technical support document draft/proposed ......technical support document, permit action number:...

Technical Support Document, Permit Action Number: 01300098-002 Page 1 of 29 Date: 12/10/2013

TECHNICAL SUPPORT DOCUMENT

For

DRAFT/PROPOSED AIR EMISSION PERMIT NO. 01300098-002

This technical support document (TSD) is intended for all parties interested in the draft/proposed permit

and to meet the requirements that have been set forth by the federal and state regulations (40 CFR §

70.7(a)(5) and Minn. R. 7007.0850, subp. 1). The purpose of this document is to provide the legal and

factual justification for each applicable requirement or policy decision considered in the preliminary

determination to issue the draft/proposed permit.

1. General Information

1.1 Applicant and Stationary Source Location:

Table 1. Applicant and Source Address

Applicant/Address Stationary Source/Address

(SIC Code: 4911)

Mankato Energy Center, LLC

c/o Calpine Corporation

717 Texas Avenue, Suite 1000

Houston, TX 77022

Mankato Energy Center

1 Fazio Lane

Mankato

Blue Earth County

Contact: Ms. Heidi Whidden

Director, Environmental Health & Safety,

Southeast Region

Phone: 713-570-4829

Fax: 713-830-8871

1.2 Facility Description

Mankato Energy Center, L.L.C. (Permittee) is a 375 megawatt electric generating plant (facility). The

Permittee operates a Siemens-Westinghouse combined cycle combustion turbine generator (CTG) fired

primarily by natural gas, with #2 fuel oil as a back-up fuel. The CTG has a heat recovery steam generator

(HRSG) and a natural gas-fired duct burner to supply steam to a steam turbine electric generator. The

facility was permitted to construct and operate two identical CTGs, but only one CTG was built.

Construction commenced in October 2004, and startup occurred in May 2006.

The facility also has an auxiliary boiler, a fire pump engine, a fuel oil storage tank for the CTG, a fuel oil

storage tank for the fire pump, and a cooling tower.

The facility is subject to the requirements of federal Prevention of Significant Deterioration (PSD) at 40

CFR Section 52.21 for PM, PM10, SO2, NOX, CO, VOC, and H2SO4. At the time of permit issuance in 2004,

PM10 was used as a surrogate for PM2.5 emissions as allowed under the (now-rescinded) Grandfathering

provision at § 52.21(i)(1)(xi). The facility uses Best Available Control Technology (BACT) to control

emissions. The facility is also subject to hazardous air pollutant (HAP) limits to avoid being a major source

under Section 63.2.


1.3 Description of the Activities Allowed by this Permit Action

This permit is a reissuance of the total facility operating permit that incorporates changes to CTG startup

and shutdown limits, revisions to stack testing requirements, and several additional changes.

1.4 Description of Notifications and Applications Included in this Action

Table 2. Notifications and Applications Included in this Action

Date Received DQ# Application/Notification Type and Description

02/23/2007 1407 Major amendment to revise CTG SUSD limits

03/17/2009 2500 Total Facility Operating Permit Reissuance

12/18/2009 2935 MPCA-initiated CEMs certification re-opening

03/22/2011 3440 Administrative amendment for test deadline extension

04/19/2012 3882

Major amendment to remove CTG power augmentation

limits and requirements (power augmentation was never

constructed) and revise HAPs testing requirements

This permit was originally a major amendment (DQ 1407) to revise CTG startup and shutdown BACT limits.

However, several additional applications for additional permit changes, and operating permit reissuance

were also received from the Permittee during the permitting process, and are incorporated in this permit

action.

DQ 1407: This is an application for a major amendment to revise the startup and shutdown (SUSD) limits

for the CTG (EU 002).

The initial construction and operation permit (No. 01300098-001) for this facility was a federal PSD

permit. PSD permits require BACT for pollutants subject to PSD. When BACT is required, BACT limits must

be established for all operating modes including startup and shutdown (SUSD). BACT limits for SUSD can

be different than BACT for normal operation. In the original PSD permit, SUSD BACT was expressed as

minutes-per-event limits. This permit replaces those limits with pounds-per-event limits and 12-month

rolling sum limits.

Revised modeling was submitted for CO and NOX to account for the revised CO and NOX SUSD BACT limits.

Based on the modeling, a total facility Tier 1 requirement for CO and Tier 2 requirements for NO2 were

added to the permit.

The PM and PM10 BACT limits for normal operation were revised to indicate they apply to both normal

operations and startup, shutdown, and malfunction. A SUSD BACT analysis submitted by the Permittee

indicates PM and PM10 SUSD emissions would be less than PM and PM10 emissions during normal

operations. Because SV 002 PM10 SUSD emissions and limits did not change as part of the SUSD BACT

analysis, inclusion of PM2.5 as a stand-alone pollutant was not triggered by the SUSD BACT re-evaluation.

DQ 2500: This application is for reissuance of the part 70 operating permit.

DQ 3440: This application is for an administrative amendment to change the repeat testing deadline from

July 13th

to September 30th

. Although this type of test deadline change can not be made by an

administrative amendment (only a one-time extension of the deadline can be made by an administrative

amendment, with all future test deadlines remaining the same as the original month/day deadline) this


permanent change to the test deadline can be made as part of a major amendment/operating permit re-

issuance.

DQ 3882: This application is a major amendment to remove power augmentation requirements and revise

HAP testing requirements.

Power augmentation was never installed so BACT emission limits applicable during power augmentation

were removed.

This application also requested elimination of low and reduced load formaldehyde and n-hexane testing

so that testing formaldehyde and n-hexane testing is required only at full load (90% - 100% of maximum

capacity). MPCA staff determined that testing for formaldehyde at low (


• The permit was restructed to reflect the construction of only one of the two combined cycle combustion turbines.

• Removal of EU 006 emergency generator requirements because the generator was not installed. • Compliance Assurance Monitoring requirements have been added (refer to Table 12) • The acid rain program compliance certification report requirement was removed because EPA no

longer requires the report.

• Clean Unit requirements were removed from the permit because the U. S. Court of Appeals for the D. C. Circuit vacated these provisions in 2005 and EPA removed these provisions from 40 CFR §

52.21(x) in 2007.

• Requirements for the Clean Air Interstate Rule (CAIR) were removed because Minnesota is no longer subject to CAIR.

Total Facility Updates

• A requirement was added regarding permit appendices which states that the Permittee shall comply with all requirements contained in the appendices.

• Title I Conditions were added requiring documentation of determinations made regarding the reasonable possibility of a significant emissions increase under 40 CFR § 52.21(r)(6).

• Updated language regarding limits set as a result of a performance test.

• A requirement to retain records of calculations documenting changes at the facility which do not require an amendment or a notification was added.

EU 001 Combustion Turbine #1 - Never Constructed

• Removed all requirements

EU 002 Combustion Turbine #2 (formerly GP 001 Combustion Turbines #1 and #2)

• Added Minn. R. 7011.2350 citation to all NSPS subpart GG citations

• Removed “Notification of the Date Construction Began”

• Removed “Notification of the Actual Date of Initial Startup”

EU 003 Duct Burner #1 - Never Constructed

• Removed all requirements

EU 004 Duct Burner #2 (formerly GP 002 Duct Burners)

• Added Minn. R. 7011.0560 citation to all NSPS subpart Da citations



• Revised applicable NSPS subp. Da requirements due to changes made in subp. Da since issuance of PER 001:

� Removed PM and opacity limits that no longer apply (§ 60.42Da(f)(1)) because only pipeline natural gas is combusted by EU 004 with a maximum 0.8 grains sulfur/100 scf

(approximately equivalent to 0.0022 lb/mmBtu at 1020 Btu/scf), and no SO2 post-

combustion control is used

� Revised NOX compliance citations; compliance requirements now listed at § 60.48Da instead of § 60.46Da

EU 005 Auxiliary Boiler




• Removed “Initial Performance Test”

• Removed “Testing Frequency Plan”

• Revised performance testing requirements – NOX testing was added at 60 month intervals, based on the 2006 and 2011 testing results and MPCA guidance, and the CO testing requirement was

removed, also based on the 2006 and 2011 test results (0.001 lb/mmBtu and 0.004 lb/mmBtu

compared to a limit of 0.06 lb/mmBtu)

EU 006 Emergency Generator - Never Constructed

• Removed all requirements.

EU 007 Fire Pump Engine

• Added applicable pt. 63, subp. ZZZZ requirements

SV 002 Combustion Turbine #2 & Duct Burners #2 Stack

• Removed “Testing Frequency Plan”

• Revised and/or added performance testing requirements for PM, PM10, PM2.5, VOC, n-hexane, and formaldehyde. The Permittee combusts very little distillate oil, and to avoid combusting distillate

oil only for the purpose of testing, testing on oil is only required if EU 002 combusted oil for more

than 50 hours in an 12-month period since the previous PM/PM10/PM2.5/VOC testing was

conducted (regardless of the fuel type(s) combusted during the previous tests).

• Added requirements from GP 003, (which was deleted,) and changed all of the language to refer to a single CTG/DB system.

• CEMS testing and results summaries were updated and moved to MR 003 for NOX CEMS and MR 004 for CO CEMS.

Facility Description Updates

• Information for buildings BG001-BG013 was added.

• TK001 & TK002 storage capacity was revised to reflect “as-built” specifications.

• CEMS information was added after the certification tests were completed and submitted. A reopening, DQ 2935 was initiated and incorporated.

2. Regulatory and/or Statutory Basis

New Source Review/Prevention of Significant Deterioration

The facility is an existing major source under New Source Review regulations. The changes authorized in

this permit action do not change that status. This permit action did trigger a PSD permit action because

the change in SUSD BACT limits was viewed as a relaxation and required review of environmental and

technological factors required under the PSD permit program.

As of January 2, 2010, the United States Environmental Protection Agency (USEPA) began regulating

Greenhouse Gases (GHGs) in terms of carbon dioxide equivalents, or CO2e. As implied by the name, the

pollutant Greenhouse Gases is not a single chemical, but a combination of chemicals. Some chemicals

have a larger global warming impact than others. To account for this, each chemical is assigned a


weighting factor referred to as a ‘global warming potential’. These global warming potentials are defined

by the US EPA at 40 CFR pt. 98, Appendix A, Table 1.

GHG emissions are quantified in two steps. First, the potential emissions of each chemical in 40 CFR pt. 98,

Appendix A, Table 1 that is emitted by the source is multiplied by the respective global warming potential;

Second, the result of each calculation in step 1 is summed to determine the facility CO2e.

This facility is a major source of Greenhouse Gases but the changes authorized by this permit action do

not make GHGs “subject to regulation” as defined at 40 CFR Section 52.21(b)(49).

Part 70 Permit Program

The facility is a major source under the Part 70 permit program. That status does not change with this

permit action.

New Source Performance Standards (NSPS)

Several portions of the facility are subject to NSPS. That status does not change with this permit action.

National Emission Standards for Hazardous Air Pollutants (NESHAP)

The facility has accepted limits on HAP emissions to qualify as an area source under 40 CFR pt. 63. Thus,

no major source NESHAPs apply. That status does not change with this permit action.

However, the fire pump engine EU 007 is subject to 40 CFR pt. 63, subp. ZZZZ, which applies to both major

and area HAP sources. EU 005 is a gas-fired boiler as defined at § 63.11237, and is not subject to pt. 63,

subp. JJJJJJ as indicated at § 63.1119(e).

Compliance Assurance Monitoring (CAM)

The combined cycle gas turbine (EU 002/EU 004/SV 002) is subject to CAM for NOX, CO, and VOC. The

Permittee uses the NOX and CO CEMS for CAM for these pollutants. For VOC, the CO CEMS is used as an

indicator of VOC compliance based on VOC stack test data and CO CEMS data. NG-fired gas turbine VOC

test and CO CEMS data from another SW501F gas turbine at the Calpine-Morgan Energy Center in

Decatur, Alabama were used for evaluating the VOC/CO relationship for operations at less than base load.

All three CAM plans are attached to this TSD (Attachment 8), as well as the VOC to CO relationship data

(Attachment 9). Refer to Table 12 for discussion of CAM requirements.

Clean Air Interstate Rule (CAIR) and Cross State Air Pollution Rule (CSAPR)

The CAIR rule was promulgated in 2005 and remanded to EPA by the U.S Court of Appeals for the District

of Columbia Circuit in July, 2008. A December 2008 court decision kept the requirements of CAIR in place

temporarily but directed EPA to issue a new rule to implement Clean Air Act requirements concerning the

transport of air pollution across state boundaries. CAIR was administratively stayed on December 3, 2009

(74 FR 56721) in Minnesota by EPA. The stay of CAIR in Minnesota required sources to hold NOX

allowances equivalent to their initial allocation. EPA was to deduct and terminate these allowances. The

CAMD records now show that zero CAIR NOX allowances are held by Minnesota sources, as allowances

have been deducted for program termination.

On August 8, 2011 EPA published in the Federal Register (76 FR 48208) the final Cross State Air Pollution

Rule (CSAPR), also called the Transport Rule, to replace CAIR and limit interstate transport of NOX and SO2 emissions that contribute to harmful levels of fine particulate matter and ozone in downwind states. The

final CSAPR rule was to take effect on January 1, 2012. The U.S. Court of Appeals for the District of


Columbia Circuit issued on December 30, 2011, an order to temporarily stay CSAPR pending the Court’s

resolution of petitions challenging the rule. On August 21, 2012, the Court issued a decision vacating

CSAPR, ruling that EPA exceeded its statutory authority in promulgating the rule. The court directed EPA

to continue administering CAIR “pending the promulgation of a valid replacement.” On November 19,

2012, EPA issued a memorandum outlining next steps for pending actions affected by the CSAPR vacatur,

while noting that it has filed a petition for rehearing of the decision.

The stay of CAIR in Minnesota continues to be in effect and therefore, no CAIR or CSAPR applicable

requirements remain for this facility, at this time.

Environmental Review & AERA

This permit action does not require an Environmental Assessment Worksheet (EAW,) or an Air Emissions

Risk Analysis (AERA).

Minnesota State Rules

Portions of the facility are subject to the Minnesota Standards of Performance. This status does not

change with this permit action. However, Minnesota rule citations that incorporate NSPS have been

added to the permit by this permit action.

• Minn. R. 7011.0560 Incorporation of New Source Performance Standards by Reference (40 CFR pt. 60, subp. Da: Standards of Performance for Electric Utility Steam Generating Units for Which

Construction is Commenced After September 18, 1978)

• Minn. R. 7011.0570 Incorporation of New Source Performance Standards by Reference (40 CFR pt. 60, subp. Dc: Standards of Performance for Small Industrial-Commercial-Institutional Steam

Generating Units)

• Minn. R. 7011.2300 Standards of Performance for Stationary Internal Combustion Engines

• Minn. R. 7011.2350 Standards of Performance for New Stationary Gas Turbines (Incorporation of 40 CFR pt. 60, subp. GG: Standards of Performance for Stationary Gas Turbines)

Table 5. Regulatory Overview of Units Affected by the Modification/Permit Amendment

Subject

Item*

Applicable Regulations Comments:

Total Facility 40 CFR §§ 72.9(b) & (c) Removed the Acid Rain Compliance Certification Report no

longer required by EPA .

SV 002 40 CFR § 52.21

Minn. R. 7017.2020,

subp. 1

Revised startup and shutdown BACT limits.

Removed original requirement for testing frequency plan (TFP)

submittal. Added performance test requirements according to

submitted and approved TFPs, added requirements for future

formaldehyde test frequency, and provisions for submittal of a

formaldehyde test frequency plan.

EU 002

(previously

GP 001)

Minn. R. 7011.2350 Added Minnesota rule citation to federal citation.


Subject

Item*

Applicable Regulations Comments:

EU 004

(previously

GP002)

Minn. R. 7011.0560 Added Minnesota rule citation to federal citation.

SV 002

(previously

GP 003)

40 CFR §§ 52.21(x)(3)(ii)

and (x)(6)(i)

Removed Clean Unit Designations requirements.

SV 002

(previously

GP 003)

Title I Condition: 40 CFR §

52.21(j) BACT Limit

Startup and shutdown limits were revised from 12-month

rolling sum operating hour limits to ton per year and hours per

event limits.

EU 001 Removed all requirements. CTG not installed

EU 002 40 CFR §§ 60.7(a)(1) and

(a)(3)

Removed completed requirements.

EU 003 Removed all requirements. Duct burner not installed

EU 004 40 CFR §§ 60.7(a)(1) and

(a)(3)

Removed completed requirements.

EU 005 40 CFR § 52.21(j) Added Minnesota rule citation to federal citation.

EU 006 40 CFR § 52.21(j) Removed all requirements. Generator never installed.

EU 007 40 CFR § 52.21(j); 40 CFR

pt. 63, subp. ZZZZ

Added Minnesota rule citation to federal citation. Added pt.

63, subp. ZZZZ requirements

FS 001 40 CFR § 52.21(j) Added Minnesota rule citation

3. Technical Information

3.1 Startup/Shutdown PSD BACT Limits Revisions

The current permit action (No. 01300098-002) replaces the Permit No. 01300098-001 startup and

shutdown duration BACT limits (expressed as minutes per startup and shutdown event) with short-term

NOX, CO, and VOC lb/event emission limits (refer to Table 6b) and long-term NOX, CO, and VOC SUSD tpy

emission limits (refer to Table 6c). The Permittee submitted a revised SUSD BACT analysis demonstrating

the existing NOX, CO, and VOC controls are BACT for SUSD operations.

To establish the lb/event and 12-month rolling sum limits, the Permittee furnished MPCA staff with the

number of anticipated SUSD events and event length data shown in Table 6a, and NOX and CO CEMS data

for determining the appropriate lb/event and ton-per-year 12-month rolling sum SUSD CO, NOX, and VOC

limits (see limits in Tables 6b and 6c, respectively).


Table 6a. Number of Start-up and Shutdown Events

FUEL Number of Events

per year Event Length (hours) Total Hours per year

Natural

Gas

Cold SU 46.0 3.5 161

Warm SU 184.0 2.5 460

SD 230.0 0.5 115

736 SUSD hours on NG

Distillate

Oil

Cold SU 6.0 3.5 21

Warm SU 24.0 2.5 60

SD 30.0 0.5 15

96 SUSD hours on distillate oil

TOTAL

832

The Table 6b short-term limits for start-up and shut-down operations were determined through MPCA

staff analysis of the Permittee’s CEMS data and discussions with the Permittee.

Table 6b. Short-term Startup and Shutdown Permit Limits, lb/event

Pollutant Fuel* Cold SU lb/event Warm SU lb/event SD lb/event

NOX Natural gas 323.5 148.3 4.4

Fuel oil 459.3 140.7 16.8

CO Natural gas 5387.6 3068.6 46.8

Fuel oil 1498.2 545.9 309.3

VOC** Natural gas 2693.8 1534.3 23.4

Fuel oil 749.1 272.9 154.7

*“Fuel oil” refers to when EU 002 combusts distillate fuel oil but initially starts up on natural gas and switches over to distillate fuel oil as described below in Section 3.1. **VOC values are one half of the respective CO values, as proposed by the Permittee.

The Table 6c ton-per-year (12-month rolling sum) values were calculated from the annual number of

events shown in Table 6a, and the corresponding lb/event limits in Table 6b.

Table 6c. Long-term Startup and Shutdown Permit Limits, ton/year

(12-Month Rolling Sum)

Pollutant Fuel Cold SU tpy Warm SU tpy SD tpy

NOx Natural gas 7.44 13.64 0.50

Fuel oil 1.38 1.69 0.25

CO Natural gas 123.92 282.31 5.39

Fuel oil 4.49 6.55 4.64

VOC* Natural gas 61.96 141.15 2.69

Fuel oil 2.25 3.28 2.32

* VOC values are one half of the respective CO values, as proposed by the Permittee.

Refer to Attachment 5 for more information regarding derivation of the SUSD limits, and Attachment 6 for

the revised BACT analysis demonstrating the current air pollution controls still comprise BACT for NOX, CO,

and VOC emissions from startup and shutdown operation.


CTG Distillate Fuel Oil Startup and Shutdown Processes: When EU 002 starts up with distillate fuel oil, EU

002 is actually initially fired with natural gas. When EU 002 attains approximately 30 MW output on

natural gas, EU 002 operating level is maintained at the 30 MW level while combustion is transferred to a

set of oil combustors. Once the transfer is complete, the startup process continues on distillate fuel oil.

The oil-fired shutdown process is the reverse of the startup procedure; there is a comparable hold and

fuel switch step – from distillate fuel oil to natural gas – before combustion ceases.

For the purposes of this permit and TSD, ‘fuel oil/distillate fuel oil/oil startup’ refers to the process of

initial startup on natural gas with a switchover to fuel oil as described above, and fuel oil/distillate fuel

oil/oil shutdown’ refers to the process of shutting down on fuel oil with a switch to natural gas as

described above.

3.2 PSD Modeling and Additional Impacts Analysis

a. The conversion of the original (permit no. 01300098-001) SV 002 PSD startup and shutdown time length limits to lb/event and 12-month rolling tpy limits triggered the need to revise the facility

PSD modeling. The revised modeling results showed the facility would not cause or contribute to

the exceedence of any NAAQS or MAAQS.

The worst case short-term SV 002 CO and NOX emissions profiles are complicated due to varying

lengths of startup, and the impact of the startup process on CO and NOX emissions. The worst

case 1-hour emission rates exceed the permitted worst case average hourly emission rate

(associated with startup and shutdown; refer to Table 7 below). To determine appropriate NOX

and CO emission rates for modeling impacts for the 1-hour NO2, 1-hour CO, and 8-hour CO

ambient air standards, MPCA staff analyzed actual startup emissions determined by CEMS to

determine emission rates for modeling for these ambient air standards. Table 7 shows the

modeled emission rates, and the permitted maximum average lb/hr emission rates for

comparative purposes. Annual NOX was modeled at the same g/s emission rate as the 1-hr NOX

presumably for simplicity (modeling results for the annual federal and Minnesota NOX ambient air

standards are only 32% of the standard when using the 1-hour modeling SV 002 g/s emission

rate).

Table 7. Permitted Maximum and Modeled SV 002 NOX and CO Emission Rates

Pollutant Fuel

cold

startup

average

lb/hr1

warm

startup

average

lb/hr2

shutdown

lb/hr3

Worst Case

non-SUSD

lb/hr

Modeled

Emission

Rate

lb/hr

Modeled

Emission

Rate

g/s

NOX Natural Gas 92.4 59.3 20.3 31.9 235.55 29.68

NOX Fuel Oil 131.2 56.3 45.7 57.9

CO Natural Gas 1539.3 1227.4 59.7 25.9 3771 1-hr 475.14 1-hr

CO Fuel Oil 428.1 218.4 324.4 30.2 1215.9 8-hr 153.21 8-hr 1Determined with lb/event limit over the 3.5 hour event duration; worst case 1-hr emission rate is higher

2Determined with lb/event limit over the 2.5 hour event duration; worst case 1-hr emission rate is higher

3Determined with lb/event limit over the 0.5 hour event duration plus 0.5 hours of worst-case normal operation


Table 8. Air Dispersion Modeling Results for Mankato Energy Center- NAAQS/MAAQS

Pollutant Averaging

Time

Modeled

Impacts

(μg/m3)

Background

Value

(μg/m3)

Total

Predicted

Impacts

(μg/m3)

NAAQS

(MAAQS)

(μg/m3)

% of

NAAQS

(MAAQS)

MPCA Modeling

Language Tier

Recommendations

NOx 1-hr 95.42 62 157.42 188 83.73%

Tier 2 Annual 22.89 9 31.89 100 31.89%

CO 1-hr 1,838.23 575.00 2,413.23

40,000

(35,000)

6.03%

(6.9%) Tier 1

8-hr 498.08 345 843.08 10,000 8.43%

Emissions were modeled in accordance with 40 CFR § 52.21 to determine compliance with the 1-

hour and annual NO2 ambient air standards, and the 1-hour and 8-hour CO ambient air standards.

The modeling report was approved by MPCA staff on September 22, 2011, although 1-hour CO

modeling was revised in October 2013 using an adjusted 1-hour CO emission rate. The results of

the modeling prompted the addition of Tier 2 NO2 and Tier 1 CO requirements to the total facility

portion of the permit (refer to Table 8). Refer to Attachment 4 for additional information

regarding MPCA review of the modeling results.

The modeled SV 002 NOX and CO emission rates were not included as NAAQS-based permit limits

because the worst case emission rates were used in modeling.

The Permittee also conducted an assessment of PM2.5 impacts as required by MPCA staff. The

Permittee used the original facility PM10 modeling (circa 2003 for the construction/part 70 permit

No. 01300098-001) and assumed all PM10 was PM2.5. Based on this assumption, PM2.5 impacts

were below the 24-hour and annual PM2.5 NAAAQS.

b. The Additional Impacts Analysis from the original (circa 2003) permit application was reviewed to determine if it is still valid. This analysis included a growth analysis, soils and vegetation analysis,

water usage and quality analysis, and a visibility analysis.

The Permittee was authorized by the 2004 permit to construct two combined cycle stationary gas

turbines with duct burners, an auxiliary boiler, an emergency generator, and a fire pump engine.

One of the gas turbine/duct burner units was not constructed, as well as the emergency

generator. As a result, the impacts identified by the additional impacts analyses have been

reduced or stayed the same, and the original analyses are still valid.

3.3 Environmental Justice, Endangered Species Act, and National Historic Preservation Act Requirements

Environmental Justice (EJ)

Environmental Justice is the fair treatment and meaningful involvement of all people regardless of race,

color, national origin, or income with respect to the development, implementation, and enforcement of

environmental laws, regulations, and policies. EPA has this goal for all communities and persons across

the U.S.A. It will be achieved when everyone enjoys the same degree of protection from environmental

and health hazards and equal access to the decision-making process to have a healthy environment in

which to live, learn, and work.

As part of the PSD permitting process, the MPCA contacts US E.P.A. Region 5 staff to verify if there are any

possible EJ issues for facility location that need to be addressed in the permit action. For this project,


MPCA staff contacted EPA Region 5 staff who used the draft Environmental Justice Strategic Enforcement

Assessment Tool (EJSEAT) that identified the facility location as potentially having EJ concerns. Additional

review by the MPCA revealed no negative comments for the existing permit (No. 01300098-001 issued

September 29, 2004) and a history of no complaints for this facility. Therefore, additional action regarding

EJ is not warranted at this time.

Endangered Species Act (ESA)

EPA made a determination on December 8, 2008, that the SUSD limits changes did not generate any

Endangered Species Act concerns. See Attachment 3.

National Historic Preservation Act (NHPA)

3.4 Performance Testing

SV 002 Formaldehyde and n-Hexane:

This permit action revises the formaldehyde and n-hexane testing requirements. Determination of the

requirements (for testing conditions and frequency) for these two HAPs was done using the following:

A. Minnesota Rules for performance testing and “worst-case conditions” B. Variability of emissions C. Existing guidance on testing frequency D. Actual formaldehyde emissions for calendar years 2010-2012 E. Actual distillate fuel oil use at the Facility

The Permittee submitted justification for reduced frequency formaldehyde testing, (i.e., testing only at full

load instead of at startup, less than full load, and full load) multiple times with the most recent and robust

discussion received March 6, 2013. The Permittee argues the bases for the request were primarily low

variability between loads, based on the September 2011 tests, and low actual usage of fuel oil at the

facility.

However, MPCA staff review of past formaldehyde performance test data from 2006 and 2011 revealed

wide variability between different loads, different runs at the same load, and between the averages of the

test results. The greatest variability was while combusting natural gas in the 60-90% load range (which is

the operating mode with the most operating hours), which exhibited a 224% increase from 2006 to 2011

on a ppmv basis (refer to Table 10).

Current MPCA guidance indicates formaldehyde testing should be conducted annually for all loads for

both fuels.

Formaldehyde and n-Hexane Testing While Combusting Distillate Fuel Oil: Testing for formaldehyde and n-

hexane while combusting fuel oil was removed from the permit based on the following:

1. Actual EU 002 hours combusting fuel oil are extremely low; 2. The cost to combust fuel oil in EU 002 is very high, and currently EU 002 combusts fuel oil solely

for testing purposes;

3. Actual single and total HAP emissions are well below the 9.0 tpy and 22.5 tpy limits, respectively; and,


4. Formaldehyde and n-hexane emissions from fuel oil combustion for all operating loads will be calculated using the highest one-hour test run lb/hr value measured for each pollutant from the

2011 testing.

Formaldehyde and n-Hexane Testing While Combusting Natural Gas: The permit imposes formaldehyde

emission factor verification testing while combusting natural gas at thirty month intervals and n-hexane

testing at 60 month intervals. This allows every other formaldehyde test to coincide with required PM,

PM10, PM2.5, VOC, and n-hexane tests. This formaldehyde test interval is less frequent than annual testing

suggested by test frequency guidance, but is acceptable due to actual SV 002 formaldehyde emissions

averaging 1.80 tpy for the 2010-2012 period. The permit also provides the option of SV 002 formaldehyde

testing while EU 002 combusts natural gas, at 60-month intervals. This option may be used providing the

Permittee agrees to use the maximum one-hour formaldehyde emission rate measured during a single

test run of any of the three tested operating loads, for calculating actual SV 002 formaldehyde emissions

from natural gas combustion.

Table 9. SV 002 Natural Gas Formaldehyde Testing Results

July 2006 September 2011

Run 1 Run 2 Run 3 Average Run 1 Run 2 Run 3 Average

Operating Load 20% 16%

Load (MW) 35.2 35.2 35.2 35.2 30.2 30.2 30.1 30.2

Fuel Flow Rate

(MMBtu/hr) 754.73 752.7 749.21 752.21 740.52 756.26 770.47 755.75

T (˚F) 87 87 85 86 55 58 60 58

Humidity (lb/lb air) 0.0225 0.0225 0.0183 0.021 0.0066 0.0069 0.0065 0.007

HCHO (lbs/hr) 1.38 1.26 1.26 1.30 1.3 1.43 2.15 1.63

HCHO (ppmv) 0.5 0.47 0.49 0.49 0.55 0.61 0.92 0.69

Operating Load 65% 68%

Load (MW) 103.1 110.3 110.4 107.9 125.4 125.4 125.4 125.4

Fuel Flow Rate

(MMBtu/hr) 1198.55 1251.72 1251.22 1233.83 1407.48 1422.85 1436.56 1422.30

T (˚F) 85 80 77 81 65 68 68 67


HCHO (lbs/hr) 0.44 0.46 0.46 0.45 2.12 1.33 1.77 1.74

HCHO (ppmv) 0.17 0.17 0.17 0.17 0.67 0.42 0.57 0.55

Operating Load Base load (w/DB) Base load (w/DB)

Load (MW) 170.3 164.8 164.1 166.4 186.9 183.5 181.5 184.0

Fuel Flow Rate

(MMBtu/hr) 1805.7 1758.38 1735.52 1766.53 2409.15 2446.3 2449.56 2435.00

T (˚F) 81 85 85 84 50 55 57 54


HCHO (lbs/hr) 0.41 1.27 0.40 0.69 2.54 0.93 0.96 1.48

HCHO (ppmv) 0.12 0.38 0.12 0.21 0.62 0.23 0.23 0.36

Table 10. Change in HCHO Concentration From 2006 to 2011 Testing (Natural Gas)

Load Range 2006 ppmv, avg. 2011 ppmv, avg. % change

15-30% 0.49 0.69 41%

60-70% 0.17 0.55 224%

Base load 0.21 0.36 71%

Testing for n-hexane emission factor verification while combusting natural gas is at 60-month intervals

based on the results of the 2006 and 2011 tests that were very consistent for all three runs for each

test.

EU 005 NOX and CO Testing Frequency – EU 005 NOX and CO emissions were tested in 2006 and 2011.

CO test results were very low (0.001 lb/mmBtu and 0.004 lb/mmBtu in 2006 and 2011, respectively,

compared to a limit of 0.06 lb/mmBtu), and therefore, no future CO testing is warranted at this time.

For NOX, even though test frequency guidance suggests testing at 36 month intervals (because 2006 and

2011 test results were in the 60% -

Table 11: Permitted Normal and Startup-Shutdown Operating Hours

Fuel Type

Annual Total

Operating

Hours

Annual Normal

Operating Hours

Annual SUSD

Operating Hours

Total Hours Combusting Natural Gas1 7885 7149 736

Total Hours Combusting Distillate Oil 875 779 96

Total 8760 7928 832 1Note that natural gas is only ‘limited’ by the number of hours of EU 002 fuel oil combustion up to the permitted 875 hr/yr; there is no actual limit on the natural gas operating hours

Attachment 1 to this TSD contains calculations submitted by the Permittee and revised by agency staff.

SV 002 PTE was determined by calculating the emissions from the worst case allowable operating

scenario (fuel type and permitted SUSD emissions).

If worst case emissions for a specific pollutant (NOX, CO, and VOC ) are during startup and shutdown,

emissions of these pollutants were determined as a combination of the permitted startup and

shutdown emissions, with the remainder of the annual operating hours emissions determined at base

load. If worst case emissions for a specific pollutant (NOX) occur while combusting distillate fuel oil,

emissions for the pollutant were determined based on combusting distillate fuel oil for 875 hours per

year, with the remainder of the annual emissions based on combusting natural gas for 7885 hours per

year (8760-875=7885). For some pollutants such as NOX, worst case emissions occur during (cold)

startup on distillate fuel oil, so the 875 hour/yr distillate fuel oil operating limit, the distillate fuel oil

startup limits, and permitted natural gas startup/shutdown emissions are accounted for in determining

NOX annual PTE.

3.7 Periodic Monitoring

In accordance with the Clean Air Act, it is the responsibility of the owner or operator of a facility to have

sufficient knowledge of the facility to certify that the facility is in compliance with all applicable

requirements.

In evaluating the monitoring included in the permit, the MPCA considers the following:

• The likelihood of violating the applicable requirements;

• Whether add-on controls are necessary to meet the emission limits;

• The variability of emissions over time;

• The type of monitoring, process, maintenance, or control equipment data already available for the emission unit;

• The technical and economic feasibility of possible periodic monitoring methods; and

• The type of monitoring for similar units.

Table 12 summarizes the periodic monitoring requirements for those emission units for which the

monitoring required by the applicable requirement is nonexistent or inadequate.

Table 12. Periodic Monitoring and CAM

Subject Item Requirement

(rule basis)

Monitoring Discussion

SV 002

(EU 002 CTG and

EU 004 DB)

NOX and CO limits

PM, PM10, PM2.5,

and VOC limits

SO2 limits

SUSD lb/event limits

and 12-month

rolling sum tpy

limits on NOX, CO,

and VOC

(Title I Conditions:

40 CFR Section

52.21(j) BACT

Limits; Minn. R.

7007.3000)

Formaldehyde:

Subject Item Requirement

(rule basis)

Monitoring Discussion

Condition: to avoid

major source status

under 40 CFR pt. 63)

determined through

testing and form AP-42.

factors, and AP-42 emission

factors for all other HAPs.

EU 005 Auxiliary

Boiler

PM/PM10: < 0.008

lb/mmBtu

SO2: < 0.001

lb/mmBtu

VOC: < 0.007

lb/mmBtu

CO: < 0.06

lb/mmBtu

NOX: < 0.036

lb/mmBtu

(Title I Condition: 40

CFR Section 52.21(j)

BACT Limits;

Minn. R. 7007.3000)

None

Periodic NOX stack testing

to verify compliance with

limit. No CO testing due to

very low test results

compared to limit.

No monitoring warranted -

fuel restricted to NG only.

Periodic stack testing will

determine compliance with

NOX limit.

EU 007 Fire

Pump

40 CFR § 52.21(j)

BACT limits

Minn. R. 7011.2300,

subp. 1 (opacity <

20% once operating

temperature is

attained)

Limits from 40 CFR

pt. 63, subp. ZZZZ

Fuel sulfur content

monitoring

None

Monitoring from the

NESHAP is adequate

No additional monitoring or

testing warranted due use of

very low sulfur diesel fuel, and

small size and emergency

nature of operation.

Pt. 63, subp. ZZZZ is post-1990

and EPA has determined that

all post-1990 standards

already contain adequate

monitoring requirements.

3.8 Insignificant Activities

The facility has two activities (350,000 gallon and 360 gallon distillate fuel oil tanks) classified as

insignificant activities. These are listed in Appendix A to the permit. There are no changes to the

insignificant activities with this permit action.

EPA has stated the permit must include periodic monitoring for all emissions units, including

insignificant activities. The insignificant activities at this Facility are only subject to general applicable

requirements (in part because distillate fuel oil has a true vapor pressure of 0.0045 psi (0.031 kPa) at

50˚F, and so both tanks are not subject to NSPS subp. Kb, or Minn. R. 7011.1505).

3.9 Permit Organization

In general, the permit meets the MPCA Delta Guidance for ordering and grouping of requirements. One

area where this permit deviates slightly from Delta guidance is in the use of appendices. While

appendices are fully enforceable parts of the permit, in general, any requirement that the MPCA thinks

should be tracked (e.g., limits, submittals, etc.), should be in Table A or B. The main reason is that the

appendices are word processing sections and are not part of the tracking system. Violation of the

appendices can be enforced, but the computer system will not automatically generate the necessary

enforcement notices or documents. Staff must generate these.

In this permit action, groups previously used are not used because half of the plant was never built. All

requirements are now at the SV level or the EU level.

3.10 Comments Received –completed after start of public comment period

Public Notice Period: -

EPA 45-day Review Period: -

4. Permit Fee Assessment

This permit action is the reissuance of an individual Part 70 (DQ 2500) with several amendment

applications rolled into this reissuance. Attachment 7 to this TSD contains the MPCA assessment of

application and additional points used to determine the permit application fee required by Minn. R.

7002.0019.

No application fee applies to the reissuance (DQ 2500) under Minn. R. 7002.0016, subp. 1. However,

this permit action includes three additional permit applications: DQ 1407 for changing SV 002 SUSD

BACT limits, DQ 3440 for revising the SV 002 testing deadline, and DQ 3882 for amending SV 002 HAPS

testing and removing EU 002 power augmentation requirements; fees apply to both of these actions.

DQ 1407 was received before the July 1, 2009 effective date of the fee rule, so only applicable

additional fees apply to DQ 1407. DQ 3440 and DQ 3882 were received after the fee rule effective date,

so both the application and any applicable additional fees apply to DQ 3440 and 3882. DQ 2935 is an

MPCA-initiated re-opening, so no fees apply to this action.

The reissuance (DQ 2500) includes the incorporation of pt. 63, subp. ZZZZ for EU 007, however this was

an existing standard that applied to the facility and is not a chargeable activity.

5. Conclusion

Based on the information provided by Mankato Energy Center and Calpine Corp., the MPCA has

reasonable assurance that the proposed operation of the emission facility, as described in the Air

Emission Permit No. 01300098-002 and this TSD, will not cause or contribute to a violation of applicable

federal regulations and Minnesota Rules.

Staff Members on Permit Team: Jessica Forsberg (permit writer/engineer)

Marshall Cole (permit writer/engineer)

Brent Rohne (enforcement)

Sean O’Connor (stack testing)

Jim Kolar (stack testing)

Chris Buntjer (peer reviewer)

Dave Beil (peer reviewer)

Dick Cordes (peer reviewer)

AQ File No. 4198; DQ 2500; DQ 1407; DQ 2935; DQ3440; DQ 3882

Attachments: 1. Emission Calculation Spreadsheets

2. Facility Description and CD-01 Forms 3. Endangered Species Act Consultation 4. Air Dispersion Modeling Analysis Review 2011 and 2013 Revision 5. SUSD Limits Development 6. SUSD BACT Analysis 7. Points Calculator 8. CAM Plans 9. VOC-CO CAM Relationship Data 10. National Historic Preservation Act Consultation (this will be completed prior to permit

issuance)

ATTACHMENT 1: Emission Calculations

Permit No. 1300098-002 Mankato Energy Center

Mankato Energy Center Emissions Summary

Permit No. 01300098-002

SV 002 EU 005 EU 007 FS 001 Total

PM 118.5 2.45 7.88E-03 12.07 133.0

PM10 118.5 2.45 7.88E-03 2.88 123.8

PM2.5 118.5 2.45 7.88E-03 0.02 121.0

SO2 56.0 0.37 1.63E-02 56.4

NOX 160.5 11.04 0.66 172.2

VOC 244.6 2.17 9.45E-03 246.8

CO 491.4 18.40 2.89E-02 509.8

Lead 1.37E-02 1.50E-04 1.39E-02

H2SO4 8.50 4.90E-02 2.17E-03 8.55

Formaldehyde 9.00 2.25E-02 1.58E-04 9.02

n-hexane 8.50 0.54 9.04

Total HAP 22.50 0.57 8.62E-04 23.07

CO2e 1,530,925 35,873.0 1.7 1,566,799

Limited PTE (tpy)


MINNESOTA POLLUTION CONTROL AGENCY ALTERNATE PERMIT APPLICATION FORM EC-03AIR QUALITY DIVISION INTERNAL COMBUSTION

520 LAFAYETTE ROAD CALCULATION FORM

ST. PAUL, MN 55155-4194 9/10/2002

1) AQD Facility ID No.: 1300098

2) Facility Name: Mankato Energy Center, LLC

3) Emission Unit Identification No.: Combined Cycle System #2 - (EU 002 Combustion Turbine #2,

EU 004 - Combustion Turbine #2 Duct Burners)

4) Stack/Vent Designation No.: SV 002

5) Control Equipment Identification No.: CE 002, CE 004

6) Engine Type: Reciprocating Turbine Other: Combined Cycled Turbine

7) Engine is Used For: Non Emergency use Emergency use only

(If you check this box, you must complete

Part 2 of this form)

8) Rated Heat Input: 2,082 (Combustion Turbine Firing Natural Gas)a

800 (Duct Burners Firing Natural Gas)b

9a) Primary Fuel Type: Natural Gas

9b) Fuel Parameters, if applicable: % Sulfur 0.8 grains/100 scf % Ash NA

10) Heat Value: 1,020 Btu/cf (BTU/ton, BTU/gal, or BTU/cf)

11) Fuel Consumption Rate: 2.04 MMscf/hr (Combustion Turbine Firing Natural Gas)

0.78 MMscf/hr (Duct Burners Firing Natural Gas)

12) Calculations Summary:

12a) 12b) 12c) 12d) 12e) 12f) 12g) 12h)

Maximum Pollution Maximum Limited Actual

Pollutant Emission Emission Uncontrolled Control Controlled Controlled Emissions

Factor Rate Emissions Efficiency Emissions Emissions

includes

SUSD

includes

SUSD

does not

include

SUSD

includes

SUSD

(lbs/MMBtu) (lbs/hr)d

(tons/yr)e

(%)f

(tons/yr)g

(tons/yr) (tons/yr)

PM NAc

22.0 96.4 0.0% 96.4 96.4

PM10 NAc

22.0 96.4 0.0% 96.4 96.4

PM2.5 NAc

22.0 96.4 0.0% 96.4 96.4

SO2 NAc

3.5 15.1 0.0% 15.1 15.1

NOx NAc

256.0 1048.6 80.0% 139.7 149.5

VOC NAc

769.7 282.9 40.0% 50.5 252.0

CO NAc

1539.3 889.5 90.0% 113.4 515.4

Lead NAc

ND ND ND ND ND

H2SO4h NA

c0.52 2.3 0.0% 2.3 2.3

eAnnual maximum uncontrolled emissions are conservatively estimated based on maximum hourly emission rate and does not incorporate BACT limits.

aThe maximum hourly natural gas heat input capacity is based on the combustion turbine's highest hourly operating scenario (combinations of load, ambient

temperature) which is based on vendor data.bThe ductburners have a maximum rated heat input capcity of 800 MMBtu/hr and fire natural gas only.

cThe hourly emission rates provided in 12c) are a worst-case projected emissions for the combined cycle system, which are based on several different operating

scenarios at varying heat input capacities for the combustion turbine. The emission rate also include the duct burner natural gas combustion emissions. These emission

rates do not correlate directly to the maximum heat input capacity provided above. Therefore, a specific emission factor is not relevant to the combined cycle system

emission rates provided on this form.dCombined cycle system maximum hourly emission rate is a worst case composite uncontrolled emission scenario based on the combustion turbines' highest hourly

emission operating scenario (combinations of load, ambient temperature) for each pollutant, based on combustion turbine vendor data. The emission rate also

incorporates maximum hourly duct burner emissions.

fThe NOx, CO, and VOC control efficiencies only represent a nominal control efficiency and are not used in column 12f) to calculated controlled emissions.


NA = Not applicable

ND = No emission factor data available in AP-42

Pollutant Fuel

Cold SU

tpy* Warm SU tpy* SD tpy*

SUSD Total

tpy cold startup lb/hr

warm startup

lb/hr shutdown lb/hr1

worst case lb/hr NG

operating scenario

NOx Natural Gas 7.44 13.64 0.51 21.6 92.4 59.3 20.3 Cold SU

CO Natural Gas 123.91 282.31 5.38 411.6 1539.3 1227.4 59.7 Cold SU

VOC Natural Gas 61.96 141.16 2.69 205.8 769.7 613.7 29.2 Cold SU1Worst case lb/hr emissions occur during the one-hour period composed of 1/2 hour shutdown and 1/2 hour regular controlled operation

*Calpine's Proposed SUSD limits, ton/yr, calc'd as 12-month rolling sum

Proposed No. of Events

# of events

per year Hours per event

Total Hours for

SUSD

Gas Cold SU 46.0 3.5 161

Warm SU 184.0 2.5 460

SD 230.0 0.5 115

Total hours for startup or shutdown event on natural gas 736

gThe turbine and the ductburners will both vent to a common stack. Therefore, the maximum controlled emissions represent the calculated maximum controlled

emissions at ambient conditions for the combined cycle system, which includes both the combustion turbine & ductburners. The controlled emissions are based on the

following BACT limits while firing natural gas - 3.0 ppmvd NOx @ 15% O2, 4.0 ppmvd CO @15% O2, 3.0 ppmvd VOC @15% O2. fH2SO4 emissions are equal to 15.2% of SO2 emissions. See H2SO4 derivations calculation in 'H2SO4' worksheet.

Remainder of hours per year not operating in startup or

shutdown mode8024


Emission Unit Identification No.: Combined Cycle System #2 - (EU 002 Combustion Turbine #2,


Stack/Vent Designation No.: SV 002

ND indicates no data from AP-42, Section 3.1 (4/00)

9a) Backup Fuel Type: Fuel Oil

Rated Heat Input: 2,243 (Combustion Turbine Firing Fuel Oil)a

million BTU/hr

800 (Duct Burners Firing Natural Gas)b

9b) Fuel Parameters, if applicable: % Sulfur 0.05 % Ash NA

10) Heat Value: 140,000 Btu/gal (BTU/ton, BTU/gal, or BTU/cf)

11) Fuel Consumption Rate: 16,021 gal/hr (Combustion Turbine Firing Natural Gas)

0.78 MMscf/hr (Duct Burners Firing Natural Gas )

12) Calculations Summary:

12a) 12b) 12c) 12d) 12e) 12f) 12g) 12h)

Maximum Pollution Maximum Limited Actual

Pollutant Emission Emission Uncontrolled Control Controlled Controlled Emissions

Factor Rate Emissions Efficiency Emissions Emissions

includes

SUSD

includes

SUSD

does not

include

SUSD

includes

SUSD

(lbs/MMBtu) (lbs/hr)d

(tons/yr)e

(%)f

(tons/yr)g

(tons/yr)h

(tons/yr)

PM NAc

72.6 318.0 0.0% 318.0 31.8 NA

PM10 NAc

72.6 318.0 0.0% 318.0 31.8 NA

PM2.5 NAc

72.6 318.0 0.0% 318.0 31.8 NA

SO2 NAc

96.8 423.9 0.0% 423.9 42.3 NA

NOX NAc

381.9 1557.5 80.0% 253.4 25.9 NA

VOC NAc

214.0 229.9 40.0% 111.2 17.7 NA

CO NAc

428.1 1331.5 90.0% 132.2 27.4 NA

Leadi

1.4E-05 0.031 0.138 0.0% 0.138 0.014 NA

H2SO4j NA

c14.7 64.3 0.0% 64.3 6.4 NA

iLead emission factor taken from AP-42, Section 3.1 (4/00)

NA = Not applicable

aThe maximum hourly fuel oil heat input capacity is based on the combustion turbine's highest hourly operating scenario (combinations of load, ambient temperature)

which is based on vendor data.

jH2SO4 emissions are equal to 15.2% of SO2 emissions. See H2SO4 derivation calculations in 'H2SO4' worksheet.

cThe hourly emission rates provided in 12c) are a worst-case projected emissions for the combined cycle system, which are based on several different operating

scenarios at varying heat input capacities for the combustion turbine. The emission rate also include the duct burner natural gas combustion emissions. These emission

rates do not correlate directly to the maximum heat input capacity provided above. Therefore, a specific emission factor is not relevant to the combined cycle system

emission rates provided on this form.dThe combined cycle system maximum hourly emission rate is a worst case composite emission scenario that is based on the combustion turbines' highest hourly

emission operating scenario (combinations of load, ambient temperature) for each pollutant, which is based on combustion turbine vendor data. The emission rate also

incorporates the maximum hourly duct burner emissions.eAnnual maximum uncontrolled emissions are conservatively estimated based on the maximum hourly uncontrolled emission rate, scaled-up SUSD hours based on 8760

hr/yr fuel oil operating hours, and does not incorporate the proposed turbine fuel oil operating usage limit or BACT limits.

fThe NOx, CO, and VOC control efficiencies only represent a nominal control efficiency and are not used in column 12f) to calculated controlled emissions.

gThe turbine and the ductburners will both vent to a common stack. Therefore, the maximum controlled emissions represent the calculated maximum controlled

emissions at ambient conditions for the combined cycle system which include both the turbine & ductburners. The controlled emissions are based on the following

BACT limits while firing fuel oil - 5.5 ppmvd NOx @ 15% O2, 4.8 ppmvd CO @15% O2, and 2.0 ppmvd VOC @15% O2.

bThe duct burners have a maximum rated heat input capacity of 800 MMBtu/hr and fire natural gas only.

hThe combustion turbine will be limited to firing low sulfur distillate fuel oil (no greater than 0.05% sulfur by weight) for no more than 875 hours per year.


Pollutant Fuel

Cold SU

tpy* Warm SU tpy* SD tpy*

SUSD Total

tpy cold startup lb/hr

warm startup

lb/hr shutdown lb/hr1

worst case lb/hr fuel

oil operating

scenario

NOx Fuel Oil 1.38 1.69 0.25 3.3 131.2 56.28 45.73 Cold SU

CO Fuel Oil 4.49 6.55 4.64 15.7 428.1 218.4 324.4 Cold SU

VOC Fuel Oil 2.25 3.27 2.32 7.8 214.0 109.2 167.4 Cold SU1Worst case lb/hr emissions occur during the one-hour period composed of 1/2 hour shutdown and 1/2 hour regular controlled operation

*Calpine's Proposed SUSD limits, ton/yr, calc'd as 12-month rolling sum

Proposed No. of Events

# of events

per year Hours per event

Total Hours for

SUSD

Gas Cold SU 6.0 3.5 21

Warm SU 24.0 2.5 60

SD 30.0 0.5 15

Total hours for startup or shutdown on fuel oil 96

Remainder of fuel oil non-SUSD operating hours per year 779

Emission Unit Identification No.: Combined Cycle System #2 - (EU 002 Combustion Turbine #2,


Stack/Vent Designation No.: SV 002

12) Worst-Case Potential-to-Emit Summary:

12a) 12b) 12c) Operating

Before After Worst After After Conditions

Pollutant Operating Operating Case Operating Operating For lb/hr worst

Limits Limits Fuel Limits Limits case emission rates

(Does not

include

SUSD)

(Includes

SUSD)

(for tpy emissions

after operating

limits) (Does not include

SUSD)

(Includes

SUSD)

After Operating

Limits (Includes

SUSD )

(ton/yr)a

(ton/yr)b

(lb/hr) (lb/hr) MODELED EMISSION RATES

PM 318.0 118.5 Fuel Oil 72.6 72.6 base load FO 29.679 g/sec NOx emission rate

PM10 318.0 118.5 Fuel Oil 72.6 72.6 base load FO 235.55 lb/hr NOx (1-hr avg; cold FO SU)

PM2.5 318.0 118.5 Fuel Oil 72.6 72.6 base load FO

SO2 423.9 56.0 Fuel Oil 96.8 96.8 base load FO 475.14 g/sec CO 1-hr emission rate

NOX 253.4 160.5 Fuel Oil 57.9 235.6 cold SU FO 3771.0 lb/hr (1-hr avg; cold NG SU)

VOC 111.2 244.6 Natural Gas 11.5 769.7 cold SU NG 153.205 g/sec CO 8-hr emission rate

CO 132.2 491.4 Natural Gas 30.2 3771.0 cold SU NG 1215.9 lb/hr (8-hr avg during FO cold SU

Lead 1.38E-01 1.37E-02 Fuel Oil 3.14E-02 3.14E-02 base load FO & FO normal operation)

H2SO4 6.43E+01 8.5 Fuel Oil 14.7 14.7 base load FO

13) Operating Limitations, if applicable:

Fire low sulfur distillate fuel oil (


Pollutant Fuel

cold startup

avg lb/hr1

warm startup

avg lb/hr2

shutdown

avg lb/hr3

Worst Case

non-SUSD

lb/hr

Modeled

Emission Rate

lb/hr

Modeled

Emission

Rate g/s

modeled emission

rate averaging

time

NOx Natural Gas 92.4 59.3 20.3 31.9

NOx Fuel Oil 131.2 56.3 45.7 57.9

CO Natural Gas 1539.3 1227.4 59.7 25.9 3771.04 475.14 1-hour

CO Fuel Oil 428.1 218.4 324.4 30.2 1215.94 153.205 8-hour1Determined with lb/event limit over the 3.5 hour event duration

2Determined with lb/event limit over the 2.5 hour event duration

3Determined with lb/event limit over the 0.5 hour event duration plus 0.5 hours of worst-case normal operation

Pollutant Averaging Time

Modeled

Impacts

(µg/m3)

Background

Value (µg/m3)

Total

Predicted

Impacts

(µg/m3)

NAAQS

(MAAQS)

(µg/m3)

% of NAAQS

(MAAQS)

CO 1-hr 580.15 575 1155.15 40,000 (35,000) 3.30%

at 1215.94

lb/hr8-hr 498.08 345 843.08 10,000 8.43%

CO 1-hr 1801.13 575 2376.13 40,000 (35,000) 5.94%

at 3775 lb/hr 8-hr 1546.34 345 1891.34 10,000 18.91%

235.55 29.6791-hour

& annual


MINNESOTA POLLUTION CONTROL AGENCY PERMIT APPLICATION FORM EC-13CAIR QUALITY DIVISION HAZARDOUS AIR POLLUTANTS

520 LAFAYETTE ROAD CALCULATION FORM (FUEL COMBUSTION)

ST. PAUL, MN 55155-4194 5/27/1998



3) Emission Unit Identification No.: EU 002 - Combustion Turbine #2


5) Maximum Rated Boiler Capacity: 2,082.0 MMBTU/hr (Natural Gas)

2,243.0 MMBTU/hr (Fuel Oil)

6) Control Equipment: None

7) Fuel Parameters

7a) 7b) 7c) 7d) 7e)

Fuel Type % Sulfur % Ash Heat Value Units Maximum Fuel

Consumption

Rate

Units

Natural Gas 0.8 grains/100 scf negligible 1,020 Btu/cf 2.04 MMcf/hr

Fuel Oil No. 2 0.05 negligible 140,000 Btu/gal 15,714.3 gal/hr

When calculating Potential Emissions, use items 8a, 8b, 8d, 8e, 8g, 8h, and 8i (if a limit is proposed in item 12).

When calculating Actual Emissions, use items 8a, 8b, 8c, 8f, 8g, and 8j.

8) Calculations Summary - Primary Fuel : Natural Gas

8b) 8c) 8d) 8e) 8f) 8g) 8h) 8i) 8j)

Emission Actual Emission Maximum Actual Pollution Maximum Limited Actual

Factorc

Annual Fuel Rate Uncontrolled Uncontrolled Control Controlled Controlled Controlled

(lbs/ton, lbs/gal, Use Emissions Emissions Efficiency Emissions Emissions Emissions

lbs/MMBtu, etc) (tons, gallons, (lbs/hr)d

(tons/yr) (tons/yr) (%) (tons/yr) (tons/yr) (tons/yr)

MMcf, etc.)

4.00E-05 NA 8.33E-02 3.65E-01 NA 0.00% 3.65E-01 3.65E-01 NA

6.40E-06 NA 1.33E-02 5.84E-02 NA 0.00% 5.84E-02 5.84E-02 NA

1.20E-05 NA 2.50E-02 1.09E-01 NA 0.00% 1.09E-01 1.09E-01 NA

4.29E-07 NA 8.93E-04 3.91E-03 NA 0.00% 3.91E-03 3.91E-03 NA

3.20E-05 NA 6.66E-02 2.92E-01 NA 0.00% 2.92E-01 2.92E-01 NA

2.19E-04 NA 4.56E-01 2.00E+00 NA 0.00% 2.00E+00 9.00E+00 NA

1.30E-06 NA 2.71E-03 1.19E-02 NA 0.00% 1.19E-02 1.19E-02 NA

2.20E-06 NA 4.58E-03 2.01E-02 NA 0.00% 2.01E-02 2.01E-02 NA

2.90E-05 NA 6.04E-02 2.64E-01 NA 0.00% 2.64E-01 2.64E-01 NA

1.30E-04 NA 2.71E-01 1.19E+00 NA 0.00% 1.19E+00 1.19E+00 NA

6.40E-05 NA 1.33E-01 5.84E-01 NA 0.00% 5.84E-01 5.84E-01 NA

Totals 1.11 4.88 4.88 22.50aNahpthalene is included in the Polyaromatic Hydorcarbon(PAH) emissions but is not double-counted in the total HAPs.

bTotal PAH emission factor is equal to the sum of the individual PAH compounds.

Ethylbenzene [100-41-4]

aThe maximum hourly natural gas and fuel oil heat input capacities are based on the combustion turbine's highest hourly operating scenario (combinations of load, ambient temperature which is taken from vendor data.

8a)

HAP Name

(CAS)

Acetaldehyde [534-15-6]

Acrolein [107-02-8]

Benzene [71-43-2]

1,3 Butadiene [106-99-0]

Formeldahyde [50-00-0]

Naphthalenea [91-20-3]

PAHb[130498-29-2]

Propylene Oxide [75-56-9]

Toluene [108-88-3]

Xylene [1330-20-7]

cAll emission factors are from AP-42, Section 3.1 (4/00), except formaldehyde, which based on a synthetic limit equivalent to combustion turbine MACT (YYYY) standard for formaldehyde (91 ppbvd @ 15% O2), potential to emit is calculated using average

ambient temperature operating scenario and 100 percent load. dThe maximum hourly emissions are based on the combustion turbine's highest hourly operating heat input scenario (combinations of load, ambient temperature) which is taken from vendor data.


When calculating Potential Emissions, use items 9a,9b,9d, 9e, 9g, 9h, and 9i (if a limit is proposed in item 12).


9) Calculations Summary - Backup Fuel: Fuel Oil No. 2

9b) 9c) 9d) 9e) 9f) 9g) 9h) 9i) 9j)


Factorc

Annual Fuel Rate Uncontrolled Uncontrolled Control Controlled Controlled Controlled

(lbs/ton, lbs/Mgal, Use Emissions Emissions Efficiency Emissions Emissions Emissions

lbs/MMBtu, etc) (tons, gallons, (lbs/hr)d

(tons/yr) (tons/yr) (%) (tons/yr) (tons/yr)e

(tons/yr)

1.10E-05 NA 2.47E-02 1.08E-01 NA 0.00% 1.08E-01 1.08E-02 NA

5.50E-05 NA 1.23E-01 5.40E-01 NA 0.00% 5.40E-01 5.40E-02 NA

3.10E-07 NA 6.95E-04 3.05E-03 NA 0.00% 3.05E-03 3.04E-04 NA

1.60E-05 NA 3.59E-02 1.57E-01 NA 0.00% 1.57E-01 1.57E-02 NA

4.80E-06 NA 1.08E-02 4.72E-02 NA 0.00% 4.72E-02 4.71E-03 NA

1.10E-05 NA 2.47E-02 1.08E-01 NA 0.00% 1.08E-01 1.08E-02 NA

2.19E-04 NA 4.91E-01 2.15E+00 NA 0.00% 2.15E+00 9.00E+00 NA

1.40E-05 NA 3.14E-02 1.38E-01 NA 0.00% 1.38E-01 1.37E-02 NA

7.90E-04 NA 1.77E+00 7.76E+00 NA 0.00% 7.76E+00 7.75E-01 NA

1.20E-06 NA 2.69E-03 1.18E-02 NA 0.00% 1.18E-02 1.18E-03 NA

3.50E-05 NA 7.85E-02 3.44E-01 NA 0.00% 3.44E-01 3.43E-02 NA

4.60E-06 NA 1.03E-02 4.52E-02 NA 0.00% 4.52E-02 4.51E-03 NA

4.00E-05 NA 8.97E-02 3.93E-01 NA 0.00% 3.93E-01 3.93E-02 NA

2.50E-05 NA 5.61E-02 2.46E-01 NA 0.00% 2.46E-01 2.45E-02 NA

Totals 2.67 11.71 11.71 22.50aNahpthalene is included in the Polyaromatic Hydorcarbon(PAH) emissions but is not double-counted in the total HAPs.

bTotal PAH emission factor is equal to the sum of the individual PAH compounds.

10) Worse-Case Potential-to-Emit Summary: (Ignore this item if filling out this form for a Registration Pemit Option D)

Before After Before After

Operating Operating Operating Operating

Limits Limits Limits Limits

(ton/yr)c

(ton/yr) (lb/hr) (lb/hr)

3.65E-01 3.65E-01 8.33E-02 NA

5.84E-02 5.84E-02 1.33E-02 NA

1.08E-01 1.08E-02 2.47E-02 NA

5.40E-01 1.52E-01 1.23E-01 NA

3.05E-03 3.04E-04 6.95E-04 NA

1.57E-01 1.92E-02 3.59E-02 NA

4.72E-02 4.71E-03 1.08E-02 NA

1.08E-01 1.08E-02 2.47E-02 NA

2.92E-01 2.92E-01 6.66E-02 NA

2.15E+00 9.00E+00 4.91E-01 NA

1.38E-01 1.37E-02 3.14E-02 NA

7.76E+00 7.75E-01 1.77E+00 NA

1.18E-02 1.18E-03 2.69E-03 NA

3.44E-01 4.50E-02 7.85E-02 NA

4.52E-02 4.51E-03 1.03E-02 NA

3.93E-01 5.73E-02 8.97E-02 NA

2.64E-01 2.64E-01 6.04E-02 NA

2.46E-01 2.45E-02 5.61E-02 NA

1.19E+00 1.19E+00 2.7E-01 NA

5.84E-01 5.84E-01 1.33E-01 NA

Totals 14.46 22.50 3.30

d Nahpthalene is included in the Polyaromatic Hydorcarbon(PAH) emissions but is not double-counted in the total HAPs.

e Total PAH emission factor is equal to the sum of the individual PAH compounds.

11) Operating Limitations, if applicable: (Ignore this item if filling out this form for a Registration Pemit Option D):

Not Applicable

9a)

HAP Name

(CAS)

Naphthalenea [91-20-3]

Arsenic [7440-38-2]

Benzene [71-43-2]

Beryllium [7440-41-7]

1,3-Butadiene [106-99-0]

Cadmium [7440-43-9]

Chromium [7440-47-3]

Formeldahyde [50-00-0]

Lead [7439-92-1]

Manganese [7439-96-5]

Mercury [7439-97-6]

Acrolein [107-02-8]a

Nickel [7440-02-0]

PAHb

[130498-29-2]

Selenium [7782-49-2]

cAll emission factors are from AP-42, Section 3.1 (4/00), except formaldehyde, which based on a synthetic limit equivalent to combustion turbine MACT (YYYY) standard for formaldehyde (91 ppbvd @ 15% O2), potential to emit is calculated using average

ambient temperature operating scenario and 100 percent load.

dThe maximum hourly emissions are based on the combustion turbine's highest hourly operating heat input scenario (combinations of load, ambient temperature, and power/steam augmentation) which is taken from vendor data.

eThe combustion turbine will be limited to firing low sulfur distillate fuel oil (no greater than 0.05% sulfur by weight) for no more than 875 hours per year.

HAP Name (CAS)

Acetaldehyde [75-07-0]a

Naphthalene [91-20-3]b, d

Arsenic [7440-38-2]b

Benzene [71-43-2]b

Beryllium [7440-41-7]b

1,3 Butadiene [106-99-0]b

Cadmium [7440-43-9]b

Chromium [7440-47-3]b

Ethylbenzene [100-41-4]a

Formeldahyde [50-00-0]b

Lead [7439-92-1]b

Manganese [7439-96-5]b

Mercury [7439-97-6]b

a After operating limit emissions are based on a worst-case emission scenario where the turbine fires natural gas for 8,760 hours per year.

b After operating limit emissions assume a worst-case emission scenario, where the turbine operates on fuel oil for 875 hours per year and the remainder of the year (7,885 hours) the turbine fires natural gas.

c Represents the worst case annual conctrolled HAP emissions

.

Nickel [7440-02-0]b

PAH [130498-29-2]

b, e

Propylene Oxide [75-56-9]a

Selenium [7782-49-2]b

Toluene [108-88-3]a

Xylenes [1330-20-7]a


MINNESOTA POLLUTION CONTROL AGENCY PERMIT APPLICATION FORM EC-13CAIR QUALITY DIVISION HAZARDOUS AIR POLLUTANTS


ST. PAUL, MN 55155-4194 5/27/1998



3) Emission Unit Identification No.: EU 004 - Combustion Turbine #2 Duct Burners


5) Maximum Rated Boiler Capacity: 800.0 MMBTU/hr


7) Fuel Parameters

7a) 7b) 7c) 7d) 7e)


Consumption

Rate

Units





8b) 8c) 8d) 8e) 8f) 8g) 8h) 8i) 8j)

Actual Emission Maximum Actual Pollution Maximum Limited Actual

Emission Annual Fuel Rate Uncontrolled Uncontrolled Control Controlled Controlled Controlled

Factor Use Emissions Emissions Efficiency Emissions Emissions Emissions

(lbs/MMcf)a

(tons, gallons, (lbs/hr) (tons/yr) (tons/yr) (%) (tons/yr) (tons/yr) (tons/yr)

MMcf, etc.)

2.1E-03 NA 1.6E-03 7.21E-03 NA 0.0 7.2E-03 7.2E-03 NA

1.2E-03 NA 9.4E-04 4.12E-03 NA 0.0 4.1E-03 4.1E-03 NA

7.5E-02 NA 5.9E-02 2.58E-01 NA 0.0 2.6E-01 9.0E+00 NA

1.8E+00 NA 1.4E+00 6.18E+00 NA 0.0 6.2E+00 8.5E+00 NA

6.1E-04 NA 4.8E-04 2.10E-03 NA 0.0 2.1E-03 2.1E-03 NA

3.4E-03 NA 2.7E-03 1.17E-02 NA 0.0 1.2E-02 1.2E-02 NA

Polycyclic Organic Matter (POM)c 8.8E-05 NA 6.9E-05 3.03E-04 NA 0.0 3.0E-04 3.0E-04 NA

2.0E-04 NA 1.6E-04 6.87E-04 NA 0.0 6.9E-04 6.9E-04 NA

1.2E-05 NA 9.4E-06 4.12E-05 NA 0.0 4.1E-05 4.1E-05 NA

1.1E-03 NA 8.6E-04 3.78E-03 NA 0.0 3.8E-03 3.8E-03 NA

1.4E-03 NA 1.1E-03 4.81E-03 NA 0.0 4.8E-03 4.8E-03 NA

8.4E-05 NA 6.6E-05 2.89E-04 NA 0.0 2.9E-04 2.9E-04 NA

3.8E-04 NA 3.0E-04 1.31E-03 NA 0.0 1.3E-03 1.3E-03 NA

2.6E-04 NA 2.0E-04 8.93E-04 NA 0.0 8.9E-04 8.9E-04 NA

2.1E-03 NA 1.6E-03 7.21E-03 NA 0.0 7.2E-03 7.2E-03 NA

2.4E-05 NA 1.9E-05 8.24E-05 NA 0.0 8.2E-05 8.2E-05 NA

Totals 1.48 6.48 6.48 22.5

bNahpthalene is included in the Polycyclic Organic Matter (POM) emissions and is not double-counted in the total HAPs.

cTotal POM emission factor is equal to the sum of the individual POM compounds.

When calculating Potential Emissions, use items 9a,9b,9d, 9e, 9g, 9h, and 9i (if a limit is proposed in item 12).





(ton/yr) (ton/yr) (ton/yr) (ton/yr)

7.21E-03 NA 2.89E-04 NA

Dichlorobenzene (25321-22-6) 4.12E-03 NA 1.31E-03 NA

Formaldehyde (50-00-0) 2.58E-01 9.00 8.93E-04 NA

Hexane (110-54-3) 6.18E+00 8.50 7.21E-03 NA

Naphthalene (91-20-3)1 2.10E-03 NA 8.24E-05 NA

Toluene (108-88-3) 1.17E-02 NA

POM 3.03E-04 NA

Arsenic (7440-38-2) 6.87E-04 NA

Beryllium (7440-43-0-9) 4.12E-05 NA

Cadmium (7440-43-9) 3.78E-03 NA

Chromium (7440-47-3) 4.81E-03 NA

Totals 6.48 22.51Nahpthalene is included in the Polycyclic Organic Matter (POM) emissions and is not double-counted in the total HAPs.

12) Operating Limitations, if applicable: (Ignore this item if filling out this form for a Registration Permit Option D):

Formaldehyde < 9.0 tpy

n-hexane < 8.5 tpy

total HAP < 22.5 tpy

8a)

HAP Name

(CAS)

Manganese (74439-96-5)

Benzene (71-43-2)

Dichlorobenzene (25321-22-6)

Formaldehyde (50-00-0)

Hexane (110-54-3)

Naphthalene (91-20-3)b

Toluene (108-88-3)

Arsenic (7440-38-2)

Beryllium (744-43-0-9)

Cadmium (7440-43-9)

Chromium (7440-47-3)

Cobalt (744-48-4)

Mercury (7439-97-6)

Nickel (7440-02-0)

Selenium (7782-49-2)

aAll emissions are calculated based on emission factors from AP-42, Section 1.4 "Natural Gas Combustion"(7/98).

HAP Name (CAS) HAP Name (CAS)

Benzene (71-43-2) Cobalt (744-48-4)


Mercury (7439-97-6)

Nickel (7440-02-0)



EC-17Greenhouse Gas Emissions

Air Quality Permit Program

Doc Type: Permit Application

Instructions on page 2

1a) AQD Facility ID No.: 13800098 1b) AQ File No.: 4198

2) Facility name: Mankato Energy Center LLC

3) Emission unit ID number: EU 002 and 004 - Combustion Turbine #2 & Duct Burners

4) Stack/Vent designation number: SV 002

5) Control equipment number(s): CE 002, CE 004


Capacity: 2082 MMBtu/hr Natural Gas (CT-2 Only)

7a) 7b) 7c) 7e)

GHG Emission Pollution

Pollutant Factor Control

Efficiency

(lb/unit) (lb/hr) (tpy) (%) (lb/hr) CO2e (tpy) (lb/hr) (tpy) (tpy) CO2e (tpy)

CO2 1 116.89 243,363 1,065,929 0 243,363 1,065,929 243,363 959,458 NA NA

CH4 21 2.20E-03 4.59 20.10 0 4.59 20.10 4.59 20.10 NA NA

N2O 310 2.20E-04 0.46 2.01 0 0.46 2.01 0.46 2.01 NA NA

CO2e 243,601 1,066,974 243,601 1,066,974 243,601 1,066,974

1,066,974 1,066,974 1,066,974

Capacity: 2243 MMBtu/hr Fuel Oil (CT-2 Only) Limited emissions based on current fuel oil limit of 875 hours per year.

7a) 7b) 7c) 7e)



Efficiency

(lb/unit) (lb/hr) (tpy) (%) (lb/hr) (tpy) (lb/hr) (tpy) (tpy) CO2e (tpy)

CO2 1 163.05 365,729 1,601,895 0 365,729 1,601,895 365,729 160,007 NA NA

CH4 21 6.61E-03 14.8 65.0 0 14.8 65.0 14.83 6.49 NA NA

N2O 310 1.32E-03 2.97 13.0 0 2.97 13.0 2.97 1.30 NA NA

CO2e 366,961 1,607,288 366,961 1,607,288 366,961 160,545

Capacity: 800 MMBtu/hr Natural Gas (CT-2 Duct Burner Only)

7a) 7b) 7c) 7e)



Efficiency

(lb/unit) (lb/hr) (tpy) (%) (lb/hr) (tpy) (lb/hr) (tpy) (tpy) CO2e (tpy)

CO2 1 116.89 93,511 409,579 0 93,511 409,579 93,511 409,579 NA NA

CH4 21 2.20E-03 1.76 7.72 0 1.76 7.72 1.76 7.72 NA NA

N2O 310 2.20E-04 0.18 0.77 0 0.18 0.77 0.18 0.77 NA NA

CO2e 93,603 409,981 93,603 409,981 93,603 409,981

Capacity: Total

7a) 7b)

GHG

Pollutant

(lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (tpy) CO2e (tpy)

CO2 459,241 2,011,474 459,241 2,011,474 459,241 1,433,207 NA NA

CH4 16.6 72.7 16.6 72.7 16.6 32.31 NA NA

N2O 3.14 13.8 3.14 13.8 3.14 3.88 NA NA

CO2e 460,564 2,017,269 460,564 2,017,269 460,564 1,530,925

Use this form to summarize the potential and actual greenhouse gas (GHG) emissions for each operation contributing to GHG emissions. Continue to use the other emission forms (EC-01 through EC-16)

as applicable for other regulated air pollutants. Follow the guidance on calculation of greenhouse gas (GHG) emissions. Attach a separate spreadsheet showing all calculations

7) Greenhouse Gas Emissions Summary. Use this table to document GHG emissions from the unit or operation listed above. You must provide mass emissions of each pollutant, as well as carbon dioxide

equivalents (CO2e). For hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs), you will have to calculate emissions of individual compounds on the separate spreadsheet and report the total HFCs and

PFCs in the table below. Instructions are provided starting on page 2. Please report all numbers using three (3) significant digits; use scientific notation if necessary (for example, report 379,355 tons as

“3.79E5”.

7d) 7f) 7g) 7h)

7d) 7f) 7g) 7h)

GWP

Uncontrolled Controlled Limited and Controlled Actual Controlled

Emission Rate Emission Rate Emission Rate Emission Rate

Total GHG (CO2e)

Emissions are calculated based on emission factors from 40 CFR 98 Tables C-1 and C-2. Emission factor units are in lb/MMBtu.

7d) 7f) 7g) 7h)

GWP




7g) 7h)

GWP




Actual Controlled

Emission Rate


Uncontrolled Controlled Limited and Controlled

Emission Rate Emission Rate Emission Rate


MINNESOTA POLLUTION CONTROL AGENCY PERMIT APPLICATION FORM EC-02AIR QUALITY DIVISION EXTERNAL COMBUSTION (BOILER)

520 LAFAYETTE ROAD CALCULATION FORM

ST. PAUL, MN 55155-4194 5/27/1998

- Fill out this form for each boiler, or attach sheets with equivalent information.

- Instructions begin on Page 6.

- If the boiler emits Hazardous Air Pollutants (HAPs), fill out and attach Form EC-13C.



3) Emission Unit Identification No.: EU 005 - Auxiliary Boiler




7) Fuel Parameters

7a) 7b) 7c) 7d) 7e)


Consumption

Rate

Units

Natural Gas0.8

grains/100 negligible 1,020 Btu/cf 68,627.5 cf/hr




8a) 8b) 8c) 8d) 8e) 8f) 8g) 8h) 8i) 8j)

Actual Maximum Actual Pollution Maximum Limited Actual

Pollutant Emission Annual Emission Uncontrolled Uncontrolled Control Controlled Controlled Controlled

Factor Fuel Usage Rate Emissions Emissions Efficiency Emissions Emissions Emissions

(lbs/MMBtu)a

(cf/yr) (lbs/hr) (tons/yr) (tons/yr) (%) (tons/yr) (tons/yr) (tons/yr)

PM 8.0E-03 NA 0.56 2.45 NA 0.00% 2.45 NA NA

PM10 8.0E-03 NA 0.56 2.45 NA 0.00% 2.45 NA NA

PM2.5 8.0E-03 NA 0.56 2.45 NA 0.00% 2.45 NA NA

SO2 1.2E-03 NA 0.08 0.37 NA 0.00% 0.37 NA NA

NOx 3.6E-02 NA 2.52 11.04 NA 0.00% 11.04 NA NA

VOC 7.1E-03 NA 0.50 2.17 NA 0.00% 2.17 NA NA

CO 6.0E-02 NA 4.20 18.40 NA 0.00% 18.40 NA NA

Lead 5.0E-10 NA 3.4E-05 1.5E-04 NA 0.00% 1.5E-04 NA NA

H2SO4 NA NA 0.01 0.05 NA 0.00% 0.05 NA NAaAll emission factors based on vendor data (See Appendix B), except for lead (from AP-42 Section 1.4 "Natural Gas Combustion"(7/98)),

H2SO4 (13.3% of SO2) and PM2.5 (equal to PM10).

9) Worse-Case Potential-to-Emit Summary: (Ignore this item if filling out this form for a Registration Permit Option D)

9a) 9b) 9c)

Before After MODELED EMISSION RATES

Pollutant Operating Operating 0.318 g/sec NOx

Limits Limits 2.52 lb/hr NOx

(ton/yr) (ton/yr) 0.529 g/sec CO

PM 2.45 NA 4.20 lb/hr CO

PM10 2.45 NA

SOx 0.37 NA

NOx 11.04 NA

VOC 2.17 NA

CO 18.40 NA

Lead 1.5E-04 NA


Not Applicable


MINNESOTA POLLUTION CONTROL AGENCY PERMIT APPLICATION FORM EC-13C

AIR QUALITY DIVISION HAZARDOUS AIR POLLUTANTS


ST. PAUL, MN 55155-4194 5/27/1998



3) Emission Unit Identification No.: EU 005 - Auxiliary boiler




7) Fuel Parameters

7a) 7b) 7c) 7d) 7e)


Consumption

Rate

Units





8b) 8c) 8d) 8e) 8f) 8g) 8h) 8i) 8j)


Factor Annual Fuel Rate Uncontrolled Uncontrolled Control Controlled Controlled Controlled

(lbs/ton, lbs/gal, Use Emissions Emissions Efficiency Emissions Emissions Emissions

lbs/MMcf, etc)a

(tons, gallons, (lbs/hr) (tons/yr) (tons/yr) (%) (tons/yr) (tons/yr) (tons/yr)

MMcf, etc.)

2.1E-03 NA 1.4E-04 6.31E-04 NA 0.0 6.3E-04 NA NA

1.2E-03 NA 8.2E-05 3.61E-04 NA 0.0 3.6E-04 NA NA

7.5E-02 NA 5.1E-03 2.25E-02 NA 0.0 2.3E-02 NA NA

1.8E+00 NA 1.2E-01 5.41E-01 NA 0.0 5.4E-01 NA NA

6.1E-04 NA 4.2E-05 1.83E-04 NA 0.0 1.8E-04 NA NA

3.4E-03 NA 2.3E-04 1.02E-03 NA 0.0 1.0E-03 NA NA

Polycyclic Organic Matter (POM)c

7.0E-04 NA 4.8E-05 2.10E-04 NA 0.0 2.1E-04 NA NA

2.0E-04 NA 1.4E-05 6.01E-05 NA 0.0 6.0E-05 NA NA

1.2E-05 NA 8.2E-07 3.61E-06 NA 0.0 3.6E-06 NA NA

1.1E-03 NA 7.5E-05 3.31E-04 NA 0.0 3.3E-04 NA NA

1.4E-03 NA 9.6E-05 4.21E-04 NA 0.0 4.2E-04 NA NA

8.4E-05 NA 5.8E-06 2.52E-05 NA 0.0 2.5E-05 NA NA

3.8E-04 NA 2.6E-05 1.14E-04 NA 0.0 1.1E-04 NA NA

2.6E-04 NA 1.8E-05 7.82E-05 NA 0.0 7.8E-05 NA NA

2.1E-03 NA 1.4E-04 6.31E-04 NA 0.0 6.3E-04 NA NA

2.4E-05 NA 1.6E-06 7.21E-06 NA 0.0 7.2E-06 NA NA

Totals 0.13 0.57 0.57

bNahpthalene is included in the Polycyclic Organic Matter (POM) emissions but is not double-counted in the total HAPs.

cTotal POM emission factor is equal to the sum of the individual POM compounds.




(ton/yr) (ton/yr) (ton/yr) (ton/yr)

6.31E-04 NA 2.52E-05 NA

Dichlorobenzene (25321-22-6) 3.61E-04 NA 1.14E-04 NA

Formaldehyde (50-00-0) 2.25E-02 NA 7.82E-05 NA

Hexane (110-54-3) 5.41E-01 NA 6.31E-04 NA

Naphthalene (91-20-3)1

1.83E-04 NA 7.21E-06 NA

Toluene (108-88-3) 1.02E-03 NA

POM 2.10E-04 NA

Arsenic (7440-38-2) 6.01E-05 NA

Beryllium (7440-43-0-9) 3.61E-06 NA

Cadmium (7440-43-9) 3.31E-04 NA

Chromium (7440-47-3) 4.21E-04 NA

Totals 0.57 ton/yr1Nahpthalene is included in the Polycyclic Organic Matter (POM) emissions but is not double-counted in the total HAPs.


Not Applicable

8a)

HAP Name

(CAS)


Benzene (71-43-2)

Dichlorobenzene (25321-22-6)

Formaldehyde (50-00-0)

Hexane (110-54-3)

Naphthalene (91-20-3)b

Toluene (108-88-3)

Arsenic (7440-38-2)

Beryllium (744-43-0-9)

Cadmium (7440-43-9)

Chromium (7440-47-3)

Cobalt (744-48-4)

Mercury (7439-97-6)

Nickel (7440-02-0)


aAll emissions are calculated based on emission factors from AP-42, Section 1.4 "Natural Gas Combustion"(7/98).

HAP Name (CAS) HAP Name (CAS)

Benzene (71-43-2) Cobalt (744-48-4)


Mercury (7439-97-6)

Nickel (7440-02-0)



EC-17Greenhouse Gas Emissions

Air Quality Permit Program

Doc Type: Permit Application

Instructions on page 2

1a) AQD Facility ID No.: 13800098 1b) AQ File No.: 4198

2) Facility name: Mankato Energy Center LLC

3) Emission unit ID number: EU 005 - Auxiliary Boiler

4) Stack/Vent designation number: SV 003

5) Control equipment number(s): None


Capacity: 70 MMBtu/hr

7a) 7b) 7c) 7e)



Efficiency

(lb/unit) (lb/hr) (tpy) CO2e (tpy) (%) (lb/hr) (tpy) CO2e (tpy) (lb/hr) (tpy) CO2e (tpy) (tpy) CO2e (tpy)

CO2 1 116.89 8,182 35,838 35,838 0 8,182 35,838 35,838 8,182 35,838 35,838 NA NA

CH4 21 2.20E-03 0.15 0.68 14.2 0.0 0.2 0.7 14.2 0.2 0.6759 14.2 NA NA

N2O 310 2.20E-04 0.015 0.068 21 0 0.015 0.068 21 0.015 0.068 21 NA NA

HFCs

PFCs

technical support document draft/proposed ......technical support document, permit action number:...

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