UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

REGION IX 

75 Hawthorne Street 

San Francisco, CA 94105

MEMO 

SUBJECT: Revised GHG Emissions for the SPI-Anderson 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 potential (GWP) factors and certain default emission 

factors used for calculating GHG emissions. These amendments became effective on 

January 1, 2014. 

The attachment contains EPA Region 9’s updated GHG emissions calculations and other GHG 

emissions-related data for the SPI-Anderson project. 

Attachment 
Revised 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 greenhouse gases (GHGs) as an aggregate of: carbon 

dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), 

perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). (See 40 CFR § 52.21(b)(49)(i).) The 

proposed new equipment at the SPI-Anderson facility has the potential to emit only three of 

these GHGs: CO2, CH4, and N2O. 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 cooling tower will not emit any GHGs. 

EPA regulations further define CO2e as the sum of the mass emissions 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 Rule at 40 CFR Part 98. (See 40 CFR § 

52.21(b)(49)(ii).) On November 29, 2013, EPA finalized 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 specific GWP and emission factor amendments in the Part 98 

regulations that are relevant to the SPI-Anderson project are provided 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 (CO2) 1 1 

(No change)

Methane (CH4) 21 25 

Nitrous Oxide (N2O) 310 298 

Sulfur hexafluoride (SF6) 23,900 22,800 
Revised 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 

CO2 93.8 93.8 

(No change)

CH4 0.032 0.0072 

N2O 0.0042 0.0036 

Natural Gas 

CO2 53.02 53.06 

CH4 0.001 0.001 

(No change)

N2O 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 expected 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/hr. The biomass boiler will also be equipped 

with two 62.5 MMBtu/hr natural gas 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 majority 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 emergency 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 CO2e emissions from the project, and show that the proposed project has the potential 

to generate a maximum of 429,182 tons of CO2e per year (which is less than the previous 

estimate of 432,439 tons of CO2e per year in our GHG AAQIR which 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 Factor1

(Heat Input) Global 

Warming 

Potential2

GHG 

Pollutant 

Emission 

Rate 

(tpy)3

CO2e 

Emission 

Rate 

(tpy) (kg/MMBtu) (lb/MMBtu) 

Stoker 

Boiler 

CO2 93.8 206.60793 1 423,513 423,513

CH4 0.0072 0.01586 25 33 813

N2O 0.0036 0.00793 298 16 4,844

Total CO2e -- -- -- -- 429,170

Emergency 

Engine 

CO2 53.06 116.87225 1 13 13 

CH4 0.001 0.00220 25 0.00024 04

N2O 0.0001 0.00022 298 0.00002 05

Total CO2e -- -- -- -- 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/MMBtu emission factors are calculated 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. CO2e was calculated by 

multiplying each individual emission rate by the applicable GWP factor, and summing. 

4

 CO2e estimate for CH4 is less than 1 tpy. 5

 CO2e estimate for N2O 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 Emissions for Proposed New Equipment

GHG Pollutants 

Previous CO2e Emission Rate 

from November 2013 AAQIR 

(tpy) 

Revised CO2e Emission Rate 

(tpy) 

CO2 423,526 423,526 

CH4 3,034 813 

N2O 5,879 4,844 

Total 432,439 429,182 

The PSD permit limits the annual heat input from natural gas to not exceed 10 percent of the 

total heat input on an annual basis. Operation of the natural gas burners will not exceed 10 

percent of the annual heat input capacity of the boiler, or 409,968 MMBtu/yr (468 MMBtu/hr * 

8,760 hr/yr * 10%). Based on that maximum annual heat input, and the revised GWPs and 

emission factors for natural gas combustion in 40 CFR Part 98, the maximum GHG emissions 

from the natural gas burners is expected not to exceed 23,968 tons of CO2e per year (which is 

less than the previous estimate of 23,981 tons of CO2e per year in our GHG AAQIR which is 

based on the previous GWP and emission factors in 40 CFR Part 98). 

The proposed cogeneration unit will be started and shutdown as infrequently as possible. SPI 

anticipates at least one outage period each year for maintenance; any additional shutdown-andstartup cycles will be the result of an unscheduled 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 accomplish, 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 Factor6

(lb/MMBtu) 

Hourly Emission Rate7

(lb/hr) 

Event Emission Rate8

(lb/event) 

Firing 

Biomass Fuel 

CO2 206.60793 96,876 581,256 

CH4 0.01586 7 45 

N2O 0.00793 4 22 

Total CO2e -- 98,167 589,005 

Firing Natural 

Gas 

CO2 116.87225 7,305 43,827 

CH4 0.0022 0 1 

N2O 0.00022 0 0 

Total CO2e -- 7,312 43,872 

 

6

 The CH4 and N2O 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 emission 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 less than the previous estimate of 359 tons of CO2e 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

) 

CO2 55,691 668,288 334 104,181 625,083 313 

CH4 66 794 0.397 8 45 0.0227

N2O 9 104 0.0521 4 22 0.0112

Total CO2e 59,771 717,250 359 105,479 632,877 316

3. Revised GHG Emission Estimates for Existing Equipment 

Table 3-1 lists the existing equipment 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 NOx, and multiclone with ESP to 

control PM emissions 

 Equipped with one 30,400 ft3

, 2 hog fuel bins, 2 wood chip fuel bins 

Conveyance System 

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

 (1) 7,118 ft2 MAC Pulse Jet Baghouse with 300hp Blower 

 (1) 35” x 45” Rotary Airlock 

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

 (2) Each overhead storage bins 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 kilns
Revised 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 (SF6) as a dielectric medium. The existing boiler will be 

decommissioned and dismantled after the new cogeneration 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 used 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 Emissions for Existing Equipment

Emission 

Unit 

GHG 

Pollutants 

Emission Factor9

(Heat Input) Global 

Warming 

Potential 

GHG 

Pollutant 

Emission 

Rate 

(tpy) 

CO2e 

Emission 

Rate10

(tpy) (kg/MMBtu) (lb/MMBtu) 

Biomass 

Boiler 

CO2 93.8 206.60793 1 105,335 105,335

CH4 0.0072 0.01586 25 8 202

N2O 0.0036 0.00793 298 4 1,205

Total CO2e -- -- -- -- 106,742

Circuit 

Breaker 

SF6 1% leakage/year 22,800 0.000950 5

Total CO2e -- -- -- -- 5 

Table 3-3: Total Greenhouse Gas Emissions for Existing Equipment

GHG Pollutants 

Previous CO2e Emission Rate 

from GHG AAQIR 

(tpy) 

Revised CO2e Emission Rate 

(tpy) 

CO2 105,335 105,335

CH4 755 202

N2O 1,462 1,205

SF6 5 5

Total CO2e 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 SF6 emission rate for the switchgear was calculated by multiplying the SF6 capacity 

of the existing breaker and two switches (190 lb) by the 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. CO2e was calculated by multiplying each individual 

emission rate by the applicable GWP factor, and summing them to obtain the total CO2e 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 process involves that ranking available 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 economic impacts justify a conclusion that the most 

stringent technology is not achievable for the case at hand. If the 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 contains 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 emergency 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-down BACT analysis and BACT determination for 

this unit has not changed as a result of the revised 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 provided in the following sections. 

4.1. Step 1 – Identify Available 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 Technically 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 CO2, and use of oxidation catalyst technology for reduction of CH4 and N2O. 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 CO2e(tpy) % Control Controlled CO2e(tpy)

CO2 423,513 1 423,513 90 381,162

CH4 33 25 825 0 0

N2O 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 CO2e(tpy) % Control Controlled CO2e(tpy)

CO2 423,513 1 423,513 0 0 

CH4 33 25 825 40 330 

N2O 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 estimates did not change the 

cost effectiveness estimates for removal of the selective non-catalytic reduction (SNCR) control 

system, and the addition of a N2O-abating selective catalytic reduction (SCR) system. 

Table 4-3: Removal of SNCR GHG Emission Reduction 

GHG Emission Rate

(tpy) GWP Uncontrolled CO2e(tpy) % Control Controlled CO2e(tpy)

CO2 423,513 1 423,513 0 0

CH4 33 25 825 0 0

N2O 16 298 4,768 100 4,768 

Total -- -- 429,106 -- 4,768 

Percent GHG Reduction: 1.40% 

Table 4-4: Addition of N2O-Abating SCR System 

GHG Emission Rate

(tpy) GWP Uncontrolled CO2e(tpy) % Control Controlled CO2e(tpy)

CO2 423,513 1 423,513 0 0 

CH4 33 25 3,034 0 0 

N2O 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 effectiveness ranking of the technically feasible control 

alternatives, in order of most to least effective on a CO2e basis. 

Table 4-5: GHG Control Methods Ranked by Control Effectiveness 

Control Method 

Previous Control 

Effectiveness 

(% reduction on a CO2e basis) 

Revised Control 

Effectiveness 

(% reduction on a CO2e 

basis) 

Post Combustion CCS 88.1 88.8

Removal of NOx Control System 

(SNCR) 3.7 1.4 

Addition of N2O-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 RBLC. (See Table 5-8 of the GHG AAQIR.) Any 

PSD or Title V permit issued on or after January 1, 2014, which is the effective date of the 

amendments to the Part 98 regulations must include 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 information regarding these BACT determinations. 

Additionally, SPI proposed a GHG limit of 0.36 lb CO2e per lb steam produced. This limit is 

based on the total CO2e emissions expected from the proposed biomass boiler and the 275,000 

pounds per hour (24 hour block average) steam production limit in Permit Condition X.C.3 of the 

PSD permit. Based on the revised calculation of total CO2e emissions, the GHG limit of 0.36 lb 

CO2e 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-combustion CCS focused on the cost of 

this control alternative. GHG emissions data was not used here. Therefore, EPA’s evaluation 

and conclusion for this control alternative has not changed as a result of the revised GHG 

calculations.

Removal of NOx Control System (SNCR): Revisions to the GHG emissions for removal of the 

SNCR system would potentially reduce 16 tpy N2O emissions (instead of 53.4 tpy based on the 

previous GHG calculations). This is only 1.4 percent of the total CO2e that is estimated to be 

emitted from the cogeneration project (instead of 3.7 percent of the total CO2e emissions based 
Revised GHG Emissions Evaluation for the SPI-Anderson PSD Project 

April 2014 

Page 10 

on the previous GHG calculations). Additionally, this alternative would result in increased NOx

emissions (i.e., 267 tpy NOx 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 emissions for a catalytic 

destruction/oxidation system would potentially reduce 1.1 percent of the total CO2e emissions 

(instead of 1.6 percent of the total CO2e emissions based on the previous GHG calculations). 

This would be a reduction of 33 tpy CH4 and 16 tpy N2O (instead of 144 tpy CH4 and 19 tpy 

N2O based on the previous GHG calculations). With an annualized cost of approximately 

$2,379,713, and with CH4 and N2O emissions reductions expected to be even lower, particularly 

in terms of CO2e, EPA still considers the construction and operating costs of a catalytic 

destruction/oxidation system to control these pollutants to be excessive. Therefore, EPA’s 

previous conclusion eliminating this control option has not changed.

Addition of N2O-Abating SCR System: Revisions to the GHG emissions for the addition of a 

N2O-abating SCR system would still potentially reduce 1.4 percent of the total CO2e emissions. 

This estimate has not changed. However, this would be a reduction of 16 tpy N2O (instead of 19 

tpy N2O based on the previous GHG calculations). With an annualized cost of approximately 

$1,276,065, and with N2O emissions expected to be even lower, EPA still considers the 

construction and operating costs of the addition of a N2O-abating SCR system to control this 

pollutant to be excessive. Therefore, EPA’s previous 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 Boiler / Utilization of Biomass Fuel Alone: These 

control options are still considered the baseline level. GHG emissions data was not used in 

EPA’s step 4 analysis for this baseline level control alternative. Therefore, EPA’s evaluation and 

conclusion for this control alternative 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. Specifically, we continue to conclude that BACT 

for the proposed biomass-fired stoker boiler is (1) 0.36 pounds of CO2e 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 natural 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 application and subsequent submissions to the EPA, which 

include, but are not limited to, (i) construction and operation of an efficient, state-of-the-art, aircooled, reciprocating stepgrate stoker boiler that ensures 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 CO2e limit applies at all times, including during 

startups and shutdowns.