icfi.com |

Bruce Hedman March 5, 2013

Update on ICI Boiler MACT

2 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.com |

CHP Analysis XYZ Papers

Boiler Unit Data:

Unit TypeTotal Capacity (MMBtu/hr) Primary Fuel

Hours of Operation Year Installed

Emissions Control

TechnologyStoker/Sloped Grate Boiler 156 Coal 8400 1960 ESPStoker/Sloped Grate Boiler 245 Coal 8539 1968 ESP

Total Coal Capacity: 401 Max Hours 8539

Compliance Control Requirements:Fabric Filter TCI = $0Electrostatics Precipitator TCI = $0Scrubber TCI = $0Dry Sorbent Injection followed by a Fabric Filter (DIFF) TCI = $17,895,905CO Oxidation Catalyst TCI = $12,954Boiler Tune-up TCI = $12,954Total 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 $6,621,935Coal Boiler Replacement Cost $14,560,413Natural Gas Access Cost (if gas is not available at the site) $390,720Coal Boiler Decommissioning Cost $8,767,111Total Fuel Switching TCI = $14,560,413

13 icfi.com |

CHP Analysis Comparative Cost of Compliance Options

Upgrade Coal Boilers

Boiler Replacement: New Natural Gas Boilers

Boiler Conversion: Natural Gas Burners and

ControlsNatural 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&M Cost $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 $/MMBtuNatural Gas Price: 5.00 $/MMBtu

Electricity Price: 0.065 $/kWh

14 icfi.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 ProjectionsUpgrade Coal

BoilersNew Natural Gas Boilers

Boiler Conversion to

Natural GasNatural Gas

CHPCapital Costs $17,921,813 $14,560,413 $6,621,935 $26,747,8675 YR Annual Fuel Cost $34,683,064 $70,449,973 $80,514,255 $91,946,6295 YR Annual O&M Cost $21,676,915 $9,440,296 $10,788,910 $14,835,1275 YR Annual Compliance O&M $16,519,642 $0 $0 $05 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 $26,747,86710 YR Annual Fuel Cost $74,890,240 $152,120,801 $173,852,344 $198,537,97210 YR Annual O&M Cost $46,806,400 $20,384,187 $23,296,214 $32,033,10510 YR Annual Compliance O&M $35,670,434 $0 $0 $010 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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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 icfi.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/NewSourceReview/Combustion/egu_techsum_sp.pdf

24 icfi.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 icfi.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 icfi.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 icfi.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 l iquid fuel with at least 75% landfil l gas, digester gas, stranded oilfield gas, or gaseous or l iquid 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 5/16/2007Units > 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 l imited to the use of the following fuels: 1) natural gas, 2) landfil l gas, digester gas, stranded oilfield gas, or gaseous renewable fuel, or 3) l iquid fuels not containing waste oils or solvents

Standard Permit NOx limits Permit by Rule (PBR) NOx limits