1. Continuing Evolution of New
Source Review
John Egan and Colin McCall
All4 Inc.
2010 Mid-Atlantic Environmental
and Energy Conference and Trade Show
Camp Hill, PA
April 14, 2010

2. Agenda
 Brief major new source review primer
 Case study example of current issues:
• Applicability analysis
• Excluded emissions
• Tracking against projections
 PM2.5 and GHG meet major NSR
 Aggregation and offsets for non-attainment
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3. Major NSR Permits
 Major new source review (NSR) is the air
permitting program for major new sources
and major modifications.
 Two different Major NSR programs:
• Prevention of Significant Deterioration (PSD) for
sources in NAAQS attainment areas
• Non-attainment New Source Review (NNSR) for
sources in NAAQS non-attainment areas
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4. NAAQS
Pollutant Averaging Time Primary Standard Secondary Standard
Particulate Matter PM10, 24 hr 150 g/m3 150 g/m3
PM2.5, annual 15 g/m3 15 g/m3
PM2.5, 24 hr 35 g/m3 35 g/m3
Sulfur Dioxide (SO2) annual 80 g/m3 (0.03 ppm) ----
24 hr 365 g/m3 (0.14 ppm) ----
3 hr ---- 1,300 g/m3 (0.5 ppm)
1 hr Coming Soon --
Nitrogen Dioxide (NO2) annual 100 g/m3 (0.053 ppm) 100 g/m3 (0.053 ppm)
1 hr 100 ppb (new std form)
Ozone (O3) 8 hr 0.075 ppm 0.075 ppm
Carbon Monoxide (CO) 8 hr 9 ppm (10 g/m3) ----
1 hr 35 ppm (40 g/m3) ----
Lead (Pb) 3-month rolling avg. 0.15 g/m3 ----
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5. NSR Major Modifications
 In order to trigger a major modification
under PSD or NNSR:
• Facility must be an existing major source and
project must result in a significant emissions
increase, or
• Project must be a major source
 Different major source thresholds and
significance levels under PSD and NNSR
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6. NSR Major Modifications
 Major modifications under both PSD and
NNSR can include:
• New emissions units
• Physical changes to existing emissions units or to
non-emissions units
• Change in the method of operation of existing
emissions units (e.g., debottlenecking)
• Removal of previous permit restrictions
• Use of fuels or raw materials that the unit could
not previously use
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7. Example – How Major NSR Works
 The Project
• Existing combination fuel boiler
 Fires primarily wood and coal
• Modification:
 Increase steam rate (more power)
 Burn more wood (biomass)
 Install new over fire air system
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8. Considerations
 Use NSR Reform:
• Actual-to-projected actual calculations
 For this discussion assume:
• Historic decrease in coal use
• Only five years of historic data available
• No baseline adjustments required
• Located in an attainment area
• Able to avoid PSD for all pollutants
• Focus on SO2 only
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9. SO2 Applicability Analysis
 Potential to emit (PTE) rate = 500 TPY (no
change)
 Baseline period selected is 2003/2004
 Baseline actual emission (BAE) rate = 300 TPY
 Projected actual emission (PAE) rate = 325 TPY
• PAE – BAE = 25 TPY
(< 40 TPY PSD significance threshold for SO2)
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10. SO2 Baseline/Future
Baseline and Projected Future Actual SO2 Emissions 2003-2018
500
Potential
to Emit
450
Project Occurs
2008
400
Baseline
+ 40 TPY
350
300
Emissions (TPY)
Baseline
300 TPY
250
200
150
100
50
0
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014-2018
Baseline Actual Emissions YEAR Projected Actual Emissions
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11. Excluded Emissions
 §52.21(b)(41)(ii)(c) states that in
determining PAE the source shall exclude
emissions following the project that the unit
could have accommodated during the
baseline period and that are unrelated to
the project, including demand growth.
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12. Excluded Emissions
 For example if PAE is 380 TPY:
PAE – BAE = 380 – 300 = 80 TPY
 If boiler operated at a rate that resulted in 30 tons
of SO2 during May 2004, a reasonable argument
may exist that the boiler could have
accommodated 360 TPY during baseline period
(i.e., 30 tons/month x 12 months)
 Any increase in SO2 cannot be due to the project
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13. Excluded Emissions
 Applicability analysis per §52.21(a)(2) and
§52.21(b)(41)(ii)(c) definition of PAE:
Excluded emissions (EE) = CHA – BAE
360 – 300 = 60 TPY
Project increase = PAE – EE – BAE
380 – 60 – 300 = 20 TPY
 Currently a controversial topic with U.S. EPA
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14. Excluded Emissions
 Do they matter?
• In first case project increase was less than
significant regardless of CHA emissions
• In second case CHA made project not
significant
• Also if the project involved other units that emit
SO2 they could affect applicability analysis
and/or future reporting
Note that the rule says “shall exclude”
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15. Permit Language
 Requirement to monitor, calculate, and record
annual boiler SO2 emission rate for 10 years
following project due to:
• Applicability approach
• Increased steaming capacity
• Reasonable possibility of significant increase per
§52.21(r) due to 25 TPY increase not counting excluded
emissions
 Requirement to submit report if annual emissions
exceed BAE by a significant amount and differ
from documented projection
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16. Future Tracked Emissions
 2009, 2010, 2011 annual SO2 emission rate
is less than BAE + 40 TPY:
• No report required
 In 2011 scarcity of biomass results in
greater coal use and annual emissions
exceed preconstruction projection
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17. Future Tracked Emissions
Projected Actual and Actual SO2 Emissions 2009-2012
500
Potential to
Emit
450
400
Baseline Baseline
+ 40 TPY 300 TPY
350
300
Emissions (TPY)
Projected Actual
250
Actual
200
150
100
50
0
2009 2010 2011 2012
YEAR
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18. Future Tracked Emissions
 By 2012 increased coal use results in
annual emissions exceeding both the BAE
+ 40 TPY and preconstruction projection:
• Report required
• Justification that emissions are within the
scope of the project
• Possibly use excludable emissions from
baseline period to support
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19. Other Thoughts
 What if in 2012 we decide to fire TDF
instead of more coal?
• Likely considered a modification if not allowed
in permit
• New applicability analysis required
• Baseline may need to change
• CHA emissions may be important
• May not be excludable
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20. More Thoughts
 The more complicated the project the greater the
potential for confusion and non-compliance. For
example say the project required wood yard
upgrades and netting for PM10:
• Required to track PM10 for project and could have
units greater than and less than projections and
not need to report
• What happens if one unit included in a multi-unit
project isn’t changed?
• How does the next project get permitted?
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21. Final Project Thoughts
 What happens if actual emissions exceed
BAE + 40 TPY due to the project?
 Maybe PTE isn’t so bad…
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22. PSD/NNSR for Fine Particulate (PM2.5)
 Several unique PSD/NNSR issues:
• Difficulty quantifying emissions
• PSD air quality modeling challenges
• NNSR applicability and offset challenges
 Impacts to project viability, schedule, and
design
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23. Quantifying PM2.5 Emissions
 PSD/NNSR will require establishing
emission limits with a margin of compliance
 Published emission factors not widely
available, particularly for condensables
 Vendor emission factors are often lacking
 Test methods available but may not be
appropriate in certain instances
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24. PM2.5 PSD Air Quality Modeling
 Significant impact levels (SILs) not finalized
 NAAQS demonstration will be difficult:
• Adding facility-wide modeled concentrations
to nearby monitored concentrations
• Current background concentrations are
above or near the 24-hour and annual
NAAQS level already
 24-hour concentrations could be temporally
paired in certain situations
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25. PM2.5 NAAQS Considerations
NAAQS
Level
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PM2.5 24-hour Concentration ( g/m3 )
7 g/m3 available
for modeling
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Monitored
Background Value
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26. PM2.5 NNSR Applicability Challenges
 Pennsylvania specific: 10-year deminimis
aggregation
 Projects with minor emission increases
must be summed with other increases and
decreases that occurred with a 10-year
lookback
 If a project triggers NNSR
requirements, the clock is “reset” with
respect to aggregation
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27. PM2.5 Deminimis Aggregation Example
 Major facility with the following historic permitting
activities:
• New project (2 tpy)
• 2007: New storage pile (1.3 tpy)
• 2005: New boiler (2.4 tpy)
• 2004: Boiler uptime improvement (3.5 tpy)
• 2002: New outdoor vent (0.9 tpy)
 Total of 10.1 tpy would need to be offset
 Same process applies to SO2 (40 tpy threshold)
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28. PM2.5 Offset Challenges
 PM2.5 emission reduction credits (ERCs) are in
short supply
 Interpollutant trading will help
 ERCs are to be obtained from the same
nonattainment area of the project
location, otherwise air quality modeling is
required
 Significant limits on the spatial separation
between the sources generating the PM2.5 ERCs
and the project location
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29. ERC Equivalency Demonstration
Project Location
ERC Location
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30. Finding PM2.5 ERCs
 Direct PM2.5 ERCs are selling in PA for
between $3,000 – $10,000 per ton with very
limited sales of ERCs from which to judge
 Determine the amount of ERCs needed
early in their planning process
 Begin looking for available ERCs as soon as
possible
 Internal reductions of PM2.5 should be given
serious consideration
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31. New NAAQS Levels
 1-Hour NO2 NAAQS: 100 ppb
 Extremely stringent for a 1-hour averaging
time standard.
 No proposed SIL, awaiting guidance.
 Proposed 1-Hour SO2 NAAQS with similar
issues as the NO2 NAAQS
 No grandfathering of PSD permit applications
that have not received final approval (even
with draft permits)
 Challenge for NAAQS demonstrations that
correspond to Title V renewals
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32. New NAAQS Levels
 Any major facility will have difficulty
demonstrating compliance using facility-wide
modeling
 Strategic approaches to permitting:
 Look for emission reductions where they are
available (to either avoid major source
permitting or to decrease modeled impacts)
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33. GHG Tailoring Rule
 “Major Sources” of GHGs
 Regulated GHG pollutants
 PSD implications and timing
 U.S. EPA will begin regulating GHGs for
stationary sources in January 2011
 No grandfathering for permit
applications that have not been issued
 Addressing GHGs in construction permit
emissions inventories and control
technology requirements (BACT, etc.)
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34. Conclusions
 NSR applicability process is still evolving
 Implications of new NAAQS are immediate
and far reaching
 GHGs can’t be ignored
 Environmental considerations will impact
planning and design
 Pay attention to these issues and try not to
be surprised
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35. Questions?
John and Colin
All4 Inc.
2393 Kimberton Road
P.O. Box 299
Kimberton, PA 19442
610.933.5246 x14 and x20
www.all4inc.com
jegan@all4inc.com
cmccall@all4inc.com
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