UNITED STATES ENVIRONMENTAL PROTECTION AGENCY REGION IX 75 Hawthorne Street San Francisco, CA 94105



## MEMO

SUBJECT: Revised GHG Emissions for the SPI-A nderson Prevention of Significant Deterioration (PSD) Permit Project

TO: SPI-Anderson PSD Permit Administrative Record

FROM: Shaheerah Kelly, Environmental Engineer U.S. EPA, Region 9, Air Division, Permits Office

DATE: April 25, 2014

On November 29, 2013, EPA finalized amendments to 40 CFR Part 98, which included amendments related to the global warming poten tial (GWP) factors and cer tain default emission factors used for calculating GHG emissions. These amendments became effective on January 1, 2014.

The attachment contains EPA Region 9’s upda ted GHG emissions calculations and other GHG emissions-related data for the SPI-Anderson project.

AttachmentRevised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 1 

## Revised GHG Emissions Evaluation SPI-Anderson PSD Project

1. Introduction

EPA’s PSD permitting regulations define greenh ouse gases (GHGs) as an aggregate of: carbon dioxide (CO 2 

### ), methane (CH 4 

### ), nitrous oxide (N 2 

### O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), a nd sulfur hexafluoride (SF 6 

### ). (See 40 CFR § 52.21(b)(49)(i).) The proposed new equipment at the SPI-Anderson facility has the pot ential to emit only three of these GHGs: CO 2 

### , CH 4 

### , and N 2 

### O. All GHG emissions associated with the proposed new equipment will be generated by the biomass-fired boiler, which is part of the cogeneration unit, and emergency engine; the cooli ng tower will not emit any GHGs.

EPA regulations further define CO 2 

### e as the sum of the mass emi ssions of the constituent GHG, each multiplied by the appropriate global warming potential (GWP) factor provided in Table A-1 of the Federal Mandatory GHG Reporting Ru le at 40 CFR Part 98. (See 40 CFR § 52.21(b)(49)(ii).) On November 29, 2013, EPA fina lized amendments to 40 CFR Part 98, which included amendments related to the GWP factors and certain default emission factors used for calculating GHG emissions. The sp ecific GWP and emission factor amendments in the Part 98 regulations that are relevant to the SPI-Anderson project are pr ovided in Tables 1-1 and 1-2 below. These amendments became effective on January 1, 2014. Therefore, EPA Region 9 is updating the GHG emissions calculations and other GHG emissions-related data in our Supplemental Statement of Basis and Ambient Air Quality Impact Report for Greenhouse Gases issued in November 2013 (GHG AAQIR) based on the amended rule.

Table 1-1 : GWP Amendments in 40 CFR Part 98
GHG Pollutant Previous GWP Revised GWP

Carbon Dioxide (CO 2 ) 1 1 (No change)
Methane (CH 4 ) 21 25

Nitrous Oxide (N 2 O) 310 298

Sulfur hexafluoride (SF 6 ) 23,900 22,800Revised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 2 Table 1-2 : Default Emission Factor Amendments in 40 CFR Part 98

Fuel Type GHG Pollutant Emission Factor (kg/MMBtu)

Previous Emission Factors Revised Emission Factors

Wood and Wood Residuals CO 2 93.8 93.8 (No change)

CH 4 0.032 0.0072

N 2 O 0.0042 0.0036

Natural Gas CO 2 53.02 53.06

CH 4 0.001 0.001 (No change)

N 2 O 0.0001 0.0001 (No change)



## 2. Revised GHG Emission Estimates for Proposed New Equipment

Table 2-1 lists the proposed new equipment that is subject to PSD review, and that will be regulated by the PSD permit.

Table 2-1 : New and Existing Equipment List

Unit Description

Stoker Boiler with Reciprocating Grate  Biomass-fired with natural gas burners for start-up, shutdown, and flame stabilization.

 Maximum annual average heat input of 468 MMBtu/hr and steam generation rate of 250,000 lbs/hr

 Equipped with two natural gas burners, each with a maximum rated heat input of 62.5 MMBtu/hr

 Equipped with SNCR system to reduce nitrogen oxides, and multiclone with ESP to control PM emissions

Emergency Engine  256 hp at 1,800 rpm

 Used to run the emergency boiler recirculation pump

 Natural-gas fired
Cooling Tower  Composed of three cells with an e xpected water load of 4.24 gallons per minute per square foot.



### The proposed biomass-fired boiler that is part of the cogeneration unit is expected to have a maximum annual average heat input of 468 million British thermal units per hour ( MMBtu/hr), and an annual average heat input of 425 MMBtu/h r. The biomass boiler will also be equipped with two 62.5 MMBtu/hr natural ga s burners that will be used during startup, and, potentially,Revised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 3 

### during shutdown and for flame stabilization. The biomass boiler will combust a small amount of natural gas throughout the year, but the vast major ity of emissions will be from combustion of wood and wood-residual solid biomass fuel.

The proposed emergency engine will be natural- gas-fired, and will operate as a feedwater pump used to circulate water through the cogeneration unit boiler in case of an emergency shutdown while disconnected from the grid. The emergenc y engine will have a maximum heat input of 2.16 MMBtu/hr, and will be operated a maximum of 100 hours per year for maintenance and testing purposes, in addition to any emergency use.

Tables 2-2 and 2-3 summarize the GHG emissions for the biomass boiler and emergency engine, and total CO 2 

### e emissions from the project, and show th at the proposed project has the potential to generate a maximum of 429,182 tons of CO 2 

### e per year (which is less than the previous estimate of 432,439 tons of CO 2 

### e per year in our GHG AAQIR wh ich is based on the previous GWP and emission factors in 40 CFR Part 98).

Table 2-2: Greenhouse Gas Emissions for Proposed New Equipment

Emission Unit GHG Pollutants Emission Factor 1 (Heat Input) Global Warming Potential 2 GHG Pollutant Emission Rate (tpy) 3 CO 2 e Emission Rate (tpy) (kg/MMBtu) (lb/MMBtu)

Stoker Boiler CO 2 93.8 206.60793 1 423,513 423,513 CH 4 0.0072 0.01586 25 33 813 N 2 O 0.0036 0.00793 298 16 4,844 Total CO 2 e -- -- --

-- 429,170

Emergency Engine CO 2 53.06 116.87225 1 13 13 CH 4 0.001 0.00220 25 0.00024 0 4
N 2 O 0.0001 0.00022 298 0.00002 0 5
Total CO 2 e -- -- -- -- 13

1 The kg/MMBtu emission factors for combustion of wood and wood residual solid biomass fuel, and natural gas, are from 40 CFR Part 98, Tables C-1 and C-2; the lb/MMB tu emission factors are calcu lated by converting the kg/MMBtu emission factors using 2.2046 lb/kg.

2 100-year time horizon global warming potential (GWP – from 40 CFR Part 98, Table A-1).

3 Calculated by multiplying the emission factor by the maximum annual average heat input (468 MMBtu/hr for the cogeneration unit and 2.16 MMBtu/hr for the emergency pump engine). Annual emission rates are based on 8,760 hr/yr operation for the cogeneration unit, and 100 hr/yr for the emergency pump engine. CO 2 e was calculated by multiplying each individual emission rate by the applicable GWP factor, and summing.

4 CO 2 e estimate for CH 4 is less than 1 tpy.

5 CO 2 e estimate for N 2 O is less than 1 tpy.Revised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 4 Table 2-3: Total Greenhouse Gas Emi ssions for Proposed New Equipment

GHG Pollutants Previous CO 2 e Emission Rate from November 2013 AAQIR (tpy) Revised CO 2 e Emission Rate (tpy)

CO 2 423,526 423,526 CH 4 3,034 813 N 2 O 5,879 4,844 Total 432,439 429,182



### The PSD permit limits the annual heat input from natural gas to not exce ed 10 percent of the total heat input on an annual basis. Operati on of the natural gas burners will not exceed 10 percent of the annual heat i nput capacity of the boiler, or 409,968 MMBtu/yr (468 MMBtu/hr * 8,760 hr/yr * 10%). Based on that maximum a nnual heat input, and the revised GWPs and emission factors for natural gas combustion in 40 CFR Part 98, the ma ximum GHG emissions from the natural gas burners is expe cted not to exceed 23,968 tons of CO 2 

### e per year (which is less than the previous estimate of 23,981 tons of CO 2 

### e per year in our GHG AAQIR which is based on the previous GWP and emi ssion factors in 40 CFR Part 98).

The proposed cogeneration unit will be started an d shutdown as infrequently as possible. SPIanticipates at least one outage period each year for maintenance; any additional shutdown-andstartup cycles will be the result of an unschedul ed event. It will take approximately 12 hours to start the cogeneration unit; natural gas burners will be used to heat the refractory for the first 6 hours, and then biomass fuel will be phased in and gas firing phased out over the final 6 hours. Shutdown will take approximately 1 hour to accomp lish, and the natural gas burners will be used only if elevated carbon monoxide (CO) levels are indicated by the continuous emissions monitoring system (CEMS). Based on the startup protocol outlined above, a revised calculated estimate of GHG emissions is provided in Tables 2-4 and 2-5.

Table 2-4: Greenhouse Gas Emissions for Startup Periods

Fuel GHG Pollutants Emission Factor 6 (lb/MMBtu) Hourly Emission Rate 7 (lb/hr) Event Emission Rate 8 (lb/event)

Firing Biomass Fuel CO 2 206.60793 96,876 581,256 CH 4 0.01586 7 45 N 2 O 0.00793 4 22 Total CO 2 e -- 98,167 589,005

Firing Natural Gas CO 2 116.87225 7,305 43,827 CH 4 0.0022 0 1 N 2 O 0.00022 0 0 Total CO 2 e -- 7,312 43,872

6 The CH 4 and N 2 O emission rates were increased by a factor of 4 to reflect incomplete combustion during startup; a similar approach was taken when calculating CO and VOC emission rates during startup.

7 Hourly emission rates are based on 468 MMBtu/hr when firing biomass, and 125 MMBtu/hr when firing natural gas.

8 Event emission rate is the hourly em ission rate multiplied by 6 hours.Revised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 5 

### As shown in Table 2-5, overall startup emissions from the proposed biomass boiler are expected to be 316 tons per startup event (which is le ss than the previous es timate of 359 tons of CO 2 

### e per year in our GHG AAQIR which is based on the previous GWP and emission factors in the 40 CFR Part 98 regulations).

Table 2-5: Total Greenhouse Gas Emissions for Startup Periods

GHG Pollutants Previous Emission Rates from GHG AAQIR Revised Emission Rates

Average Hourly Emission Rate (lb/hr) Event Emission Rate (lb/event) Event Emission Rate (ton/event) Average Hourly Emission Rate (lb/hr) Event Emission Rate (lb/event) Event Emission Rate (ton/event )
CO 2 55,691 668,288 334 104,181 625,083 313 CH 4 66 794 0.397 8 45 0.0227 N 2 O 9 104 0.0521 4 22 0.0112 Total CO 2 e 59,771 717,250 359 105,479 632,877 316



## 3. Revised GHG Emission Estimates for Existing Equipment

Table 3-1 lists the existing e quipment currently located at the SPI-Anderson facility.

Table 3-1 : New and Existing Equipment List

Unit Description

Wellons Stoker Boiler  Biomass-fired Boiler

 Maximum annual average heat input of approximately 116.4 MMBtu/hr

 Equipped with SNCR system to reduce NO x , and multiclone with ESP to control PM emissions

 Equipped with one 30,400 ft 3

, 2 hog fuel bins, 2 wood chip fuel bins

Conveyance System  (2) Cyclones with combined flow rate of 51.004 scfm

 (1) 7,118 ft 2 MAC Pulse Jet Baghouse with 300hp Blower

 (1) 35” x 45” Rotary Airlock

 (1) Buhler en-masse, 19”, 22tph Conveyor

 (2) Each overhead storage bi ns with enclosed sides
Spray Unit  Closed loop unit equipped with integrated, negative pressure, mist collection system and 65’ exhaust stack
Wood Chip Loading Facility  (1) Platform truck dumper

 (1) Wood chip conveying system with dust containment hood

 (1) 200hp, 59,000CFM Rader blower 7 De-greasing Tanks  Non-solvent based tanks Gasoline Storage Tank  Above ground with 10,000 gallon capacity tank Painting Operation  Miscellaneous painting operation Drying Kilns  (8) steam-heated, double-track, lumber drying kilnsRevised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 6 

### Existing equipment at the facility includes a biomass-fired boiler with a maximum annual average heat input capacity of 116.5 MMBtu/hr, and a circuit breaker and two switches that utilize sulfur hexafluoride (SF 6 

### ) as a dielectric medium. The existing boiler will be decommissioned and dismantled after the new coge neration unit is constructed and operating. The existing circuit breaker will be used by the new equipment and will not be modified. There are also eight steam-heated, double-track, kilns us ed for drying lumber at the facility. No combustion occurs in the kilns; thus , no GHGs are emitted from the kilns.

Tables 3-2 and 3-3 summarize the revised GHG emission rate calculations for the existing equipment at the facility.

Table 3-2: Greenhouse Gas Emi ssions for Existing Equipment

Emission Unit GHG Pollutants Emission Factor 9 (Heat Input) Global Warming Potential GHG Pollutant Emission Rate (tpy) CO 2 e Emission

Rate 10 (tpy) (kg/MMBtu) (lb/MMBtu)

Biomass Boiler CO 2 93.8 206.60793 1 105,335 105,335 CH 4 0.0072 0.01586 25 8 202 N 2 O 0.0036 0.00793 298 4 1,205 Total CO 2 e -- -- -- -- 106,742
Circuit Breaker SF 6 1% leakage/year 22,800 0.000950 5 Total CO 2 e -- -- -- -- 5

Table 3-3: Total Greenhouse Gas Em issions for Existing Equipment

GHG Pollutants Previous CO 2 e Emission Rate from GHG AAQIR (tpy) Revised CO 2 e Emission Rate (tpy)

CO 2 105,335 105,335 CH 4 755 202 N 2 O 1,462 1,205 SF 6 5 5 Total CO 2 e 107,557 106,747

9 The kg/MMBtu emission factors for combustion of wood and wood residual solid biomass fuel, and natural gas, are from 40 CFR Part 98, Tables C-1 and C-2; the lb/MMBtu emission factors are calculated by multiplying the kg/MMBtu emission factors by 2.2046 lb/kg.

10 The emission rate for the existing biomass-fired boiler was calculated by multiplying the emission factor by the maximum heat input (116.4 MMBtu/hr); annual emission rates are based on 8,760 hr/yr operation. The annual SF 6 emission rate for the switchgear was calculated by multiplying the SF 6 capacity of the existing breaker and two switches (190 lb) by th e annual leak rate of (1%, which was the industry standard at the time the equipment was installed) ; the hourly emission rate was based on the assumption that the leak rate is uniform throughput the year. CO 2 e was calculated by multiplying each individual emission rate by the applicable GWP factor, and summing them to obtain the total CO 2 e emissions.Revised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 7 

## 4. Revised GHG Emission Estimates for Best Available Control Technology (BACT) Purposes

BACT is required for GHG emissions for the new proposed emission units. Generally, the BACT analysis is a top-down pr ocess involves that ranking ava ilable control technologies in descending order of control effectiveness in which the top, most stringent technology is established as BACT unless, the PSD permit applicant demonstrates that technical considerations, or energy, environmental, or eco nomic impacts justify a conclusion that the most stringent technology is not achieva ble for the case at hand. If th e most stringent technology is eliminated, then the next most stringent option is evaluated until BACT is determined. The topdown BACT analysis is a case-by-case exercise for the particular source under evaluation.

EPA Region 9’s GHG AAQIR cont ains the top-down GHG BACT analysis, performed in accordance with 40 CFR § 52.21 and relevant EPA guidance and policies, for the proposed biomass-fired boiler and natural gas-fired em ergency engine. (See Section 5 of the GHG AAQIR.) Since GHG emissions data was not used in the BACT analysis for the proposed natural gas-fired emergency engine, our top-dow n BACT analysis and BACT determination for this unit has not changed as a result of the revi sed GHG calculations. Therefore, our revised topdown BACT analysis for the proposed biomass- fired boiler due to EPA’s amendments to 40 CFR Part 98 regulations is provide d in the following sections.


## 4.1. Step 1 – Identify Ava ilable Control Technologies

The revised GHG emission estimates for this project do not change our analysis for step 1 of the top-down BACT analysis.


## 4.2. Step 2 – Eliminate Technica lly Infeasible Control Technologies

The revised GHG emission estimates for this project do not change our analysis for step 1 of the top-down BACT analysis.


## 4.3. Step 3 – Rank Remaining Control Technologies by Control Effectiveness

EPA made the following revisions to the GHG reduction levels for post-combustion CCS for reduction of CO 2 

### , and use of oxidation catalys t technology for reduction of CH 4 

### and N 2 

### O. These revisions are shown in Tables 4-1 and 4-2.Revised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 8 Table 4-1: Post Combustion CCS

GHG Emission Rate (tpy) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)

CO 2 423,513 1 423,513 90 381,162 CH 4 33 25 825 0 0 N 2 O 16 298 4,768 0 0 Total -- -- 429,106 -- 381,162
Percent GHG Reduction: 88.8%

Table 4-2: Catalytic Destruction/Oxidation

GHG Emission Rate (tpy) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)

CO 2 423,513 1 423,513 0 0 CH 4 33 25 825 40 330 N 2 O 16 298 4,768 95 4530 Total -- -- 429,106 -- 381,162
Percent GHG Reduction: 1.1%



### As shown in Tabled 4-3 and 4-4, the revisions to the GHG emission estimat es did not change the cost effectiveness estimates for removal of the selective non-catalytic re duction (SNCR) control system, and the addition of a N 2 

### O-abating selective catalytic reduction (SCR) system.

Table 4-3: Removal of SNCR GHG Emission Reduction

GHG Emission Rate (tpy) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)

CO 2 423,513 1 423,513 0 0 CH 4 33 25 825 0 0 N 2 O 16 298 4,768 100 4,768 Total -- -- 429,106 -- 4,768
Percent GHG Reduction: 1.40%

Table 4-4: Addition of N 2 O-Abating SCR System

GHG Emission Rate (tpy) GWP Uncontrolled CO 2 e (tpy) % Control Controlled CO 2 e (tpy)

CO 2 423,513 1 423,513 0 0 CH 4 33 25 3,034 0 0 N 2 O 16 298 5,879 100 5,879 Total -- -- 432,426 -- 5,879
Percent GHG Reduction: 1.40%Revised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 9 

### Table 4-5 provides the revised cost effectivenes s ranking of the technically feasible control alternatives, in order of most to least effective on a CO 2 

### e basis.

Table 4-5: GHG Control Methods Ra nked by Control Effectiveness

Control Method Previous Control Effectiveness (% reduction on a CO 2 e basis) Revised Control Effectiveness (% reduction on a CO 2 e basis)

Post Combustion CCS 88.1 88.8 Removal of NO x Control System (SNCR) 3.7 1.4

Addition of N 2 O-Abating SCR System 1.4 1.4
Catalytic Destruction 1.6 1.1 Good Boiler Design, Good Combustion Practices, and Efficient Operation / Proper Combustion Practices and Use of a Properly Designed Boiler / Utilization of Biomass Fuel Alone Baseline Baseline



### In EPA’s GHG AAQIR, EPA provided a table of recent GHG BACT determinations made at similar facilities according to the RACT/BACT/LAER Clearinghouse (RBLC), as well as other permit determinations not included in the RBL C. (See Table 5-8 of the GHG AAQIR.) Any PSD or Title V permit issued on or after Janua ry 1, 2014, which is the effective date of the amendments to the Part 98 regulations must in clude the revised GWPs and applicable emission factors in the rule. Since the permits for these determinations were issued before January 1, 2014, it is not necessary to change the informa tion regarding these BACT determinations.

Additionally, SPI proposed a GHG limit of 0.36 lb CO 2 

### e per lb steam produced. This limit is based on the total CO 2 

### e emissions expected from the proposed biomass boiler and the 275,000 pounds per hour (24 hour block aver age) steam production limit in Permit Condition X.C.3 of the PSD permit. Based on the revised calculation of total CO 2 

### e emissions, the GHG limit of 0.36 lb CO 2 

### e per lb steam produced has not changed.


## 4.4. Step 4 – Evaluate Most Effective Controls

Post Combustion CCS: EPA’s step 4 analysis for post-co mbustion CCS focused on the cost of this control alternative. GHG emissions data wa s not used here. Therefore, EPA’s evaluation and conclusion for this control alternative ha s not changed as a result of the revised GHG calculations.

Removal of NO x 

### Control System (SNCR): Revisions to the GHG emissions for removal of the SNCR system would poten tially reduce 16 tpy N 2 

### O emissions (instead of 53.4 tpy based on the previous GHG calculations). This is only 1.4 percen t of the total CO2e that is estimated to be emitted from the cogeneration project (i nstead of 3.7 percent of the total CO 2 

### e emissions basedRevised GHG Emissions Evaluation for the SPI-Anderson PSD Project April 2014 Page 10 

### on the previous GHG calculations). Additionally, this alternative would re sult in increased NO x 

### emissions (i.e., 267 tpy NO x 

### projected to be emitted from the boiler). Therefore, EPA’s previous conclusion eliminating this control option has not changed.

Catalytic Destruction/Oxidation: Revisions to the GHG emi ssions for a catalytic destruction/oxidation system would potenti ally reduce 1.1 percent of the total CO 2 

### e emissions (instead of 1.6 per cent of the total CO 2 

### e emissions based on the previous GHG calculations). This would be a reduction of 33 tpy CH 4 

### and 16 tpy N 2 

### O (instead of 144 tpy CH 4 

### and 19 tpy N 2 

### O based on the previous GHG calculations). W ith an annualized cost of approximately $2,379,713, and with CH 4 

### and N 2 

### O emissions reductions expected to be even lower, particularly in terms of CO 2 

### e, EPA still considers the constructi on and operating costs of a catalytic destruction/oxidation system to control these pol lutants to be excessive. Therefore, EPA’s previous conclusion eliminating th is control option has not changed.

Addition of N 2 

### O-Abating SCR System: Revisions to the GHG emissions for the addition of a N 2 

### O-abating SCR system would still poten tially reduce 1.4 percent of the total CO 2 

### e emissions. This estimate has not changed. However, this would be a reduction of 16 tpy N 2 

### O (instead of 19 tpy N 2 

### O based on the previous GHG calculations). W ith an annualized cost of approximately $1,276,065, and with N 2 

### O emissions expected to be even lower, EPA still considers the construction and operating cost s of the addition of a N 2 

### O-abating SCR system to control this pollutant to be excessive. Therefore, EPA’s pr evious conclusion eliminating this control option has not changed.

Good Boiler Design, Good Combustion Practices, and Efficient Operation / Proper Combustion Practices and Use of a Properly Designed Bo iler / Utilization of Biomass Fuel Alone: These control options are still consider ed the baseline level. GHG em issions data was not used in EPA’s step 4 analysis for this baseline level cont rol alternative. Therefore, EPA’s evaluation and conclusion for this control al ternative has not changed as a result of the revised GHG calculations.


## 4.5. Step 5 – Select BACT

Based on the above revisions to the GHG emissions calculations from the SPI-Anderson project, EPA has not changed its BACT determination. Speci fically, we continue to conclude that BACT for the proposed biomass-fired stoker boiler is (1) 0.36 pounds of CO 2 

### e per pound of steam (12-month rolling average basis), (2) combustion of biomass at all times except during periods of startup, shutdown and flame stabilization (in which na tural gas fuel is allowed to be combusted), and (3) energy efficient design and use of good combustion and operational and maintenance practices as described in SPI’s permit applicati on and subsequent submissions to the EPA, which include, but are not limited to, (i) construction and operation of an e fficient, state-of-the-art, aircooled, reciprocating stepgrate st oker boiler that ensu res good combustion; (ii) operation of the boiler as a cogeneration unit; and (iii) operation and maintenance of the boiler in accordance with the manufacturer’s recommendations. The CO 2 

### e limit applies at all times, including during startups and shutdowns.