.tl\
En €staiot I Arcessibitrly I Cot,yrgl[ liilornlan.n I PNr .] Folr ) lConlacl
USA.gav lD(,v€l.p$t lApply lor a $f
SRA EXHIBIT 403
Page2 of2
http://www,whitehouse.gov/the-press-office/2013l06l25lpresidential-memorandum-power-... 11,/612013
(c)
@ cmARrNG uP
Ill Mainzen Policyto Stay in Northwesti
Reconstruction Looks Manageable
Acting Administrator Elliot Mainzer this week said he is
"comforted" by assurances from DOE headquarters that the
department will confine its involvement at BPA to issues concerning
human capital management. He is "guardedly optimistic" that
Bonneville will be able correct its flawed hiring actions through
natural attrition and by filling existing vacancies. In his first public
interview since the hiring scandal broke last July, Mainzer took
ownership of BPA's sins, but declined to comment on the merits of the
removal of Drummond and Decker, or the prospects for their retum.
BPAfinils ils voice, at [21].
l2l OK of REP Settlement Solidifies 52 Billion in
Preference Savings
One of the biggest controversies in the Northwest power industry
came to an end Oct. 28 when the 9th U,S, Circuit Court of Appeals
upheld the Residential Exchange Program Settlement agreement. The
ruling ensures an era of rate and REP benefit certainty for the next
15 years. Although industrial customers failed to rend the settlement,
they did win an important ruling on standing. At fi41, we can say it at
last-RIP, REP dispute.
t3l Pacffic States and B.C. Create Plan to
Combat Climate Change
Califomia, Oregon, Washington and British Columbia signed an
agreement this week that could lead to a more harmonized regional
effort to combat climate change. The Pacific Coast Action Plan on
Climate and Energy commits the jurisdictions to a number of steps
aimed at reducing greerihouse-gas emissions, including the creation
of carbon-pricing programs, the low-carbon fuel standard and other
initiatives California has pioneered. At [22], "the world's greotest
exis tentiql ch allen g e, "
I4l OPUCWants Deeper,TransparentCoal
I nvestments Analysis From Pacifi Corp
Oregon PUC commissioners advised PacifiCorp at an Oct. 28
meeting to perform a more thorough and transparent analysis of the
environmental investments needed in its coal fleet or face the pos-
sibility that the commission will reject requests to include the costs
in rates. OPUC staff said the number of coal plants analyzed in the
company's 2013 IRP was "insufficient," and "with few exceptions,
PacifiCorp either conducted no analysis or inadequate analysis of the
coal retrofits in question. " At fiSJ, ghosts oJ the 2012 mte case ha nt
the proceeding.
for the Paclfic
Northwest and
Yestern Cmada'
Former ldaho PUC Member ConleyWard
Dies at 66 ....lumptotl2l.
Former Montana PSC Chalr Bob Anderson
DiesinAccident. ....Jumptofi2.ll,
Brief Mentions: News Roundup.. lwWto [, 221.
Montana PSC Orders NorthWestern to Redo
Lost RevenueTrue-Ups. .......lumpto fi61.
IPUC OIG Settlement Avoiding PacifiCorp
GeneralRateCase. ....tumptofifl,
ldaho PUC Reaffirms Denialof Solar
Project's PURPA Contract..... .Jump to U Sl.
Oregon, Washington Gas Custorners
See Mostly Low PGA Rates . ...lumptoll9l,
Groups Sue EPA OverWashingtonl
Fish-Consumption Standard. . .Jump to 'I20],.
NorthWesternt Q3 Earnings Jump; Outages
Hurt PGES Bottom Line... .....lumpto[23],
POTOMAC: Rescheduled Columbia River
Treaty Hearing Setfor Nov.7 ..Jump tot241.
Poneman Memo Adds lntrigue to Evolving
DOE-BPA Dynamic . . ..lumpto n?l.
RegionalGeneration Dips and the Mix
Changes Detallson Page 5,
Natural Gas Use Should Fall in Winter
Detailson Page 6,
Go to www.EnergylobsPortal.com for the latest in
regional energy career opportunities.
SRA EXHIBIT 404
Page I of3
Energy NewsData,Seattle & San Francisco: November 1,2013 . No 1619
CLEARING (IP . November l, 2013 . No. 1619 . Page 10
[15] OPUC to PacifiCorp-Work Needed on
2013 IRP to Avoid'Train Wreck'. from [4]
PacifiCorp has held a dozen or so public meetings
and technical workshops on its proposed 2013 integrated
resource plan, but on Oct. 28 during an Oregon PUC
meeting, the company received the most pointed com-
ments yet on the plan.
Oregon PUC commissioners, following the advice of
the PUC staff, advised the company to perform a more
thorough and transparent analysis of the environmental
investments needed in its coal fleet, or face the prospects
of the commission rejecting future requests to include
those costs in rates.
"Acknowledgment of an IRP is not rate approval, but
it's really, really close," Commissioner John Savage said
at the end of the meeting. "The reason we do a very rig-
orous IRP in Oregon is we'd rather do this in an IRP than
duke it out in a rate case, but right now we are heading
for a train wreck."
savage's comments came in response to staff's report
that PacifiCorp has not sufficiently modeled billions of
dollars' worth of investments in pollution controls needed
on 14 of its coal units-Cholla 4, Hayden
1 and 2, Craig I and 2, Dave Johnson
Unit 3, Jim Bridger units 1 and 2, Naugh-
ton units I and 2, Hunter units 1 and 2,
and Huntington I and 2-as called for in
the preferred portfolio in the IRP.
"The number of coal plants analyzed is
insufficient," according to a staff report.
"With few exceptions, PacifiCorp either
conducted no analysis or inadequate analy-
sis of the coal retrofits in question. "
'Acknowledgment of an
IRP is not rate approval,
but it's really, really
dose.'
control (CU No. 1570 [18]). The company's preferred
portfolio was developed using base-case pollution control
requirements that included parts of the disapproved state
plan, according to a staff report. Staff said changes have
also been made to Wyoming's plan that aren't reflected
in the IRP (CU No. 1599 [11]). "Therefore, even at the
time the IRP was filed, the company's preferred portfolio
did not represent the most current conditions, " staff said.
Staffsaid an "alternative compliance option analysis
is needed for all plants facing major upgrades in 2019,
which should include the proqpects of early retirements
and tradeoffs between coal plants. Where there was
uncertainty about the extent of and riming of pollution
control investments and where there was a pending law-
suit, the company did not perform an analysis ofpotential
compliance alternatives, "
"We don't think an IRP update is sufficient to look
at coal plant investments like this," Johnson told the
commlsslon.
The company's modeling software, known as
System Optimizer, was also criticized by staff as being
"too complex and not the right tool for the job when
multiple variables need to be meaked and trigger points
established. " Staff said it had no way to verify
the results of System Optimizer, noting that
in the 201 1 IRP update, a simple "screening
tool" spreadsheet model was provided that
allowed parties to perform plant analysis.
When commission staff asked that two
scenarios be analyzed, the company said it
would take weeks to get the results. "We
need to be able to understand and verify what
Because all coal plants requiring major investments
by 2019 need to be considered right now, "time is of the
essence," Juliet Johnson, PUC staff member, told the
commission during the meeting.
"Anything that requires action by 2019 can't wait until
the 2015 IRP" because it won't allow enough time for
negotiations ofpotential early shutdowns or tradeoffs in
emissions investment at plants, Johnson said.
The company's 2013 IRP, which was filed in April,
shorved a decrease in load growth and continued low
natural gas prices. Energy efficiency and market pur-
chases play key roles in meeting demand during the first
decade modeled, with 953 MW of efficiency covering
about 67 percent ofthe forecasted load growth. The IRP
also calls for market purchases of between 650 MW and
1,333 MW.
The plan also calls for investing heavily in pollution
cohtrols at several coal-fired facilities to meet regional
haze and other air requirements.
But staff called the proposed IRP "functionally
incomplete" because no analysis was performed for
near-term retrofits needed at Craig 1 and 2, Hayden I and
2, and Cholla 4-plants where PacifiCorp holds minority
ownership. Staffencouraged the company to provide that
analysis "beeause Oregon ratepayers will be paying for
these upgrades."
Four months prior to PacifiCorp filing the IRP
in April 2013, EPA rejected parts of Utah's state
implementation plan related to regional haze pollution
is happening right now," Johnson said to the
commission, describing System Optimizer as a "big black
box" that "may not be the right tool. "
PacifiCorp also did not factor into its coal analysis the
impact of coal plant alternatives on sizing of transmission
lines. A replacement gas plant could be located closer to
load and thereby change the need for new transmission,
staff said.
In addition to having numerous issues with Pacifi-
Corp's coal analysis, staff said the company "ignored or
delayed action plan items related to DSM in other states"
when load projections came in lower than expected.
Don Jones, DSM planning manager at PacifiCorp,
later explained to the commission that the company was
planning a "direct install" that was put on hold until the
new load forecasts were figured out, but contract negotia-
tions with a commercial provider are ongoing and an RFP
will be going out.
Mary Wiencke, legal counsel at PacifiCorp, told
commissioners that this was the first time they had heard
staff's concerns, despite a number ofworkshops and
technical conferences. "We would have Iiked to have
gotten that feedback earlier, instead ofnow at this late
date," she said, noting that PacifiCorp will respond to
staff's remarks in written testimony expected to be filed
in the next few weeks.
Hanging over the meeting and the 2013 IRP is the
ghost of the PacifiCorp's 2012 rate case, where the
OPUC trimmed the revenue request by $tZ million
because the company failed to analyze its options on coal
invesrments, The commission linked their ruling directly
Copyright o 20i3, Energy NewsData Corporation
SRA EXHIBIT 404
Page 2 of3
CLEARING (IP . November . No.1619 . Pagell
to "the lack of a full evaluation of these invesunents in
Pacific Power's IRP process," the order said.oThere is nothing staff said that I disagree with,"
Chair Susan Ackennan said in closing comments.
"I don't want to be in a position where we have another
rate casc and there isn't cnough evidence to support your
investments and we have to concoct an appropriate result
for consumers." i
The commission is scheduled to acknowledge the IRP
this March fSteve ErnstJ.
[16] Montana PSC Orders NorthWestern to
Redo Lost Revenue True-Ups. from [5]
The Montana PSC has directed NorthWestero Energy
to recalculate lost revenue true-ups associated with the
utility's energy efficiency programs.
In an Oct. 22 order on the utility's 20lt-2012
Elecricity Supply Tracker [D2012.5.49], the commission
said the utility's calculation of revenues forgone due
to demand reductions associated with its energy effi-
ciency programs overstated the saviugs, leading to an
overcollection from customers,
The order makes four adjusunents to the utility's
calculation of lost revenues "to snsure that NorthWestern
only recovers lost revenues lhat were actually incurred as
a result of its programs, and that the rates tfuough which
it collects lost revenues are just and reasonable. "
These tweal<s include directing NorthWestern to
recalculate lost revenue calculations to more accurately
incorporate the effects of free ridership and spillover on
realized energy savings; to adjust the estimated sav-
ings from its CFL programs to reflect a more accurate
bum-or usage-rate; to remove savings affiibuted to
CFLS in storage; and to remove savings associated with
the Montana Department of Environmental Qualrty's
appliance program.
The commissioners disagreed with some of the find-
lngs in a comprehensive program savings verification
study prepared for Northwestern by SBW Consulting.
Conducted every five years or so, the studies are intended
to evaluate the cost effectiveness of NorthWestern's
individual energy efficiency progftrrns and true up lost
revenue calculations from past annual true-ups, said Will
Rosquist of the Montana PSC.
In between such reports, the commission provides
interim approval of lost revenue true+rps-in this case,
from July 2006 through lune 2011. When the study is
completed, the annual tracker adjustrnent also trues up the
previously interim-approved lost revenues, he said.
The commissioners disagreed with SBW's assumption
that spillover-additional savings induced but not subsi-
dized by an efficiency program-would completely offset
free ridership; concluded that the linear regression model
SBW used to calculate CFL bum rate was flawed; and
disagreed with SBW's inclusion of savings from CFLs
not yet installed in the lost revenue figure.
sBW found that 8.6 percent of the cFLs distributed
under the utility's E* Residential Lighting Program had
not been installed. "Clearly, lamps that are installed in
drawers and closets rather than fxtures are notproducing
energy savings. The commission is not persuaded by the
claim that stored lamps should be considered installed
because they are likely to be insalled in the near future,
the order reads in part.
The cornmission also dtsagreed with NorthWestern's
inclusion of savings from a state-run appliance program
in the utility's lost revenue calculations, when the utility's
only participation was program promotion. The utility's
involvement "was not primarily responsible for produc-
ing those glyings," so the PSC directed NorthWestem to
adjust DBQ appliance program savings "by a factor equal
to the ratio of NorthWestern's program costs to the total
resource costs of the DEQ Appliance Program. "
The PSC gave NorthWestern 30 days from the service
date of the order to make a compliauce filing that adjusts
its reported energy efficiency savings as directed and
recalculates the true-up of lost revenues actually incurred
from July 2006 through December 2011.
The commlsslon also indicated skepticism "of the
status quo regarding lost revenue reccivery," saying it is
"troubled by the maglitude and complexity of the SBW
report, and by the administrative cost associated with
overseeing the process ofdetermining realized savings."
As of the order's service date, NorthWestern bears the
burden of demonstrating why any request for incremental
lost revenues resulting from energy efficieacy program
savings "is reasonable and ia the public interest," the
PSC said.
The commissioners also noted that the current
policy that allows utiliry recovery ofrevenues lost due
to effrciencies achieved by ttre state-mandated Universal
System Benefit programs-implemented in conjunction
wi& Mootana's deregulation experiment-is "particularly
questiotrable," since these programs are reguired by law.
The actual effect of the lost revenue adjustments isn't
clear at this point, but it could result in a rebate of several
million dollars, Northwestern spokeswoman Claudia
Rapkoch confirmed. She added that ttre utility is currently
working through calculations for the report to be filed at
ttp PSC in late November.
In addition, NorthWestern will not be allowed to
recover the $1.4 million it requested for the incremental
costs of regulation services it purchased during an outage
at its Dave Gates Generating Station, a 150-MW natural
gas CT plant the utility uses to provide transmission
regulation service in its balancing authority. The plaut
went on line on Jan. I , 201 1, but was off line for
three months in20l2, due to damage and problems in the
project's three 50-MW units. NorthWestern purchased
regulating capacity from Powerex and Avista until DGGS
was back in service.
The $1.4-million exceeded the sum of DGGS fixed
costs and variable DGGS costs the utility would have
incurred if there had been no outage. NorthWestern
requested full recovery from ratepayers, arguing that
it prudently managed the risk of aa outage, includ-
ing by purchasing a one-year extension to its warranty,
the order indicates. That waranty, however, didn't
cover "consequential damages"-including the cost of
replacement regulation services,
The Monuna Consumer Counsel recommended
the commission disallow recovery of the incremental
replacement costs because the utility's fuilure to evaluate
"the availabiliry, price and temrs of outage insurance"
before DGGS went on line was imprudent. Replacement
Copyright 6 2013, Energy NewsData Corporation
SRA EXHIBIT 404
Page 3 of3
O,
REOUES"il ,,N9**,.,1.1.: Please reference Dlrect Testirnony of Mlchael J.
Youngblood, p.16, lines 3-15. Please provide all analyses, assumptions, workpapers
and worksheets (ln electronlc form with formulas lntact) that resutt in the calculatlon of
the revenue requirement of approximately $9.1 rnllllon and $9.7 mlllion for Jim Bridger
Unlts 3 and 4, respectively.
BESPONSH ,fq,,,BEPlr#ST,.l.lO, 11: Please see the attached Excel file
contalning the requested analyses and workpapers,
The response to this Request was prepared by Michael J. Youngblood, Manager
of Regulatory ProJects, ldaho Power Company, ln consultation wlth Llsa D. Nordstrom,
Lead Counsel, ldaho Power Company.
IDAHO PO\A'ER COMPAT.TYS RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY. 2
ldaho Power Company
of Revenue ldaho
RATE BASE ldaho
Electric Plant in service
lntangible Plant
Productlon Plant
Transmlsslon Plant
Distribution Plant
General Plant
Total Electric Plant ln Service
Less: Accumulated Depreciation
Less: Amortization of Other Plant
Net Electric Plant in Service
Less: Customer Adv for Constructlon
Less: Accumulated Deferred lncome Taxes
Add: Plant Held for Future Use
Add: Working Capital
Add: Conservation - Other Deferred Prog
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE
NET INCOME
ldaho Power Company
of Revenue Reouirement - ldaho
RATE BASE Idaho
lntangible Plant
Production Plant
Transmlssion Plant
Dlstrlbution Plant
General Plant
Total Electrlc Plant in Service
Less: Accumulated Depreciation
Less: Amortization of Other Plant
Net Electrlc Plant in Servlce
Less: Customer Adv for Constructlon
Less: Accumulated Deferred lncome Taxes
Addr Plant Held for Future Use
Add: Worklng Capital
Add: Conservation - other Deferred Prog
Add: Subsidiary Rate Base
TOTAL COMBINED RATE EASE
NET TNCOME
s
5 60,L96,124
$ 7s2,4s9
5 59,444,26s
s
s
ffia'El65-
s
64,01.4,14t.02
5 o+,or4r+rs 800,177
$ 83,213,964
s
s
_63113",54
Operatlng Revenues
Sales Revenues
Other Operating Revenues
Total Operatlng Revennues
Operating Expenses
Operation and Maintenance Expenses
Depreclation Expenses
Amortization of Limited Term Plant
Taxes Other Than lncome
Regulatory Debits/Credits
Provision for Deferred lncome Taxes
lnvestment Tax Credit Adjustment
Current lncome Taxes
Total Operating Expenses
Operatlng lncome
Add: IERCO Operating lncome
Consolldated Operating lncome
Rate of Return as filed
Proposed Rate of Return
Earnings Deficiency
Net-to-Gross Tax Muhiplier
Revenue Deficlency
1,s04918
$
$ (s88,348)S gre,szo
$ (916,s70)
T---lri6sro)
-2%
7.86%
S s,s88,890
L.642
l-;IiE',rs-71
Operating Revenues
Sales Revenues
Other Operating Revenues
Total Operating Revennues
Operating Expenses
Operation and Maintenance Expenses
Depreciation Expenses
Amortization of Limited Term Plant
Taxes OtherThan lncome
Regulatory Deblts/Credits
Provision for Deferred lncome Taxes
lnvestment Tax Credit Adjustment
Current lncome Taxes
Total Operating Expenses
Operating lncome
Add: IERCO Operating lncome
Consolidated Operating lncome
Rate of Return as filed
Proposed Rate of Return
Earnings Deficiency
Net-to-Gross Tax Multiplier
Revenue Deficlency
1,600,3s4
s
s (62s,6s8)$ sz4esss (s746es)
rei
-2%
7.86%
s 1e43,313
L.642FTEE,rrol
SRA EXHIBIT 405
Page2 of2
o'
BEgtlEgtN9*l$: Please describe how the proiect wlll be financed. Please
include within your response a summary of the payment schedule that will be followed.
Please also provlde wlthln your response coples of any financing agreements.
RESP-ONSE TO REQI,IEST NO. 18: ldaho Power expects to finance this project
conslstent with the flnanclng of its total constructlon prcgram. The Company expects to
finance lts capital requirements with a combinatlon of internally generated funds and
externally flnanced capltal. ldaho Power has not entered into any altematlve financing
agreements and thercfore has not developed a financlng payment schedule based on
non-tnaditional fi nanclng schemes.
The response to thls Request was prepared by Randall Henderson, Flnance
Team Leader ll, ldaho Power Company, in consultatlon with Lisa D. Nordstrom, Lead
Counsel, ldaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REOUEST OF THE COMMISS]ON STAFF TO IDAHO POWER COMPANY. 9
SRA EXHIBIT 406
Page 1 of 1
REQUEST NO. 19: Please provlde copies of the mlnutes of all ldaho Power
Board of Direotors' meetings (and committee and/or subcommittee meetings) at which
the ProJect was dlscussed. Please provlde, w,lthln )our ft)sponse all analyses,
prcsentations and any other matefials that rnay have been provided to the Board of
Direc{ors and com mittee and/or subco mmittees.
RESPONSE TO REQUEST [9. le:
EggglttlltEu$. The ldaho Power Board of Dlrectors' ('Board') Minutes reflect
that investment in the SCR controls at Jlm Bridger Units 3 and 4 ('ProJect') was
discussed at the followlng Board meetings: March 16,2011 (educaflonal meeting);
January 19, 2012 (full Board meeting); March 20,2013 (educational meeting); and May
15, 2013 (educational meeting). Excerpts from the Minutes of the r6feleneed Board
meetings which pertain to the Projec'tt are prcvided on the onfidentlal GD (Attachment
1). i)pples of the full Board Minutes are avallable for review by the Gommission Staff att_
ldaho Powefs corporate headquarters upon request.
Chief Executive Officer CCEO") Letters. Beginnlng in May 2012, the ProJect was
also referenced in sevenal of the ldaho Power CEO letters that arc provided to the
Board each month. Excerpts f.romlLe monthlv CEO letters that address the Projec't are
provided on the confldentiaFC0 (Attachment 2). Dopies of the full CEO letterc whlch
referene the ProJec{ are avaihble for review by the Commission Stafi at ldaho Powe/s
corporate headquarters upon request.
Annual Budqets. The Board also approved ldaho Powe/s cunent and projected
expenditures for the Project through lts approval of ldaho Powefs annual budgets for
I The Mlnutes of Ure May 15, 2013, Bed meetng are ln draftform untl approrcd by the Board
'lts next meetirXg, whbh is scheduled for September 19, 2013. The Minutes aie subJect b ciange ut
approved by the Board.
IDAI-IO POWER COMPA}.ITS RESPONSE TO THE SECOND PRODUGTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POAIER COMPANY- 10
SRAEXHIBIT 407
Page I of5
O,
2010-2013, Further informatlon regarding sald budget approvals is included ln the
attachments provlded ln the Company's rcsponse to Staffs Production Request No. 20.
The confidential CD will be proMded to those parties that have executed the
Protective Agreement in this matter.
The response to this Request was prepared by Patrick A. Haningiton, Corporate
Secretary, ldaho Power Company, in consultatlon with Llsa D. Nordstrom, Lead
Counse!, ldaho Power Company.
IDA}IO POWER COMPANYS RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPAI.IY - 11
SRA BXHIBIT 407
Page 2 ofS
O'
REQIEST ,NO. ?g: Has the ldaho Power Board of Directors authorized
expenditure of funds for construction of the Project? lf so, what amount has been
authorized? Please lnclude within )our response the detalls of the amount authorized
and, if it differs ftom the amount included within the Company's Application, why lt
differs.
RESPQNQF fQilHQPE$I lL9..zo: ldaho Powe/s Board has authorized the
expenditure of funds for construction of the Project through the Board's approval of
ldaho Powe/s annualcapital budgets for 2010-2013, as set forth below.
2010 Capltal Budoet Aooroval. The Board approved the ldaho Power 2010
capital budget through the following resolution adopted on November 19, 2009:
RESOLVED, That the 2010 capital budget in substantially
the form presented to this meeting be, and lt hereby is,
approved, and the proper officers of the Gompany are
hereby authorized to take any and all action they deem
necessary to effect the 2010 capital budget.
The Board's apprcval of the 2010 capital budget was based on the '2010 O&M
and Capital Budgets Summary'' presented at the Board's November 19, 2009, meeting.
A copy of the portlons of the "2010 O&M and Capital Budgets Summary" which pertaln
to the Project is provided on the confidentlal CD (Attachment 1). A copy of the full
.20'10 O&M and Capital Budgets Summary" is available for review by the Commission
Staff at ldaho Powe/s corporate headquarters upon request.
2011 Capital Budqet Aporoval, The Board approved the ldaho Power 2011
capital budget through the following resolution adopted on January 20,201'l:
RESOLVED, That the 2011 capltal budget in substantially
the form presented to this meetlng be, and it hereby ls,
approved, and the proper officers of the Company are
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REOUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY - 12
SRA EXHIBIT 407
Page 3 of5
o
hereby authorized to take any and all action they deem
necessaryto effect the 201l capital budget,
The Board's approval of the 2011 capital budget was based on the "2011 O&M
and Gapital Budgets Surnmar/ presented at the Board's January 20,2011, meetirg. A
copy of the portions of the '2011 O&M and Capital Budgets Summary'' which pertain to
the Project is provided on the confidential CD (Attachment 2). A copy of the full "2011
O&M and Capikl Budgets Summary'' ls available for review by the Gommission Staff at
ldaho Powe/s corporate headquarters upon reguest.
2012 Caoital Budoet ApQroval. The Board approved the ldaho Power 2012
capital budget through the following resolution adopted on January 19,2012:
RESOLVED, That the 2012 capital budget in substantially
the form presented to this meeting be, and it hereby is,
approved, and lhe officers of the Company are hereby
authorized to take any and all actions as they deem
nec€ssary or desirable to effect the 2012 capital budget.
The Board's approval of the 2012 capital budget was based on the "2012 O&M
and Capital Budgets Summar/ presented at the Board's January 19,2012, meeting. A
copy of the portions of the "2012 O&M and Capital Budgets Summa4/ which pertain to
the Project is provided on the confidential CD (Attachment 3). A opy of the tull "2012
O&M and Capital Budgets Summary" is available for review by the Commission Staff at
ldaho Power's corporate headquarters upon request.
2013 Capital Budqet Aoproval. The Board approved the ldaho Power 2013
capital budget through the following resolution adopted on January 17,2A13:
RESOLVED, That the 2013 capital budget in substantially
the form presented to this meeting be, and it hereby is,
approved, and the officers of the Gompany are hereby
authorized to take any and all actlons as they deem
necessary or desirable to effect the 2013 capital budget.
IDAHO POWERCOMPAT.IYS RESPONSE TO THE SECOND PRODUCTION
REOUEST OF THE COMMISSION STAFFTO IDAHO POWER COMPANY- 13
SRA EXHIBIT 407
Page 4 of5
e'
The Board's approval of the 2013 capital budget was based on the '2013 O&M
and Capital Budgets Summarf presented at the Board's January 17,2013, meeiing. A
copy of the portions of the .2013 O&M and Capitat Budoets Summary'' which pertain to
the Project is provided on the Qonfidentia! GD (Attachment +';. n copy of the full '2019.,|
O&M and Capital Budgets Summary'' ls avaiiable tor revrejr,i Dy rne Gommission Staff at
ldaho Power's corporate headquarters upon request.
Page 49 of the '2013 O&M and Capital Budgets Summary" provided on the
confidential CD llsts total proJected expenditures for "Bridger-selective Catalytic
Red uctio n-All U nits' a s $2 1 8, 034,000 for the 2013-2022 bud get period.
Aeplicatiqn Gpmmitm?pt Estimate
ldaho Powe/s Applicatlon states on page 7:
v. QqMMTMENT EqJTMATE
14. As Mr. Youngblood describes in hls direct testimony,
the total cost of the Prcject before Allowance for Funds Used
During Construction (.AFUDC") is $353,8#i,886. ldaho
Powet's share of that amount, the "ProJec{ Cost," ls one-
third, or $117,947,962, comprised of a $57,649,113
investment in Jim Bridger Unit 3 and a $60,298,849
lnvestment in Jim Bridger Unit 4, before AFUDC.
Confidentlal Exhiblt No. 7 to Mr. Youngblood's direct
testimony shows the budget projections by year for Jim
Bridger Units 3 and 4. (Emphasis added.)
ldaho Powe/s Gommitment Estlmate ol $117,947,962 for the Project is less than
the $218,034,000 authorized budget expenditure level for "Bridger-Selective Gatalytic
Reduction-All Units" as shown In confidential Attachment 4. However, the
$117,947,962 Commitment Estimate set forth in ldaho Power's Application applies only
to the SCR lmprovements at Jim Bridger Units 3 and 4, whlle the $218,034,000 budget
figure applies to SCR lmprovements for all four Jim Bridger units over the 10-year
IDAHO POWER COMPANYS RESPONSE TO THE SECOND PRODUCTION
REOUEST OFTHE COMMISSION STAFFTO IDAHO POWERCOMPANY- 14
SRA EXHIBIT 407
Page 5 ofS
SSlnAcoRP
November 5,2013
IDACORP, lnc. Announces Thlrd Quarter 2013 Results,
lncreases Lower End of 2013 Earnlngs Guldance Range
BOISE--IDACORP, lnc. (NYSE: IDA) reported third quarter 2013 net lncome attributable to IDACORP of $71.8
million, or $1.43 per diluted share, compared to $92.1 million, or $1.84 per diluted share, in the third quarter of
2012. For the first nine months of 2013,|DACORP recorded net income attributable to IDACORP of $150.8 million,
or $3.01 per diluted share, compared to $152.3 mllllon, or $3.05 per diluted share for the first nine months of 2012.
ldaho Power Company, IDACORP's principal subsidiary, reported third quarter 2013 net income of $70.3 million
compared to $89.6 million in the third quarter of 2012, and net income of $149.3 million for the first nine months of
2013, eompared to net income of $150.1 million for the same period t,n2012.
"IDAGORP's third quarter operating results continue to demonslrate the strength of our underlying operations and
we remain on track for a sixth consecutive year of improved earnings," said IDACORP President and Chief
Executive Officer LaMont Keen. "Our 2013 year-to-date results reflect effective cosl management, coupled with the
positive revenue impact of weather conditions, customer growth, and increases ln base rates that went lnto effect in
mid-2012. lncome taxes impacted the comparability of results for the quarter; however, they had little bearing on
our full-year eamings expectatio ns.
*Based on these results and our outlook for the remainder of 201 3, we are tightening our estimate of IDACORP's
full year 2013 earnings by increasing the lower end of the range. Our full year 201 3 guidance range, which was
prevlously $3.40-$3.55 per share, is now $3.45-$3.55 per share. For the third year in a row we anticipate sharing
part of these annual eamings with our ldaho customers under our December 2011 regulatory settlement
agreement.
"ln another positive development, this September IDACORP's board of directors approved a 13.2 percent increase
in the regular quarterly cash dividend on IDACORP's common stock, from $0.38 to $0.43 per share, or to $1.72 per
share on an annualized basis. Reflecting the company's commitment to growing the dividend, IDACORP's
management also anticipates recommending to the Board additional annual increases to the dividend of greater
than five percent, until it reaches the upper end of the target annualized dividend payout ratio of between 50 and 60
percent of sustainable IDACORP earnlngs," added Keen.
SRA EXHIBIT 4{X'
Page I ofl
KRISTINEA. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PI.'BLIC UTILMES COMMISSION
PO BOX 83720
BOrSq rDAHO 83720-s074
(208) 33+03s7
TDAHO BARNO.6618
Street Address for Express Mail:
472W WASHTNGTON
BOISE ID 83702-5918
Attorney for the Commission Staff
IN THE MATTER OF IDAIIO POWER
COMPANY'S APPLICATION T'OR A
CERTII'ICATE OF' PUBLIC CONVEMENCE
AND NECESSITY FOR TIIE INVESTMENT
IN SELECTIVE CATALYTIC REDUCTION
CONTROLS ON JIM BRIDGERI'NITS 3
AND 4.
cAsE NO.IPC-E-13.16
COMMISSIONSTAtr'F'S
RESPONSE TO TIIE FIRST
PRODUCTTON nEQITEST Or
SNAIG RIVERALLIANCE
RECEIIJi T
?013 tl0V - | Pil 3: I S
lll '1i0,U'l'lLlT!:.1C.', I .lt. lLr,,
NOVEMBER 1,2013
SRA, EXHIBIT 410
Page I of3
BEF'ORE TIIE IDAHO PUBLIC UTILITTES COMII/ilSSION
)
)
)
)
)
)
)
The Staffof the Idaho Public Utilities Commission, by and through its attorney of record,
Kristine A. Sasser, Deputy Attomey General, rcsponds as follows to Snake RiverAlliance's First
Production Request to Commission Staff.
REQIIEST NO. L Please referto testimony of Witness Louis, Pg. 9, L. 5.
Please state with specificity each of thc potential environmental and future environmental
compliance costs evaluated by Staffand Staffs estimate of the present dollar cost of each
compliance measure.
STAI'F RESPONSE NO. r: Sce ldaho Pow€r's Application ExhibitNo. 5, pp. 18-21
for compliance costs crraluated by Staff. Statrdid not develop its own estimates.
STAItr'S RESPONSE TO THE FIRST
PRODUCTION REQUESTOF SI{AKE RIVERALLIANCE I
REQITEST NO 2: Please refer to testimony of Witness Louis, Pg. 16, L 6.
Please state with specificity each regulation about which there is considerable uncertainty.
STAI'F'RESPONSE NO. 2: Futurc existing-source greenhouse gas regulations have
considerable uncertainty because proposed rules are not expected until June l,}Ol4and final
rules are notexpected until June 1,2015.
REQUEST NO 3: Please refer to testimony of Witness Louis, Pg. 10,L.22,
Please identify all efforts of which you are aware whereby either PacifiCorp or ldaho Power
attempted to negotiate a delay in Regional Haze compliance.
STAFF RESPONSE NO. 3: I am not aware of any negotiations by ldaho Power. I am
aware of negotiations between PacifiCorp and the Wyoming Depatrment of Environmental
Quality through discussion contained in Sunebuttal Testimony of Cathy S. Woollums and
Supplemental Exhibits (Utatr DockctNo. t2-03592; RMP*(CSW-5SR); RMP_(CSW4SR)).
REOUEST NO 4: Please refer to testimony of Witness Louis, Pg. I l, L. 16.
Please identifl the specific provisions of contracnral obtigations between the companies that
make it very difficult for ldaho Power to pursue a different approach.
STAF'F RESPONSE NO.4: Please see ldaho Power's response to StaffProduction
Request No. 9.
STAFF'S RESPONSB TO TT{E FTRST
PRODUCTION REQUEST OF SNAKE RTVER
ALLIAI{CE NOVEMBER I,2OI3o
SRA EXHIBIT 410
Page 2 of3
Plcase:
Please:
REQUEST NO 5: Please refer to testimony of Witness Louis, Pg. 12,L. 4.
a. Provide adefinition of"stranded assets" as used therein.
b. Provide Staffs assessment of the degree of ccrtainty that IPCo would face
financial loss associated with "sEanded assets" a:i you have defined it.
STAFT'RESPONSE NO. 5:
a. Stranded assets are those investments which have already been madc but which, at
some time prior to the end of their economic life (as assumed at the investment
decision point), are no longer able to earn an economic return, as a result of changes
in the market and regulatory environment. (Staffs definition is derived from the
Intemational Enerry Agency's definition of stranded assets.)
b. Staffhas not assessed the degree of certainty that losses would be incurred.
REQUEST NO 6: Please refer to testimony of Witness Louis to Pg. 18 L. l.
a. Provide I copy of the "tipping point" analysis provided by the Company,
b,. Assume that instead of attempting to assign a dollar cost to CO2 emissions,
future federal regulations impose limitations on the level of GHG emissions
from existing coal-fired plants, Please state whether Staff has analyzed the
cost of such form of regulation, either generically or in connection with Jim
Bridger specifically, and if so the results of such analysis.
STAFF RESPONSE NO.6:
a. Please see ldaho Power's response to StaffProduction Request No, 43.
b. Staffhas not speculated on the cost or performed the suggested analysis of such form
of regrrlation.
STAFF'S RESPONSE TO THE FIRST
PRODUCTTON REQUEST OF SNAKE RrVERALLIA}ICE 3 NOVEMBER I,2OI3
SRA EXHIBIT 410
Page 3 of3
t7
i8
19
20
21
22
E At Pg. 3 of Exhibit 5A, the Coal Sttrdy states: "To the extent that
statemonts, information and opinions provided by the client or others
have been used in the preparation of this report, SAIC has relied upon
the same to be accurate, and for which no asflrances are intended and
no rqnesenrtations or warranties aremade. SAIC makes no certifioation
and gles no assurarces except as explicitly set forth in this report."
I The Aliance Eppreciatas IPCo's cooperation in providing a non-oonfidontial version ofExhib it 5. See
Lotter of Lisa Nordstum to Jean Jewe[ September 27, 2013.
Ml1o, Di 10
Snake River Alliance
SRA EXIIIBIT 4I1
Page 1 of3
1
2
J
4
5
6
7
8
9
10
i1
L2
i3
t4
15
16
t7
18
t9
20
21,
22
At Pg. 7 of Exhibit 5A, the Coal Study states: 'oAt this stage of the
decision process, SAIC felt that due to the uncertainties involved in the
future envirorunental regulations, oapital expenditures, and fuel
forecasts, a planning level study was the most appropriate approach.
This study examined the likely ranges of oosts involved with the relevant
options identified for eachunit, based on a simplified analysis of the
costs ofgeneration for each ofthose options."
At Pg, 8 of Exhibit 5A', the Coal Study states: 'l.lothing contained inthis
Report is intended to indicate conditions with respect to safety or to
securityregarding the proposed upgrades or to confonriance with
agreements, oodes, pemrits, rules, or regulations of any party having
jurisdiction with respect to the construction, operation, and maintenance
of the Jim Bridger and North Valmy plants, which matters are outside
the scope and purposes of this Report."
At Pg. 10 of Exhibit 5A, the Coal Study states: "Other proposed or
potential environmental regulations that could impact iPC's coal-fired
generatingplants include the Clean Water Aot Section 16(b) regulations,
Coal Combustion Residuals ("CCR") environmental regulations, and
carbon legislation/regulation. Such proposed or potential regulations
could require additional capital expenditures and an increase in the
Fixed and Variable Operation and Maintenance ("O&Mr') costs of
affected generating units. Compliance with these environmental
Miller, Di 11
Snake River Alliance
SRA EXHIBIT 411
Page 2 of3
1
2
3
4
5
6
7
8
9
10
11
t2
13
t4
15
16
t7
18
regulatory changes could also impaot the efficiency or heat rate of
affeoted units."
At Pg. 11 of Exhibit 5A, the Coal Study states: "In addition to the SCR
andmercury conkol costs, certain other environmental retofit costs
have been identitred for the plant site, including costs for landfill
closures, catalyst replaoe,ments, and new pond constuction for solid
waste disposal. SAIC did not perform any plant site visits as part of this
sludy, and as zuc\ SAIC does not have enougft information to address
the adequacy ofthese costs."
At Pgs. 36-37 of Exhibit 5A, the Coal Study states: "IPC should
consider conducting additional detailed analysis to evaluate the most
promising alternatives considered inthis preliminary study. Such
studies should consider both annual and. cumulative projected present
value power costs, production costing simulation with and without the
various proposed alternative conversions/retirernent scenarios and
sensitivity cases and revierv of the O&M expenses under scenarios and
sensitivity oases where a major shift in the operation of generation
resourcqs might be expeoted."
Miiler, Di 12
Snake River Alliance
SRA EXHIBIT 411
Page 3 of3
Table of Contents
(Mark One)
E
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.20549
x'oRM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) Or
THE SECTIRITIES EXCHANGE ACT OF 1934
Fol the fiscal year ended December 3 1. 2012
OR
TRANSTTTON REPORT P{.TRSUANT TO SECTION 13 OR 15(d) OF
TI{E SECURITIES EXCHANGE ACT OF 1934
For the transition period from ................... to,..,.,.........
Exact name ofregistrants as specified in
their charters, address of principal executive
offices, zip code and telephone number
n
Commission
FileNumber
IRS Employer
Identification Number
t-14465
1-3 198
IDACORP, Inc.
Idaho Porver Company
l22lW.Idaho Sheet
Boise, ID 83702-5627
[phone]
State of incorporation: Idaho
82-0505802
82-0130980
Name of exchange on
which registeredSECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
IDACORP, Inc.: Common Stock, withoutpar value
SECURITIES REGISTERED PURSUANT TO SECTION I2(g) OF TIIE ACT:
Idaho Power Company: Prefelred Stock
Indicate by check mark whether the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
IDACORP, Inc. Yes (X) No ( ) Idaho Power Company Yes ( ) No (X)
tndicate by check mark ifthe regishants are not required to flle reports pursuant to Section 13 or Section I 5(d) ofthe Act.
IDACORP,Inc. Yes ( ) No (X) Idaho Power Company Yes ( ) No CX)
Indicate by check mark whether the registrants (l) have filed all reports required to be filed by Section 13 or l5(d) ofthe
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to
filesuchreports),and(2)havebeensubjecttosuchfilingrequirementsforthepast90days. Yes (X) No ( )
Indicate by check mark whether the registrants have submitted elechonically and posted on their corporate Web sites, if any,
every Interactive Data File required to be submitted and posted pursuant to Rule 405 ofRegulation S-T during the preceding 12
months (or for such shorter period that the registrants were required to submit and post such files).
IDACORP,Inc. Yes CX) No ( ) Idaho Power Company Yes (X) No ( )
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein,
will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X)
NelvYork
Stock Exchange
SRA EXHIBIT 412
, . i ..:r: Page I of 2.,r.iisii$j
Table of Contents
disputes and litigation with third parties; and changes in applicable laws or regulations. lf Idaho Power is unable to complete
the construction of a project, or incurs costs that regulators do not deem prudent it may not be able to recover its costs in full
through rates. Even if ldaho Power completes a consffuction project, the total costs may be higher than estimated and/or higher
than amounts approved for recovery by regulators. If Idaho Power does not receive timely regulatory recovery of costs
associated with those expansion and reinforcement activities, Idaho Power will have to rely more heavily on extemal debt or
equity financing for its future capital expenditures, These large capital expenditures may weaken the consolidated financial
profile of IDACORP and ldaho Power. Additionally, a significant portion of Idaho Power's facilities were constructed many
years ago, which could affect reliability, increase repair and maintenance expenses, and increase reliance on market purchases
of power, which may negatively affect IDACORP's and Idaho Power's financial condition and results of operations.
Further, if Idaho Power were unable to secure permits or joint funding commitments to dwelop hansmission infrastructure
lecessary to serve loads, such as the Boardman-to-Hemingway transmission line, it may terminate those projects and as an
altemative, develop additional generation facilities within areas where Idaho Power has available transmission capacity or
pursue other more costly options to serve loads. Termination of a project carries with it the potential for a write-offof all or a
significant portion ofthe costs associated with the project ifstate public utility commissions deny recovery ofcosts they deem
imprudently incurred, which could negatively affect IDACORP's and Idaho Power's financial condition and results of
operations.
Idaho Power's business is subject lo an extenslve set of envirunmental laws, rules, and regulalions, whlch could impacl
Idaho Powerts operutlors and lncrease costs oJ operatlons, potentially renderlng some generaling unlts uneconomicol lo
malntain or operute, anil could lnuease the cosls and aller the timing of major proJecls. A number of federal, state, and local
environmental statut€s, rules, and regulations relating to air quality, water quality, natural resources, and health and safety are
applicable to Idaho Power's operations. These laws and regulations generally require Idaho Power to obtain and comply with a
wide variety ofenvironmental licenses, permits, inspections, and other approvals, and may be enforced by both public officials
and private individuals. Some ofthese regulations are changing or subject to interpretation, and failure to comply may result in
penalties or other adverse consequences. Environmental regulations have oreated the need for Idaho Power to install new
pollution control equipment at, and may cause Idaho Power to perform environmental remediation on, its olvned or co-owned
facilities, often at a substantial cost. For instance, Idaho Power plans to install environmental control apparatus at its co-owned
Jim Bridger power plant in 2015 and 2016 at a cost ofapproximately $120 million, and a second set ofcontrol apparatus in
2021 and2022. Idaho Power expects that there will be other costs relating to environmental regulations, and those costs are
likely to be substantial. Idaho Power is not guaranteed recovery ofthose costs. For instance, in December 2012 the Oregon
Public Utility Commission disallowed in part cost recovery for certain environmental upgrades made to a coal plant by one of
Idaho Power's Northwest region peer utilities, citing an insufEcient cost analysis, If Idaho Power is similarly unable to recover
in fulI its costs through the ratemaking process, such non-recovery lvould negatively impact IDACORP's and Idaho Power's
financial condition and results of operations.
Moreovel there are many legislative and rulemaking initiatives pending at the federal and state level that are aimed at the
reduction of fossil fuel plant emissions. Idaho Power cannot predict the outcome of pending or future legislative and
rulemaking proposals, or the compliance costs ldaho Power would incur in connection with that legislation. Future changes in
environmental laws or regulations goveming emissions reduction may make certain electric generating units (especially coal-
fired units) uneconomical and zubject to shut-down, may require the adoption of new methodologies or technologies that
significantly increase costs or delay in-service dates, and may raise uncertainty about the future viability of fossil fuels as an
energy source for new and existing electric generation facilities. Furthermore, Idaho Power may not be able to obtain or
maintain all environmental regulatory approvals necessary for operation ofits facilities and execution ofits long-term strategy,
including constuction ofnew transmission and distribution infrastructure. Ifthere is a delay in obtaining any reguired
environmental regulatory approval or if Idaho Power fails to obtain, maintain, or comply with any such approval, construction
and/or operation ofldaho PoweCs generation or transmission facilities could be delayed, halted, or subjected to additional costs.
At the same time, consumer preference for renewable or Iow greenhouse gas-emitting sources of energy could impact the
desirability ofgeneration from existing sources and require significant investment in new generation and transmission
resources.
Relicensing of the Hells Canyon hydroelectric project and constuction of the proposed Gateway West and Boardman-to-
Hemingway transmission lines requires consultation under the Endangered Species Act to determine the effects of these
projects on any listed species within the project areas. The listing of species as tlreatened or endangered will result in a costly
Endangered Species Act consultation for the two transmission projects and for any future transmission projects. Similarly, the
presence of sage grouse in the vicinity of the Gateway West and Boardman-to-Hemingway tansmission projects has required
more extensive, costly, and time consuming evaluation and engineering. These and other requirements of the Endangered
SRA EXHIBIT 412
Page2 of?
2l