1. icfi.com |
Bruce Hedman
March 5, 2013
Update on ICI Boiler
MACT

2. 2icfi.com |
Clean Air Acts Standards for Boilers and
Incinerators
 On December 20, 2012, EPA finalized a specific set of adjustments to
March 2011 Clean Air Act standards for boilers and certain solid
waste incinerators
− Area Source Boiler Rule
− Major Source Boiler Rule (ICI Boiler MACT)
− Commercial and Industrial Solid Waste Incinerators MACT
 Adjustments based on new data and additional information on real-
world performance
− Maintain public health benefits by reducing toxic air pollution,
including mercury and particulates
− Increase flexibility of compliance
− Maintain cuts in the cost of implementation represented by March
2011 rule
− Provide clarity in identifying which non-hazardous secondary materials
are, or are not, solid wastes

3. 3icfi.com |
Compliance Timelines
 Adjustments to numerical emissions limits and to technology
subcategories significant enough to warrant allowing a full three
years for compliance
 Major Source Boiler Rule (ICI Boiler MACT)
− Three years after publication in Federal Register (January 31, 2016)
− Sources may request an additional year if required for the installation
of controls or repowering (installation of CHP included)
 Area Source Boiler Rule
− Timeline for initial notification for existing area source boilers no later
than January 2014
− Compliance date for emissions limits, tune-up requirements and
energy assessments March 21, 2014
 CISW Incinerator Rule
− Five years after publication in Federal Register (January 31, 2016)

4. 4icfi.com |
Affected Major and Area Source Boilers
Major Source Boilers
About 14,000 Covered Units
88% follow work
practice rules
12% have
numerical
limits
About 183,000 Covered Units
(no natural gas boilers)
Less than 1%
have limits
99% follow work
practice rules
12,300 need to follow work practice
standards such annual tune ups
1,700 need to meet numerical
emissions limits
182,400 need to follow work
practice standards such tune ups
600 need to meet numerical
emissions limits
Area Source Boilers

5. 5icfi.com |
ICI Boiler MACT (Major Source Rule)
 Standards for hazardous air pollutants from major sources:
industrial, commercial and institutional boilers and process heaters
(excludes any unit combusting solid waste)
 Major source is a facility that emits:
− 10 tpy or more of any single Hazardous Air Pollutant, or 25 tpy or
more of total Hazardous Air Pollutants (HAPs)
 Emissions limits applicable to new and existing units > 10
MMBtu/hr
− Mercury (Hg)
− Filterable Particulate Matter (PM) or Total Selective Metals (TSM) as
a surrogate for non-mercury HAP metals
− Hydrogen Chloride (HCl) as a surrogate for acid gas HAP
− Carbon Monoxide (CO) as a surrogate for non-dioxin/furan organics
5

6. 6icfi.com |
ICI Boiler MACT (cont’d)
 For new and existing units < 10 MMBtu/hr – the rule
establishes a work practice standard instead of numeric
emission limits (periodic tune-ups)
 Rule significantly impacts oil, coal, biomass, and process
gas boilers
− Emission limits must be met at all times except for start-up and
shutdown periods
− Controls are potentially required for Hg, PM, HCI, and CO
− Also includes monitoring and reporting requirements
− Limits are difficult (technically and economically) for oil and coal
boilers (especially older units)

7. 7icfi.com |
Compliance Strategies
 Standard Control Technologies for Affected Boilers
− Mercury (Hg): Fabric filters and activated carbon injection are
the primary control devices
− Particulate Matter (PM): Electrostatic precipitators may be
required for units to meet emission levels
− Hydrogen Chloride (HCl): Wet scrubbers or fabric filters with dry
injection are the primary control technologies
− Carbon Monoxide (CO): Tune-ups, replacement burners,
combustion controls and oxidation catalysts are the preferred
control technologies
Required compliance measures for any unit depend on current
emissions levels from the units and the control equipment
already in place

8. 8icfi.com |
 Convert boilers to natural gas
− Replace burners in existing boilers with natural gas
burners (lose efficiency)
− Replace boiler with natural gas boiler
− Compliance becomes straight forward (tune-ups in lieu
of more rigorous control options)
Compliance Strategies

9. 9icfi.com |
 Install a natural gas fueled CHP system
− Gas turbine/generator produces electricity
− Turbine waste heat generates steam through a HRSG
 Represents a tradeoff of benefits versus additional
costs
– Represents a productive investment
– Potential for lower steam costs due to generating own
power
– Higher overall efficiency and reduced emissions
– Higher capital costs, but partially offset by required
compliance costs or new gas boiler costs
Compliance Strategy

10. 10icfi.com |
ICI Boiler MACT - Potential CHP Capacity
Fuel Type
Number
of
Facilities
Number of
Affected
Units
Boiler
Capacity
(MMBtu/hr)
CHP
Potential
(MW)
CO2
Emissions
Savings
(MMT)
Coal 332 751 180,525 18,055 114.2
Heavy Liquid 170 367 48,296 4,830 22.9
Light Liquid 109 241 22,133 2,214 10.5
Total 611* 1,359 250,954 25,099 147.6
*Some facilities are listed in multiple categories due to multiple fuel types;
there are 567 ICI affected facilities
•CHP potential based on average efficiency of affected boilers of 75%; Average annual load factor of
65%, and simple cycle gas turbine CHP performance (power to heat ratio = 0.7)
• GHG emissions savings based on 8000 operating hours for coal and 6000 hours for oil, with a CHP
electric efficiency of 32%, and displacing average fossil fuel central station generation

11. 11icfi.com |
 Compares cost of compliance options for coal
and/or oil fired boilers:
− Installing control technologies on existing boilers
− Replacing existing boilers with new natural gas boilers
− Converting existing boilers for operation on natural gas
− Replacing existing boiler with a natural gas fueled
combustion turbine CHP system
CHP Analysis

12. 12icfi.com |
CHP Analysis
XYZ Papers
Boiler Unit Data:
Unit Type
Total Capacity
(MMBtu/hr) Primary Fuel
Hours of
Operation Year Installed
Emissions
Control
Technology
Stoker/Sloped Grate Boiler 156 Coal 8400 1960 ESP
Stoker/Sloped Grate Boiler 245 Coal 8539 1968 ESP
Total Coal Capacity: 401 Max Hours 8539
Compliance Control Requirements:
Fabric Filter TCI = $0
Electrostatics Precipitator TCI = $0
Scrubber TCI = $0
Dry Sorbent Injection followed by a Fabric Filter (DIFF) TCI = $17,895,905
CO Oxidation Catalyst TCI = $12,954
Boiler Tune-up TCI = $12,954
Total Capital Cost of Controls = $17,921,813
Total Annual Operating Costs of Controls = $3,111,550
Fuel Switching Alternative Compliance Option:
Boiler Conversion to Natural Gas Costs $6,621,935
Coal Boiler Replacement Cost $14,560,413
Natural Gas Access Cost (if gas is not available at the site) $390,720
Coal Boiler Decommissioning Cost $8,767,111
Total Fuel Switching TCI = $14,560,413

13. 13icfi.com |
CHP Analysis
Comparative Cost of Compliance Options
Upgrade Coal
Boilers
Boiler
Replacement:
New Natural
Gas Boilers
Boiler
Conversion:
Natural Gas
Burners and
Controls
Natural Gas
CHP
Boiler Capacity, MMBtu/hr input 401.0 401.0 401.0 NA
Avg Steam Demand, MMBtu/hr 248.6 248.6 248.6 248.6
Boiler Efficiency 78% 80% 70% NA
CHP Capacity, MW 0 0 0 17
CHP Electric Efficiency NA NA NA 34%
Fuel Use, MMBtu/year 2,721,964 2,653,915 3,033,046 3,463,714
Annual Fuel Cost $6,532,714 $13,269,575 $15,165,228 $17,318,568
Annual O&MCost $4,082,946 $1,778,123 $2,032,141 $2,794,264
Annual Compliance O&M $3,111,550 NA NA NA
Annual Electric Savings ($8,492,036)
Annual Steam Operating Costs $13,727,210 $15,047,697 $17,197,369 $11,620,796
Annual Operating Savings (coal
compliance) $2,106,413
Annual Operating Savings (gas
boiler) $3,426,901
Based on: Coal Price: 2.40 $/MMBtu
Natural Gas Price: 5.00 $/MMBtu
Electricity Price: 0.065 $/kWh

14. 14icfi.com |
CHP Analysis Annual Steam Operating Costs $13,727,210 $15,047,697 $17,197,369 $11,620,796
Annual Operating Savings (coal
compliance) $2,106,413
Annual Operating Savings (gas
boiler) $3,426,901
Capital Costs $17,921,813 $14,560,413 $6,621,935 $26,747,867
CHP Incremental costs
(coal compliance)
CHP Payback
(coal compliance) 4.2
CHP Incremental costs
(gas boiler)
CHP Payback
(gas boiler) 3.6
Cash Flow Projections
Upgrade Coal
Boilers
New Natural
Gas Boilers
Boiler
Conversion to
Natural Gas
Natural Gas
CHP
Capital Costs $17,921,813 $14,560,413 $6,621,935 $26,747,867
5 YR Annual Fuel Cost $34,683,064 $70,449,973 $80,514,255 $91,946,629
5 YR Annual O&MCost $21,676,915 $9,440,296 $10,788,910 $14,835,127
5 YR Annual Compliance O&M $16,519,642 $0 $0 $0
5 YR Annual Electric Savings $0 $0 $0 ($45,085,370)
5 YR Net Cash Flow (Output) $90,801,433 $94,450,682 $97,925,100 $88,444,253
Capital Costs $17,921,813 $14,560,413 $6,621,935 $26,747,867
10 YR Annual Fuel Cost $74,890,240 $152,120,801 $173,852,344 $198,537,972
10 YR Annual O&MCost $46,806,400 $20,384,187 $23,296,214 $32,033,105
10 YR Annual Compliance O&M $35,670,434 $0 $0 $0
10 YR Annual Electric Savings $0 $0 $0 ($97,351,670)
10 YR Net Cash Flow (Output) $175,288,887 $187,065,401 $203,770,493 $159,967,273
10 YR IRR - Natural Gas CHP vs Coal Compliance Baseline Case 23%
$5,158,141
$8,826,054
$12,187,454
10 Yr NPV - Natural Gas CHP vs Coal Compliance Baseline Case

15. 15icfi.com |
 DOE Boiler MACT Technical Assistance Program (Decision Tree
Analysis):
http://www.1.eere.energy.gov/manufacturing/distributedenergy/boilermact.html
DOE Technical Assistance
Contact us at:
Decision Tree Analysis

16. 16icfi.com |
Boiler MACT Sites in Alabama
Fuel Type # Boilers Capacity (MMBTu/hr)
Coal 16 6,347
Heavy Oil 10 1,483
Light Oil 3 704
Process Gas 4 480
Biomass 49 13,823
Total 82 22,836
Total Affected
Sites
41
Paper
Chemicals
Nonmetallic Minerals

17. 17icfi.com |
Boiler MACT Sites in Arkansas
Fuel Type # Boilers Capacity (MMBTu/hr)
Coal 3 471
Heavy Oil 2 1,079
Light Oil 0 0
Process Gas 0 0
Biomass 52 7,014
Total 57 8,564
Total Affected
Sites
30
Paper
Nonmetallic Minerals

18. 18icfi.com |
Boiler MACT Sites in Iowa
Fuel Type # Boilers Capacity (MMBTu/hr)
Coal 39 14,641
Heavy Oil 3 145
Light Oil 5 432
Process Gas 0 0
Biomass 7 709
Total 54 15,927
Total Affected
Sites
22
Food Processing
Universities
Fabricated Metals

19. 19icfi.com |
Boiler MACT Sites in Illinois
Fuel Type # Boilers Capacity (MMBTu/hr)
Coal 36 9,478
Heavy Oil 2 178
Light Oil 7 584
Process Gas 13 1,199
Biomass 1 18
Total 59 11,458
Total Affected
Sites
25
Food Processing
Chemicals
Machinery

20. 20icfi.com |
Boiler MACT Sites in Tennessee
Fuel Type # Boilers Capacity (MMBTu/hr)
Coal 39 11,811
Heavy Oil 7 693
Light Oil 12 270
Process Gas 0 0
Biomass 15 2,273
Total 73 15,046
Total Affected
Sites
26
Paper
Government Facilities
Universities

21. 21icfi.com |
Texas Permitting Options
Texas has three permitting routes for CHP –
 Standard Permit – applies to most EGUs
 Permit by Rule (PBR) – only applies to
natural gas CHP systems
 Case-by-Case – applies to systems not
eligible under the 1st two options

22. 22icfi.com |
Texas Standard Permit
 Issued in 2001, revised in 2007
 Defined permitting procedure for CHP and other
EGUs
 Includes output-based NOx limits
o No size constraints
o Separate limits for East and West Texas
 Must use either:
o Natural gas
o Landfill gas, digester gas, stranded oilfield gas
o Liquid fuels

23. 23icfi.com |
Texas Standard Permit
 Allows for CHP thermal credit:
o Provides a compliance credit based on a rate of 1
MWh for each 3.4 MMBtu of heat recovered(added
to denominator of lbs/MWh emissions rate).
o To receive compliance credit, the heat recovered
must be > 20% of the total energy output of the
CHP unit
o The SP can be accessed at:
http://www.tceq.texas.gov/assets/public/permitting/air/NewSourceR
eview/Combustion/egu_techsum_sp.pdf

24. 24icfi.com |
Texas Permit by Rule (PBR)
 Issued in July 2012
 Expedited permit option for CHP systems fueled by
“pipeline-quality” natural gas
o Emergency fuels (propane, LPG, diesel, etc.) may be
used for no more than 720 hours in any 365 day period
 CHP systems < 20 kW are exempt from permitting
requirements
 Individual CHP system or any group of units may not
exceed 15 MW in capacity
 CHP systems from 8 to 15 MW must install an oxidation
catalyst
 No supplemental firing (gas turbines)

25. 25icfi.com |
Texas Permit by Rule (PBR)
 PBR output-based NOx limits are generally less
stringent than those in the standard permit; CO limits
also apply
 Recovered heat must be > 20% of the total heat energy
output to qualify
o Total heat energy output is “fuel in” minus “power out”
 CHP thermal credit same as under the standard permit
o 1 MWh for each 3.4 MMBtu of heat recovered
 The PBR can be accessed at:
http://info.sos.state.tx.us/pls/pub/readtac$ext.TacPage?sl=R&app=9&p_dir=&p
_rloc=&p_tloc=&p_ploc=&pg=1&p_tac=&ti=30&pt=1&ch=106&rl=513

26. 26icfi.com |
PBR M&V Requirements
 Reciprocating engine (ICE) > 20kW – analyze emissions
within 180 days with portable analyzer; ongoing
monitoring every 6 months
 If CHP unit not certified by manufacturer, tested within
90 days of startup; Gas turbines and ICE > 375kW
retest every 16,000 hours
 If oxidation catalyst required, tested within 90 days and
retest every 16,000 hours
 Records need to be kept for 2 years – non compliance
events, maintenance, and emergency fuel hours.

27. 27icfi.com |
Texas NOx Limits
Operating > 300 hrs/yr 0.47
Operating < 300 hrs/yr 1.65
Operating > 300 hrs/yr with a
capacity > 250 kW
0.14
Operating < 300 hrs/yr 0.47
Any unit with a capacity < 250 kW 0.47
Operating > 300 hrs/yr 3.11
Operating < 300 hrs/yr 21
Operating > 300 hrs/yr 0.14
Operating < 300 hrs/yr 0.38
EGUs firing any
gaseous or liquid
fuel with at least
75% landfill gas,
digester gas,
stranded oilfield
gas, or gaseous or
liquid renewable
fuel by volume
(*Except in West
Texas)
On or after
5/16/2007
N.A. 1.9
CHP units powered
by pipeline quality
natural gas-fired
engines and turbines.
Applies to an
individual unit or
group of units up to
15 MW.
20 kW to 8
MW
1.0
Installed prior to
1/1/2005
Installed on or
after 1/1/2005
East Texas
< 10 MW
West Texas
< 10 MW
On or after
5/16/2007
On or after
5/16/2007
Units > 10 MW
> 8 MW to <
15 MW
(Must have an
oxidation
catalyst)
0.7
EGU NOx limits -
applies to units
installed on or
after 5/16/2007.
Units are limited to
the use of the
following fuels: 1)
natural gas, 2)
landfill gas,
digester gas,
stranded oilfield
gas, or gaseous
renewable fuel, or
3) liquid fuels not
containing waste
oils or solvents
Standard Permit NOx limits Permit by Rule (PBR) NOx limits