Bureau of Air 

Curtis State Office Building 

1000 SVI! Jackson. Suite 310 

Topeka, KS 66612 

Rob~n Moser, lv1D, Secretary 

Source ID No. 0210002 

Mr. Jeff Burkett 

Senior Environmental Coordinator 

The Empire District Electric Company 

P.O. Box 127 

Joplin, Missouri 64802 

Department ofllealth & Environment 

July 11,2013 

RE: Air Emission Source PSD Construction Permit- Riverton Power Station 

Dear Mr. Burkett: 

Phone: 785-296-6281 

Fax: 785-291-3953 

llowry@kdheks.gov 

www. kd heks. gov/bar 

Sam BroWI1hl-lck, Cfovcrnor 

Enclosed is the Air Emission Source PSD Construction Permit for the conversion of Unit 12 from 

simple cycle to combined cycle operation at The Empire District Electric Company facility located in Riverton, 

Kansas. Also enclosed is a copy of the Responsiveness Summary. Please review the enclosed Air Emission 

Source Construction Permit carefully, since it obligates The Empire District Electric Company to certain 

requirements. The source ID number listed above should be included in all communications with the Kansas 

Department of Health and Environment (KDHE) in reference to this approval. 

As provided for in K.S.A. 65-3008b(e), an owner or operator may request a hearing within 15 days after 

affirmation, modification or reversal of a permit decision pursuant to subsection (b) ofK.S.A. 65-3008a. In the 

Request for Hearing, the owner or operator shall specify the provision of this act or rule and regulation 

allegedly violated, the facts constituting the alleged violation and secretary's intended action. Such request must 

be submitted to: Director, Office of Administrative Hearings, 1020 S. Kansas Avenue, Topeka, Kansas 66612-

1327. Failure to submit a timely request shall result in a waiver of the right to hearing. 

If you have any questions about the enclosed amendment to the construction permit, or need any 

additional information, please contact me at (785) 296-6281. 

LDL:lv 

Enclosures 

c: Doug Cole, SEDO 

C-10913 

Sincerely, 

~.owr;,~ En 1ronmental Engineer 

Air Permitting Section 
Bureau of Air 

Curtis State Office Building 

1000 SW Jackson, Suite 310 

Topeka, KS 66612-1366 

Robert Moser, MD, Secretary 

Source ID No.: 

Effective Date: 

Depm1ment of llealth & Environment 

AIR EMISSION SOURCE 

CONSTRUCTION PERMIT 

0210002 

July 11, 2013 

Phone: 785-296-6281 

Fax: 785-291-3953 

llowry@kdheks.gov 

www.kdheks.gov/bar 

Sam Brownback, Governor 

Source Name: The Empire District Electric Co. -Riverton Generating Station 

SIC Code: 

NAICS Code: 

Source Location: 

Mailing Address: 

Contact Person 

4911, Electric Services 

221112, Fossil fuel power generation 

7240 Southeast Highway 66 

Riverton, Kansas 66770 

P.O. Box 127 

Joplin, Missouri 64802 

Mr. Jeff Burkett 

Sr. Environmental Coordinator 

Telephone Number (417) 625-4236 

This permit is issued pursuant to K.S.A. 65-3008 as amended. 

I. Description of Activity Subject to Air Pollution Control Regulations 

The Empire District Electric Company (Empire), Riverton Unit 12, a Siemens V84.3A(2) natural gasfired combustion turbine, nominally rated at 150 MW, was originally issued a construction permit on 

October 18,2005 (amended on August 18,2006 and February 5, 2009) and began operation in 2007. 

Empire plans to convert the existing Riverton Unit 12 simple cycle combustion turbine to a combined 

cycle unit, with a nominal capacity of 250 MW (1963 MMBtu/hr). The proposed combined cycle unit 

will replace the capacity and energy provided by coal fired boilers Unit 7 ( 426 MMBtu/hr) and Unit 8 

(600 MMBtu/hr), which will both be retired in conjunction with the completion of this project. Empire 

plans to complete this conversion by June, 2016. 

Page 1 of 16 
Modifications will include a heat recovery steam generator (HRSG) with supplemental natural gas duct 

firing (duct burners) and a condensing steam turbine generator. A selective catalytic reduction (SCR) 

system will control oxides of nitrogen (NOx). A carbon monoxide catalyst will control carbon monoxide 

(CO) and volatile organic compound (VOC) emissions from the turbine and HRSG. Other equipment 

will include a cooling tower, an 18.6 MMBtu/hr natural gas-fired auxiliary boiler with the capacity to 

produce 15,000 pounds of steam per hour (approximately 18.6 MMBtulhr), a 1102 HP (750 Kw) 

emergency diesel engine and two (2) sulfuric hexafluoride (SF6) insulated circuit breakers. Except in 

the case of an actual emergency, Empire will not operate the emergency diesel engine more than 100 

hours per year in a non-emergency capacity to accommodate maintenance and readiness testing. 

Emissions increases of NOx, sulfur dioxide (S02), carbon monoxide (CO), volatile organic compounds 

(VOC), particulate matter (PM), PM with a diameter less than 10 microns (PM10), PM with a diameter 

less than 2.5 microns (PM25), lead, sulfuric acid mist (SAM), hydrogen fluoride (HF), and carbon 

dioxide equivalent (C02e) were evaluated for this review. This is a major modification of a major 

stationary source for at least one regulated pollutant emitted in excess of the PSD significant emission 

levels. Since there is an increase in PM, PM10, PM2.5, and C02e emissions in excess of the significant 

thresholds, the proposed modification will be subject to the requirements of 40 CFR 52.21, Prevention 

of Significant Deterioration (PSD) as adopted under K.A.R. 28-19-350. 

This project is subject to K.A.R. 28-19-300 (Construction permits and approvals; applicability) because 

the increase in potential-to-emit of PM exceeds 25 tons per year and PM 1 o exceeds 15 tons per year. 

The combined cycle unit (CT+HRSG) is an affected source subject to Title IV of the Federal Clean Air 

Act, Acid Deposition Control. The emergency diesel engine is subject to the requirements of 40 CFR 

60, Subpart IIII, Standards of Performance for Stationary Compression Ignition (CI) Internal 

Combustion Engines. 

An air dispersion modeling impact analysis, an additional impact analysis, and a Best Available Control 

Technology (BACT) determination were conducted as a part of the construction permit application 

process. 

II. Significant Applicable Air Pollution Control Regulations 

The following significant Kansas air quality regulations were determined to be applicable to this source: 

A. K.A.R. 28-19-11, Exceptions due to breakdown or scheduled maintenance - as applied to state 

regulations K.A.R. 28-19-30 through 32 and K.A.R. 28-19-650. 

B. K.A.R. 28-19-30 through 32, Indirect heating equipment emissions. 

C. K.A.R. 28-19-275, Special provisions; acid rain deposition. 

D. K.A.R. 28-19-300, Construction permits and approvals; applicability. 

E. K.A.R. 28-19-350, which adopts by reference 40 CFR 52.21, Prevention of significant 

deterioration of air quality. 

Page 2 of 16 
F. K.A.R. 28-19-650, Emissions opacity limits. 

G. K.A.R. 28-19-720, which adopts by reference 40 CFR Part 60, New Source Performance 

Standards. 

H. K.A.R. 28-19-750, which adopts by reference 40 CFR Part 63, National Emission Standards for 

Hazardous Air Pollutants. 

I. 40 CFR Part 60, Subpart A, General Provisions. 

J. 40 CFR Part 60, Subpart IIII, Standards of Performance for Stationary Compression Ignition 

Internal Combustion Engines. 

K. 40 CFR Part 63, Subpart A, General Provisions. 

L. 40 CFR Part 63, Subpart ZZZZ, National Emissions Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines. 

M. 40 CFR Part 63 Subpart YYYY, National Emission Standards for Hazardous Air Pollutants from 

Stationary Combustion Turbines. Subpart YYYY, 63.6145 requires initial notification. Owners 

or operator of lean premix gas-fired stationary combustion turbines or diffusion flame gas-fired 

turbines must comply with the initial notification requirements set forth in 40 CFR 63.6145 but 

need not comply with any other requirement of 40 CFR Part 63 Subpart YYYY until EPA takes 

final action to require compliance and publishes a document in the Federal Register. [40 CFR 

63.6095(d)] As of the date on this application, the EPA has not published such a document in 

the Federal Register. 

N. 40 CFR Part 60 Subpart KKKK, Standards of Performance for Stationary Gas Turbines, applies 

to stationary combustion turbines with a heat input at peak load equal to or greater than 10 

MMBtu/hr, based on the higher heating value of the fuel, which commenced construction, 

modification, or reconstruction after February 18, 2005. 

0. 40 CFR Part 60 Subpart De, Standards of Performance for Small Industrial CommercialInstitutional Steam Generating Units applies to the auxiliary boiler. Since the auxiliary boiler 

will fire solely natural gas it is subject to the Reporting and Recordkeeping requirements of 40 

CFR Part 60, Subpart De [40 CFR 60.48(c)]. 

P. 40 CFR Part 63 Subpart 40 CFR Part 63 Subpart DDDDD Industrial, Commercial, and 

Institutional Boilers and Process Heaters (Boiler MACT) apply to the auxiliary boiler. Since the 

auxiliary boiler will fire solely natural gas it will not be subject to any emissions limits, but 

rather will be subject to a work practice standard that requires an annual tune-up in lieu of 

emission limits. 

Page 3 of 16 
Q. 40 CFR Part 72 through Part 78, Acid Rain Program (ARP), applies to utility units. A utility unit 

is defined as a unit owned or operated by a utility that serves a generator in any state that 

produces electricity for sale. Unit 12, when converted to a combined cycle operation, will 

continue to be subject to the ARP. The ARP requires various pollutant monitors in addition to 

possession of S02 allowances for each ton of S02 emitted. The current ARP permit, under 

which unit 12 currently operates will be modified as the project is completed. 

III. Air Emission Unit Technical Specifications 

The following equipment or equivalent is approved. 

A. Combined cycle combustion unit (CT+HRSG)- Conversion of one (I) Siemens Westinghouse 

Model V84.3A(2) simple cycle combustion turbine/generator, known as emission Unit 12, 

equipped with dry low NOx burners, to a combined cycle operation, burning natural gas. The 

manufacturer's estimated performance is 250 MW. The combined cycle unit includes a heat 

recovery steam generator (HRSG) with supplemental natural gas duct firing (duct burners) and a 

condensing steam turbine generator with SCR and CO catalyst 

B. One mechanical draft cooling tower with high efficiency drift eliminator to reduce aerosol and 

particulate emissions from the tower. 

C. One 750 Kw emergency diesel engine. 

D. One 18.6 Mm Btu/hr natural gas-fired auxiliary boiler with the capacity to produce 15,000 

pounds of steam per hour. The auxiliary boiler is designed to operate when the combined cycle 

unit is in a brief period of shutdown and for startup. 

E. Two (2) Sulfur Hexafluoride (SF6)-insulated circuit breakers. 

IV. Air Emissions Estimates from the Proposed Activity 

The air emissions estimates are shown below: 

Baseline Actual Emissions and Projected Actual Emissions 

(tons per year) 

Units 7 Total Projected Actual Unit 12 I· Baseline Unit 12 &8 Baseline Actual Emissions PSD Pollutant Baseline Actual (Unit 12 Actual Units 7, 8 Increase Significance Type Actual (before & Unit 12 After Combined Cycle Threshold 

Project) (before Project) Project minus 

Project) Total Baseline) 

NOx 1120 34 1154 67 -1087 40 

Page 4 of 16 
so2 5004 1 5005 12 -4993 40 

co 90 3 93 60 -33 100 

voc 10 0.3 10.3 47.3 37 40 

Lead 0.5 -- 0.5 4.lx10-5 -0.5 0.6 

SAM 2 0.1 2.1 6.93 4.83 7 

HF 25 -- 25 1.69x10·5 -25 3 

PM 91 7 98 132 34 25 

PM to 66 7 73 132 59 15 

PM2.s 26 7 33 132 99 10 

C02e 640,234 123,604 763,838 1,020,590 256,752 75,000 

V. Air Emission Limitations 

A. The BACT emission limitations established in this permit apply to the combined cycle unit 

(CT+HRSG) at all times, including startup, shutdown and malfunction, except as provided in 

Section VII. Performance Testing and Compliance, H. Malfunction, of this permit. 

B. K.A.R. 28-19-650 (a)(3): Opacity of visible emissions from all emission units shall not exceed 

20 percent. 

C. Particulate matter emissions from all indirect heating equipment are limited to the amount 

determined by the following equation [K.A.R. 28-19-3l(a)]: 

A = 1. 026 II0233 

Where: A= the allowable emission rate in lb I I 06 Btn 

I =the total heat input of all boilers in 106 Btu 

D. The NO, emissions from the combined cycle unit (CT+HRSG) shall meet the applicable 

emission limits specified in 40 CFR 60.4320(a). NO, emission limits shall not exceed the limits 

specified in Table 1 to Subpart KKKK of Part 60-Nitrogen Oxide Emission Limits for New 

Stationary Combustion Turbines. The NO, emission limit specified in 40 CFR 60.4350(h) is 15 

ppm@ 15% 0 2 on a 30 unit operating day rolling average. 

E. The S02 emissions from the combined cycle unit (CT +HRSG) shall meet the applicable 

emission limits specified in 40 CFR 60.4330(a) which is 110 Nanogram/joule (0.90 lb/gross 

MW-hr). 

Page 5 of 16 
F. The BACT PM/PM10/PM2.s emissions shall not exceed: 

1. 30.2 lb per hour (front+ back half) for the combined cycle unit (CT + HRSG). 

2. 0.005 lb/MMBtu for the auxiliary boiler. 

3. 0.15 g/bhp-hr for the diesel engine 

4. drift rate of0.0005 percent of inlet flow for the mechanical draft cooling tower 

G. The BACT Greenhouse Gas emissions shall not exceed: 

1. For the combined cycle combustion turbine and duct burners. 

a. C02 emissions are limited to 1,021,770 tons C02/year on a 12-month rolling 

basis, 

and the following equation (Equation G-4 of Section 2.3 of 40 CFR Part 75, 

Appendix G, Revised March 19, 2012): 

(Eq. G-4) 

Where: 

W c02 ~ C02 emitted from combustion, tons/hr. 

MW C02 ~Molecular weight of carbon dioxide, 44.0 lbllb-mole. 

F, ~Carbon based F-factor, 1040 scf/mmBtu for natural gas; 1,420 scf/mmBtu 

for crude, residual, or distillate oil; and calculated according to the procedures in 

section 3.3 .5 of appendix F of 40 CFR, Part 75 for other gaseous fuels. 

H ~Hourly heat iuput in MMBtu, as calculated using the procedures in Section 5 

of Appendix F of 40 CFR, Part 75. 

u,~ 1/385 scf C02 /lb-mole at 14.7 psia and 68 °F. 

b. BACT emission limits are required for C02, only, since it is 99.9% of emissions. 

2. For the Auxiliary boiler. 

a. C02 emissions are limited to 9,512 tons C02/year on a 12-month rolling basis 

and the following equation: 

C02 (lb/MMBtu) ~ Efx (2.20462lb/kg) 

Page 6 of 16 
Where: 

Ef =Emission Factor for C02 in kg C02/MMBtu using specified values for 

natural gas fuel from Table C-1 of 40 CFR Part 98, Subpart C, Revised May 31, 

2013) 

b. BACT emission limits are required for C02, only, since it is 99.9% of emissions. 

3. For the Emergency generator. 

C02 emissions are limited to 59.3 tons C02/year on a 12-month rolling basis and 

the following equation: 

C02 (lb/MMBtu) = Efx (2.20462lb/kg) 

Where: 

Ef =Emission Factor for C02 in lb/MMBtu using specified values for Distillate 

Fuel Oil No.2 from Table C-1 of 40 CFR Part 98, Subpart C, Revised May 31, 

2013) 

b. BACT emission limits are required for C02, only, since it is 99.9% of emissions 

4. Sulfur hexafluoride (SF6l Electrical Breakers. 

a. Maintain fugitive emissions below 0.5% (by weight) of SF6 with state-of-the-art 

SF6 circuit breakers with leak detection and implementation of an LDAR 

program and density monitor alarm set to 4 psi drop. 

H. Pursuant to 40 CFR 60.4205(b ), the owner or operator of the emergency diesel engine, shall 

comply with the applicable emission standards. In accordance with 40 CFR 60.4205(b ), which 

references 40CFR 89.112 and 40 CFR 89.113, the emergency diesel engine's NMHC+ NOx 

emissions shall not exceed 6.4 g!kW-hr (4.8 g/hp-hr), CO emissions shall not exceed 3.5 g/kWhr (2.6 g!hp-hr), and PM emissions shall not exceed 0.2 g/kW-hr (0.15 g/hp-hr) over the life of 

the engine. The emergency diesel engine shall be certified by the manufacturer to meet these 

emission limits per 40 CFR 60.4202(a)(2). The owner or operator shall also meet the 

requirements of 40 CFR 60.4206. 

I. The facility shall comply with applicable requirements of 40 CFR Part 63 Subpart ZZZZ (refer 

to 40 CFR 63.6590(c)). If a conflict exists between the federal rule and the permit, requirements 

of the federal rule shall take precedent. 

J. Applicability of Federal Rule General Provisions. For the emergency diesel engine, 40 CFR 

60.4218 identifies the Subpart A requirements that are applicable. Empire shall also comply 

with Subpart A, as applicable, for Subparts KKKK and De. 

Page 7 of 16 
VI. Permit Conditions 

A. Startup and shutdown are defined as follows: 

1. Startup: The period from when the combined cycle unit (CT +HRSG) is started until 

reaching 50% of the combustion turbine (CT) load. The startup periods will be readily 

identifiable by the monitoring system. Such periods shall not exceed 8 hours. 

2. Shutdown: The period when the combined cycle unit (CT +HRSG) is shutting down from 

50% of combustion turbine (CT) load to 0% of combustion turbine (CT) load. The 

shutdown periods shall be readily identifiable by the monitoring system. Such periods 

shall not exceed 2 hours. 

B. The combined cycle unit (CT +HRSG) shall operate at load conditions between 50% of 

combustion turbine (CT) load and 100% of combined cycle unit (including HRSG and maximum 

duct burner firing capacity except during startup and shutdown. 

C. The combined cycle unit (CT +HRSG) shall use only natural gas as a fuel. 

D. The high efficiency drift eliminators for the Mechanical Draft Cooling Tower are an integral part 

of the design and shall function any time the cooling tower is in operation. 

E. Compliance with the PM/PM10PM25 BACT limit for the Mechanical Draft Cooling Tower shall 

be demonstrated by maintaining records of the vendor-guaranteed drift rate of 0.0005 percent of 

inlet flow. No chromium-based water treatment chemicals shall be used in the circulating water 

system and thus the requirements of 40 CFR Part 63, Subpart Q shall not apply. 

F. The emergency diesel engine shall burn only low sulfur diesel fuel oil that is ::S (less than or equal 

to) 15 ppm sulfur in accordance with 40 CFR 60.4207(b). 

G. Compliance with the PM/PM10/PM2.5 and C02e BACT limit for the emergency diesel engine is 

established by the BACT analysis and emissions calculations submitted with the permit 

application. 

H. The auxiliary boiler shall use only natural gas as a fuel. 

I. Compliance with the PM/PM101PM2 5 BACT limit for the auxiliary boiler is established by the 

BACT analysis and emissions calculations submitted with the permit application. 

J. Compliance with the C02e BACT limit for the combined cycle unit, including the combustion 

turbine and duct burners shall be demonstrated with an oxygen (02) concentration monitor in 

accordance with C02 calculations provided in 40 CFR Part 75. Calculations shall consist of C02 

emissions only, which account for 99.9% of total C02e emissions. 

K. Compliance with the PM/PM101PM25 BACT limit for the combined cycle unit shall be 

demonstrated with a performance test. 

Page 8 of 16 
L. Compliance with the C02e BACT limit for the auxiliary boiler shall be demonstrated by 

recording fuel usage and using emissions factors from Tables C-1 and C-2 of 40 CFR Part 98, 

Subpart C along with the Global Warming Potential Factors from Table A-1 of 40 CFR Part 98, 

Subpart A (as published in 74 FR 56374 on October 30, 2009) to determine resulting emissions 

on a monthly basis. Reports of excess emissions shall be submitted semi-annually. 

M. The SF6 Insulated Circuit Breakers shall continuously use a density (leak detection) alarm 

system on the SF 6 circuit breakers with a threshold of 10 percent. In the event of an alarm, the 

owner or operator shall immediately investigate the event and take an necessary corrective action 

to address any problems. 

N. Compliance with the C02e BACT limit for the SF 6 Insulated Circuit Breakers shall be 

demonstrated by calculating the annual mass emissions of SF 6 from the electrical breakers using 

an annual SF6 leak rate of 0.5% by weight and the Global Warming Potential Factor for SF6 from 

Table A-1 of 40 CFR Part 98, Subpart A (as published in 74 FR 56374 on October 30, 2009) to 

determine resulting emissions on a monthly basis. Reports of excess emissions shall be submitted 

semi-annually. 

0. 40 CFR Part 60 Subpart IIII- Requirements for the emergency diesel engine: 

1. For the emergency diesel engine, 40 CFR 60.4218 identifies the Subpart A requirements 

that are applicable. 

2. The owner or operator shall comply with applicable diesel fuel requirements of 40 CFR 

60.4207(b ). 

3. For the emergency diesel engine, the provisions of 40 CFR 60.4211(£) apply. 

Maintenance checks and readiness testing is limited to 100 hours per year, of which up to 

50 hours per year may be for non-emergency situations. There is no time limit on the use 

of the emergency diesel engine in emergency situations. 

4. The owner or operator shall comply with applicable requirements of 40 CFR Part 60 

Subpart IIII. If a conflict exists between the federal rule and the permit, the requirements 

of the federal rule shall take precedence. 

P. In accordance with 40 CFR Part 63 Subpart 40 CFR Part 63 Subpart DDDDD Industrial, 

Commercial, and Institutional Boilers and Process Heaters, the auxiliary boiler, firing solely 

natural gas, is subject to a work practice standard that requires an annual tune-up in lieu of 

emission limits. 

Q. Monitoring Requirements for Emergency Diesel Engine - If the emergency diesel engine does 

not meet the standards applicable to non-emergency engines, the owner or operator must install a 

non-resettable hour meter prior to startup of the engine, as specified in 40 CFR 60.4209. 

R. Empire shall permanently remove Unit 7 and Unit 8 from service when the Unit 12 combined 

cycle unit (CT +HRSG) begins commercial operation. 

Page 9 of 16 
VII. Performance Testing and Compliance 

A. Within 60 days after achieving a maximum production rate at which the combined cycle unit 

(CT +HRSG) will be operated, but not later than 180 days after initial start-up of the combined 

cycle unit, and every 5 years thereafter, the owner or operator shall conduct performance test(s) 

for PM, PM10, PM2.5 to demonstrate compliance with the applicable conditions and limitations 

set forth in this permit and furnish KDHE a written report of the results of such performance 

test(s). 

B. Within 60 days after achieving a maximum production rate at which the combined cycle unit 

(CT +HRSG) will be operated, but not later than 180 days after initial start-up of the combined 

cycle unit, the owner or operator shall conduct performance test for Sulfuric Acid Mist to 

demonstrate compliance with the estimated emission rates supplied in the permit application and 

furnish KDHE a written report of the results of such performance test 

C. In accordance with 40 CFR Part 60, Subpart KKKK, all continuous monitoring systems and 

monitoring devices required shall be installed and operational prior to conducting performance 

tests under 40 CFR 60.8. Verification of operational status, at a minimum, includes completion 

of the manufacturer's written requirements or recommendations for installation, operation, and 

calibration of the device as required by 40 CFR 60.13. 

D. In conducting the performance tests required by this permit, the reference test methods and 

procedures outlined in K.A.R. 28-19-212 and approved by KDHE, shall be used to demonstrate 

compliance with the limitation and conditions set forth in this permit 

D. For the emergency diesel engine, the owner or operator must install, configure, operate, and 

maintain the engine and control device according to the manufacturer's emission-related written 

instructions. The owner or operator must not change emission-related settings in a way that is not 

permitted by the manufacturer, or thereafter demonstrate compliance as specified at 40 CFR 

60.42ll(g)(3). 

E. Compliance with NOx emJssJon limits for the combined cycle unit (CT + HRSG) shall be 

demonstrated with a NOx continuous emission monitor (CEM) that follows the requirements 

listed in 40 CFR 60.4340(b). 

F. The N Ox CEM shall be installed, certified, operated, maintained, and quality assured m 

accordance with 40 CFR 60.4345. 

G. Compliance with S02 emission limits shall be demonstrated in accordance with the requirements 

in 40 CFR 60.4330 and 40 CFR 60.4360. 

Page 10 of 16 
H. Malfunction: The Owner or Operator must notify KDHE by telephone, facsimile, or electronic 

mail transmission within two (2) working days following the discovery of any failure of air 

pollution control equipment, process equipment, or of the failure of any process to operate in a 

normal manner which results in an increase in emission above the allowable emission limit stated 

in section "V. Air Emission Limitations" of this permit, a written notification shall be submitted 

within ten (10) days of the event. 

The written notification shall include a description of the malfunctioning equipment or abnormal 

operation, the date of the initial malfunction, the period of time over which emissions were 

increased due to the failure, the cause of the failure, the estimated resultant emissions in excess 

of those allowed in "Air Emission Limitations," and the methods utilized to mitigate emissions 

and restore normal operations. Compliance with this malfunction notification shall not 

automatically absolve the owner or operator of liability for the excess emissions resulting from 

such event. 

The following criteria will be used by KDHE to evaluate whether emissions from a malfunction 

are excluded in determining compliance with the emission rate contained herein: 

1. The excess emission were caused by a sudden, unavoidable breakdown of technology, 

beyond the control of the owner or operator; 

2. The excess emissions did not stem from any activity or event that could have been 

foreseen and avoided, or planned for, and could not have been avoided by better 

operation and maintenance practices; 

3. To the maximum extent practicable, the air pollution control equipment or processes 

were maintained and operated in a manner consistent with good practices for minimizing 

em!SS!Ons; 

4. Repairs were made in an expeditious fashion when the operator knew or should have 

known that applicable emission limitations were being exceeded. Off-shift labor and 

overtime must have been utilized, to the extent practicable, to ensure tbat such repairs 

were made as expeditiously as practicable. 

5. The amount and duration of the excess emissions (including any bypass) were minimized 

to the maximum extent practicable during periods of such emissions; 

6. All possible steps were taken to minimize tbe impact of the excess emissions on ambient 

air quality; 

7. All emission monitoring systems were kept in operation if at all possible; 

8. The owner or operator's actions in response to the excess emissions were documented by 

properly signed, contemporaneous operating logs, or other relevant evidence; 

9. The excess emissions were not part of a recurring pattern indicative of inadequate design, 

operation, or maintenance; and 

10. The owner or operator properly and promptly notified the appropriate regulatory 

authority. 

Page 11 of 16 
I. Stack parameters for all equipment listed under Section III, Air Emissions Unit Technical 

Specifications, which may include, but not limited to stack heights, stack diameters, exhaust 

temperatures, emission rates, and exit velocities, shall be consistent with data provided for the 

dispersion modeling analysis. Actual operational conditions shall be consistent with data 

provided for the dispersion modeling analysis. 

VIII. Recordkeeping 

A. The owner or operator of the combined cycle unit (CT +HRSG) shall maintain records of the 

occurrence and duration of any start-up, shut-down, or malfunction in the operation of the 

combined cycle unit (CT +HRSG); any malfunction of the air pollution control equipment; or any 

periods during which a continuous monitoring system or monitoring device is inoperative. These 

requirements are described in 40 CFR 60.7(b). 

B. As required under 40 CFR 60.7 (f), the owner or operator shall maintain a file of all 

measurements, including continuous monitoring system, monitoring device, and performance 

testing measurements; all continuous monitoring system performance evaluations; all continuous 

monitoring system or monitoring device calibration checks; adjustments and maintenance 

performed on these systems or devices; and all other information required by this part recorded 

in a permanent form suitable for inspection. The file shall be retained for at least two years 

following the date of such measurements, maintenance, reports, and records, with certain 

exceptions specified under 40 CFR 60.7(f). 

C. Reports of excess emissions shall be submitted semi-annually m accordance with the 

requirements in 40 CFR 60.7(c). 

D. Records shall be kept on site for two (2) years in accordance with 40 CFR 60.7(f). 

E. For the emergency diesel engine, the owner or operator must keep records of the emergency and 

non-emergency operations of the engine through a non-resettable hour meter if it does NOT meet 

the standards applicable to the non-emergency engines in the applicable model year. The times 

of operation and the reasons for operation must be recorded, as specified in 40 CFR 60.4214(b). 

F. A record shall be maintained demonstrating that the auxiliary boiler is in compliance with the 

particulate matter emission rate limit of Section V.C. Air Emission Limitations of this permit. 

After the initial evaluation, the particulate emission rate limitation shall be re-evaluated when 

either the process changes or an emission factor increases. 

G. In accordance with 40 CFR 60.7(b), the owner/operator shall keep records of the occurrence and 

duration of any start-up, shutdown or malfunction in the operation ofthe auxiliary boiler. 

H. In lieu of the daily record keeping requirements of 40 CFR 60.48c(g), the owner or operator shall 

record and maintain records of the amount of fuel combusted in the auxiliary boiler on a 

monthly basis. The records of the amounts of fuel burned can be maintained in the form of 

monthly fuel bills or meter readings, or other records that adequately document fuel usage. 

Page 12 of16 
I. In accordance with 40 CFR 60.48c(i), all of the required records shall be maintained by the 

owner or operator of the auxiliary boiler for a period of two years following the date of record. 

IX. Reporting 

Reports demonstrating compliance shall be submitted to the KDHE in the same units as stated in the 

applicable requirements. 

A. Items required to be reported semi-annually shall be submitted to KDHE and postmarked by the 

30th day following the end of each calendar half. 

B. Items required to be reported annually shall be submitted to KDHE and postmarked by the 30th 

day following the end of each calendar year. 

C. The combined cycle combustion unit (CT+HRSG) excess emissions and monitoring systems 

performance report and/or a summary report shall be submitted to the KDHE as required by 40 

CFR 60.7(c) on a semi-annual basis. The sunnnary report form shall contain the information and 

be in the format as specified in 40 CFR 60.7(d). One summary report form for NOx and one 

summary report form for the sulfur content of the fuel shall be submitted. Written reports of 

excess emissions shall include the following information: 

1. The magnitude of excess emissions computed in accordance with 40 CFR 60.13(h), any 

conversion factor( s) used, the date and time of commencement and completion of each 

time period of excess emissions, and the process operating time during the reporting 

period. 

2. Specific identification of each period of excess emissions that occurs during start-ups, 

shut-downs, and malfunctions, the nature and cause of any malfunction (if known), the 

corrective action taken or preventative measures adopted. 

3. The date and time identifying each period during which the continuous monitoring 

system was inoperative except for zero span checks and the nature of the system repairs 

and adjustments. 

4. When no excess emissions have occurred or the continuous monitoring system(s) have 

not been inoperative, repaired, or adjusted, such information shall be stated in the report. 

D. Reports required under Section IX. Reporting, Item C of this permit, periods of excess emissions 

as defined in 40 CFR 60.4350 shall be reported accordingly. 

E. The compliance demonstration for Section V. Air Emission Limitations, Item D, of this permit, 

shall be reported on an annual basis. 

Page 13 of 16 
F. If significant changes are made, or modeling parameters are not representative of site conditions, 

the owner or operator shall document compliance with the applicable NAAQS and allowable 

PSD increment consumption and submit documentation of compliance to KDHE prior to making 

the change(s). KDHE has final authority in determining what constitutes a significant change. If 

modeling indicates a potential NAAQS or increment exceedance, then mitigation shall be 

required. 

X. Notification 

A. The Air Quality Representative in the Southeast District Office shall be notified within 30 days 

of when installation of the equipment is complete so an evaluation may be conducted to verify 

compliance with applicable regulations. 

B. K.A.R. 28-19-720 (40 CFR 60.7(a) and 60.8(d) reqmres that written notifications of the 

following be submitted to KDHE: 

I. The date construction of the combined cycle unit (CT+HRSG), the auxiliary boiler and 

the emergency diesel generator are commenced. The notification is to be postmarked no 

less than 30 days after such date. 

2. The actual date of initial startup of the combined cycle unit (CT+HRSG), auxiliary boiler 

and emergency diesel generator. The notification is to be postmarked within 15 days 

after such date. 

3. The actual date the combined cycle unit (CT+HRSG) enters commercial operation and 

the date(s) Unit 7 and Unit 8 are removed from serv1ce. The notification is to be 

postmarked within 15 days after such date(s). 

4. The date when the initial performance testing of the combined cycle unit (CT +HRSG) is 

to commence. The notification is to be postmarked no less than 30 days prior to such 

date. 

5. The date upon which demonstration of the continuous monitoring system performance 

commences in accordance with 40 CFR 60.13(c). Notification shall be postmarked no 

less than 30 days prior to such date. 

C. Notification of the performance test shall include a performance test protocol which includes a 

description of the test and applicable test methods. Notification of the date(s) for performance 

testing shall be submitted to KDHE, postmarked at least 30 days prior to such date(s). 

Performance testing shall also be coordinated with the KDHE Bureau of Air, Compliance and 

Enforcement Section at 785-296-0243 at least 30 days prior to the date(s) of the test. 

Page 14 of 16 
D. At the time of permit issuance, the turbines are subject to 40 CFR Part 63, Subpart YYYY, 

however pursuant to 40 CFR 63.6095(d) there has been a stay of standards for gas-fired 

subcategories. Owners or operator of lean premix gas-fired stationary combustion turbines and 

diffusion flame gas-fired turbines must comply with the initial notification requirements set forth 

in 40 CFR 63.6145 but need not comply with any other requirement of 40 CFR Part 63 Subpart 

YYYY until EPA takes final action to require compliance and publishes a document in the 

Federal Register. [40 CFR 63.6095(d)] 

XI. General Provisions 

A. This document shall become void if construction, installation or modification to convert the 

existing Riverton 12 simple cycle combustion turbine to a combined cycle unit has not 

commenced within 18 months of the effective date of this permit, or if the construction, 

installation or modification to convert the simple cycle combustion turbine to a combined cycle 

unit is interrupted for a period of 18 months or longer. 

B. A construction permit or approval must be issued by KDHE prior to commencing any 

construction or modification of equipment or processes which result in an increase in potentialto-emit equal to or greater than the thresholds specified at K.A.R. 28-19-300. 

C. Upon presentation of credentials and other documents as may be required by law, the permittee 

shall allow a representative of the KDHE (including authorized contractors of the KDHE) to: 

I. enter upon the permittee's premises where a regulated facility or activity is located or 

conducted or where records must be kept under conditions of this document; 

2. have access to and copy, at reasonable times, any records that must be kept under 

conditions of this document; 

3. inspect at reasonable times, any facilities, equipment (including monitoring and control 

equipment), practices or operations regulated or required under this document; and 

4. sample or monitor, at reasonable times, for the purposes of assuring compliance with this 

document or as otherwise authorized by the Secretary of the KDHE, any substances or 

parameters at any location. 

D. The emission unit or stationary source which is the subject of this document shall be operated in 

compliance with all applicable requirements of the Kansas Air Quality Act and the Federal Clean 

Air Act. 

E. This document is subject to periodic review and amendment as deemed necessary to fulfill the 

intent and purpose of the Kansas Air Quality Statutes and Regulations and rules promulgated in 

accordance therewith. 

Page 15 of 16 
F. This document does not relieve the permittee of the obligation to obtain other approvals, permits, 

licenses or documents of sanction which may be required by other federal, state or local 

government agencies. 

G. Issuance of this document does not relieve the owner or operator of any requirement to obtain an 

air quality operating permit under any applicable provision ofK.A.R. 28-19-500. 

Permit Engineer 

$:::&= 

Environmental Engineer 

Air Permits Section 

LDL:lv 

c: SEDO 

C-10913 

Date Signed 

Page 16 of 16 
PSD AIR CONSTRUCTION PERMIT APPLICATION

ADDENDUM – GREENHOUSE GAS

BACT ANALYSIS

Riverton Facility

Unit 12 Conversion to Combined Cycle

Project

B&V PROJECT NO. 176883

PREPARED FOR

Empire District Electric Company

MARCH 2013

®

®

©Black & Veatch Holding Company 2012. All rights reserved.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Table of Contents i

Table of Contents

Acronym List ........................................................................................................................................................... 1

1.0 Introduction.......................................................................................................................................... 1-1

2.0 Greenhouse GasBACT Basis ............................................................................................................ 2-1

3.0 Combined Cycle Combustion Turbine ......................................................................................... 3-1

3.1 Step 1 – Identify All Control Technologies ................................................................................ 3-1

3.1.1 Carbon Capture and Storage ........................................................................................ 3-1

3.1.2 Inherently Lower Emitting Process and Practices.............................................. 3-3

3.2 Step 2 – Eliminate Technically Infeasible Options ................................................................. 3-5

3.2.1 Carbon Capture and Storage ........................................................................................ 3-5

3.2.2 Inherently Lower Emitting Process and Practices.............................................. 3-6

3.3 Step 3 – Rank Remaining Control Technologies by Control Effectiveness .................. 3-7

3.4 Step 4 – Evaluate Most Effective Controls ................................................................................. 3-7

3.4.1 Carbon Capture and Storage ........................................................................................ 3-8

3.4.2 Inherently Lower Emitting Process and Practices.............................................. 3-9

3.5 Step 5 – Select BACT........................................................................................................................... 3-9

3.5.1 Proposed CCCT BACT Emission Limit....................................................................3-10

3.5.2 Proposed Compliance Monitoring ...........................................................................3-10

4.0 Auxiliary Boiler.................................................................................................................................... 4-1

5.0 Emergency Diesel Generator .......................................................................................................... 5-1

6.0 SF6 Insulated Circuit Breakers........................................................................................................ 6-1

6.1 Step 1--Identify All Control Technologies.................................................................................. 6-1

6.2 Step 2--Eliminate Technically Infeasible Options................................................................... 6-1

6.3 Step 3--Rank Remaining Control Technologies by Control Effectiveness.................... 6-1

6.4 Step 4--Evaluate Most Effective Controls................................................................................... 6-1

6.5 Step 5--Select BACT............................................................................................................................. 6-1

7.0 Suggested Permit Conditions.......................................................................................................... 7-1

Appendix A. GHG Emission Calculations................................................................................................A-1

LIST OF TABLES

Table 3-1 Estimated Costs for Post-combustion CCS ................................................................................ 3-9
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Acronym List AL-1

Acronym List

BACT Best Available Control Technology

BHP Break horsepower

Btu British Thermal Unit

CAA Clean Air Act Amendments of 1990

CCCT Combined cycle combustion turbine

CCS Carbon capture and storage

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent

ECBMR Enhanced Coal Bed Methane Recovery

Empire District Empire District Electric Company

EOR Enhanced Oil Recovery

GHG Greenhouse Gas

GWP Global Warming Potential

HRSG Heat recovery steam generator

IGCC Integrated Gasification Combined Cycle

KDHE Kansas Department of Health and Environment

kW Kilowatt

kWh Kilowatt-hour

LDAR Leak Detection and Repair

LSFO Low Sulfur Fuel Oil

MEA Monoethanolamine

MMBtu Million British Thermal Units

MW Megawatt

MWh Megawatt-hour

NSPS New Source Performance Standard

PSD Prevention of Significant Deterioration

RBLC RACT/BACT/LAER Clearinghouse
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Introduction 1-1

1.0 Introduction

On January 25, 2013, Empire District Electric Company (Empire District) submitted the 

Riverton Unit 12 Conversion to Combined Cycle Project Prevention of Significant Deterioration 

(PSD) Air Permit Application to the Kansas Department of Health and Environment (KDHE). That 

application document indicated the conversion of Unit 12 from simple cycle to combined cycle 

operation would trigger PSD permitting for PM/PM10/PM2.5 and Greenhouse Gases (GHGs). 

Accordingly, these pollutants are subject to full PSD review including the requirements to address 

Best Available Control Technology (BACT), impacts upon ambient air quality, as well as impacts 

upon area growth, soils, vegetation, and visibility. As such, Empire District is submitting this 

Addendum to the PSD Air Permit Application to address BACT for GHGs. Additional addendums 

will address the remaining PSD elements mentioned above.

As discussed in the PSD Air Permit Application document, the Project consists of the 

following GHG emission sources:

 Conversion of the existing Unit 12 natural gas-fired simple cycle combustion turbine 

to combine cycle operation with natural gas-fired duct burners in the Heat Recovery 

Steam Generator (HRSG)

 New natural gas-fired auxiliary boiler 

 New emergency diesel generator

 Two new circuit breakers

GHG emissions calculations for each of the above listed sources can be found in Appendix A.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Greenhouse Gas BACT Basis 2-1

2.0 Greenhouse Gas BACT Basis

 The Clean Air Act Amendments of 1990 (CAA) established revised conditions for the 

approval of pre-construction permit applications under the PSD program. One of these 

requirements is that BACT be installed to control all pollutants regulated under the Act that are 

emitted in significant amounts from new major sources or major modifications. BACT need not 

necessarily result in an emissions control device. Rather, BACT is an emission limitation made on a 

case-by-case basis accounting for several project-specific factors. However, in no case is BACT 

allowed to be less stringent than the emissions limits established by an applicable New Source 

Performance Standard (NSPS).

EPA announced its final “PSD Tailoring” rule on May 13, 2010 which established GHG 

emission thresholds for triggering major source PSD permitting requirements including an 

evaluation of BACT. The emission thresholds, 100,000 for new sources and 75,000 for increases 

from modifications of existing sources measured in tons per year (tpy) of carbon dioxide equivalent 

(CO2e) – took effect in 2011. 

As required under the NSR/PSD regulations, the BACT analysis presented herein employed 

the EPA-preferred “top-down,” five-step analysis process to determine the appropriate emission 

control technologies and/or emissions limitations for the Project:

 Step 1--Identify All Control Technologies

 Step 2--Eliminate Technically Infeasible Options

 Step 3--Rank Remaining Control Technologies by Control Effectiveness

 Step 4--Evaluate Most Effective Controls

 Step 5--Select BACT

The following sections present the GHGBACT analysis conducted for the Unit 12 converted 

combined cycle combustion turbine (CCCT), as well as the new auxiliary boiler, emergency diesel 

generator, and circuit breakers. This GHG BACT analysis utilizes information from various 

reference and research documents developed by or for various government entities including the 

USEPA, the Department of Energy’s National Energy Technology Laboratory, and the Interagency 

Task Force on CCS to name a few. It also relies upon information provided in a recent (August 

2012) Statement of Basis developed by USEPA Region 6 for a natural gas-fired CCCT in Texas where 

Region 6 remains the permitting authority for GHGs. Information from these and other sources of 

data are referenced throughout this application as footnote entries.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-1

3.0 Combined Cycle Combustion Turbine

3.1 STEP 1 – IDENTIFY ALL CONTROL TECHNOLOGIES

The first step in a top-down analysis is to identify all available control options for the 

emission unit in question. Identifying all the potential available control options consists of those air 

pollution control technologies or techniques with a practical potential for application to the 

emission unit and the regulated pollutant under evaluation. The potential available control 

technologies and techniques may include lower emitting processes and practices, as well as postcombustion controls. Lower emitting practices can include fuel cleaning, treatment, or innovative 

fuel combustion techniques such as pre-combustion or oxy-combustion controls. 

 Available CO2 control techniques include carbon capture and storage (CCS) and inherently 

lower emitting process and practices via energy efficient designs. The inherently lower emitting

processes and practices can be evaluated for the proposed Project (including the combustion 

turbine and HRSG), as well as on a plant-wide basis. While this analysis will evaluate such 

processes and practices for the existing combustion turbine and the new HRSG, it will not focus on 

plant-wide aspects which the USEPA states in its March 2011 guidance was intended for new 

facilities which have more opportunity to consider such efficiency improvements during 

development than does an existing generating facility which should focus only upon the emitting 

unit(s) being modified.1

3.1.1 Carbon Capture and Storage

As for CCS, the USEPA, in the same March 2011 guidance document, classifies CCS as an 

“add-on pollution control technology that is “available” for facilities emitting CO2 in large amounts, 

including fossil fuel-fired power plants, and for industrial facilities with high-purity CO2 streams 

(e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, 

ethylene oxide production, cement production, and iron and steel manufacturing).” The USEPA 

believes that it is a technology that warrants initial consideration and should not necessarily be 

eliminated in Step 1, but rather should be evaluated based on technical feasibility and costs. If CCS 

is to be eliminated during subsequent BACT steps, then it should be done so on record of 

evaluation.2

CCS involves separating and capturing CO2 from an emission unit’s flue gas, pressurizing the 

captured CO2 and finally transporting the compressed CO2 for injection into an available geologic 

storage structure. There are generally three primary technologies for CO2 capture: pre-combustion, 

post-combustion, and oxy-combustion.

 This GHG BACT will serve as that record of evaluation.

3, 4

 Pre-combustion Capture

 1 USEPA, PSD and Title V Permitting Guidance for Greenhouse Gases, EPA-457/B-11-001 (March 2011), 30.

– Typically used in Integrated Gasification Combined Cycle 

(IGCC) power plants and other industrial facilities, pre-combustion capture 

2 USEPA, 32-33. 3 DOE/NETL, Advanced Carbon Dioxide Capture R&D Program Accomplishments (April 2012), 2-5. 4 Intergovernmental Panel on Climate Change, Carbon Dioxide Capture and Storage (2005), 25.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-2

processes the primary fuel in a reactor with steam and air or oxygen to produce a 

mixture consisting mainly of CO and hydrogen called a synthesis gas. It then 

requires the CO be shifted to CO2 before being separated from the hydrogen leaving 

a pure hydrogen stream to be used as the fuel.

 Post-combustion Capture –Primarily being developed for conventional coal-fired 

power plants (but there is no reason it would not be adaptable to CCCT plants), 

post-combustion capture refers to removal of CO2 in the flue gas just prior to 

discharge to the atmosphere. Several post-combustion processes are in various 

stages of development including absorption, adsorption, and gas separation 

membrane technologies. The most widely used of these technologies (and the only 

one that is commercially available) is absorption which uses amine or 

monoethanolamine (MEA)-based solvents5



to chemically separate CO2 from other 

flue gases.

Oxy-combustion Capture

Once captured, CO2 must be pressurized for injection into a pipeline or other shipping 

container in order to be transported for ultimate sequestration such as injection into an available 

geologic storage structure. The following provides a list of transportation and storage options in 

various stages of research or development

- Primarily being developed for pulverized coal-fired 

power plants, oxy-combustion capture uses oxygen instead of air (upstream 

separation required) for combustion of the fuel to produce an exhaust stream that is 

mainly water and CO2. Additional purification of the CO2 stream may be required to 

meet pipeline and storage requirements. 

6

 Transportation

:

● Pipeline

● Shipping

 Underground Geological Storage

● Oil/gas fields (either abandoned fields or for enhanced oil recovery (EOR) in 

active fields)

● Saline formations

● Unminable coal seams (with potential for enhanced coal bed methane 

recovery (ECBMR))

● Other geologic media including basalts, oil or gas-rich shale, salt caverns, 

and abandoned mines (all offer small niche options for storage)

 Oceanic Storage

 Mineral Carbonation

 Industrial Uses of CO2

 5 USEPA Region 6, Statement of Basis – Greenhouse Gas Prevention of Significant Deterioration Preconstruction 

Permit for the Calpine Corporation, Deer Park Energy Center (DPEC), LLC (August 2012), 8. 6 Intergovernmental Panel on Climate Change, 215-220, 279, 321.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-3

While there are various methods of transport and storage, any discussion providing further 

details of these options is rather inconsequential unless and until the remaining steps of this GHG 

BACT analysis prove CO2 capture is warranted (i.e., the technology is available, cost-effective, and 

has no significant energy or other environmental impacts that would otherwise preclude its use). 

Such factors for the capture component of CCS are further evaluated in Step 4 of the GHG BACT. 

The USEPA applies this same approach in its March 2011 GHG guidance document wherein the 

agency recognizes that it is not necessary to provide a detailed evaluation of every step of the CCS

process if one part of the process warrants eliminating the control technology (e.g., if 

transportation of CO2 is cost-prohibitive there is no need to continue the analysis and provide cost 

information for CO2 capture).7

3.1.2 Inherently Lower Emitting Process and Practices

As mentioned previously, the USEPA through various guidance documents indicates that 

inherently lower-polluting processes are appropriate for consideration as available control 

alternatives. In doing so, however, the agency has recognized that a Step 1 list of options need not 

necessarily include inherently lower polluting processes that would fundamentally redefine the 

nature of the source proposed by the permit applicant. 8

According to the USEPA, inherently lower emitting processes and practices include 

methods, techniques, and systems designed to increase energy efficiency and can be classified into 

two categories: 1) technologies or processes that maximize the energy efficiency of the individual 

emissions unit and 2) those that maximize the energy efficiency across the entire facility. As 

discussed previously, and per USEPA guidance, energy efficiency improvements shall be limited to 

the modified and proposed new emissions sources and will not reach out plant-wide as is more 

appropriate for the construction of new facility.

 Given the USEPA’s stance on not allowing 

inherently lower emitting processes and practices to redefine the source and the fact that the 

Project consists of converting an existing simple cycle combustion turbine to combined cycle (i.e., 

not installing a new emissions source, but rather modifying an existing one), the inherently lower 

emitting processes and practices will be limited to those process and practices that can be 

undertaken on the modified combustion turbine and new HRSG. 

9

The Project by its shear nature is designed to increase the efficiency of Unit 12 by 

converting it from simple cycle to combined cycle thereby capturing waste heat and converting it to 

useful energy that would otherwise be lost out of the stack. Generally speaking energy efficiency 

can increase from 30 percent for simple cycle turbines to 50 percent for combined cycle operation. 

While the conversion will make Unit 12 much more efficient, there are other design processes and 

operating practices that can further improve and assist to maintain the unit’s energy efficiency. 

Based on Black & Veatch’s knowledge of power plant design and operation, as well as other GHG 

 7 USEPA, 42.

8 USEPA, 24.

9 USEPA, 29-30.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-4

permits and permit applications for similar natural gas-fired CCCTs10, 11



, the following inherently 

lower emitting processes and practices are presented as available GHG control technologies/energy 

efficiency measures:

Periodic Maintenance and Tuning



– Follow manufacturer recommendations 

regarding inspection and maintenance activities to maintain/restore optimal 

efficiency.

Reduce Heat Losses



– Install insulation on both the steam turbine and HRSG 

components to minimize heat loss thereby increasing energy efficiency via heat 

recovery. In addition, the HRSG stack will have a damper and insulation below the 

damper to minimize heat loss during shutdowns thereby reducing startup times.

Instrumentation and Controls



– Employ the use of the latest computer-based control 

systems (including upgrade of present combustion turbine control system) to 

monitor and optimize fuel and air flows which optimizes combustion operations 

thereby producing the maximum amount of power for the least amount of fuel 

burned while maintaining emissions performance over a range of load and ambient 

temperature conditions.

Steam Cycle Efficiency



–Employ a reheat steam cycle with high steam temperatures 

to increase the amount of power generated from the recovered waste heat.

Heat Exchanger Design



– Select a design which optimizes waste heat transfer from 

the combustion turbine exhaust gas while minimizing corrosion at the outlet of the 

HRSG.

Minimize Fouling of Heat Exchanger Surfaces



– Employ inlet air filtering, proper 

feed water chemistry, and tube surface cleaning practices to minimize fouling of the 

heat exchange surfaces and maintain the maximum waste heat exchange between 

the combustion turbine exhaust gas and the HRSG thereby maintaining/restoring 

optimal efficiency.

Reduce Steam Losses



– Follow an inspection routine that checks for and repairs 

steam leaks from valve, flanges, and piping to maintain/restore optimal efficiency.

Use of “Clean Fuels” 

 10 USEPA Region 6,, 10-13.

– Natural gas has the lowest carbon content of any fossil fuel 

and will be utilized in both the combustion turbine and HRSG. While the USEPA 

does include the use of “clean fuels” in the definition of BACT, and other fuels (such 

as hydrogen and bio-fuels) do exist that would produce little to no net CO2

emissions, the agency has stated that the initial list of control options for a BACT 

analysis does not need to include “clean fuel” options that would fundamentally 

redefine the source including those that would require a permit applicant to switch 

to a primary fuel type (i.e., coal, natural gas, or biomass) other than the type of fuel 

11 NRG Texas Power LLC, Application for PSD Air Quality Permit Greenhouse Gas Emissions Unit 5, S.R. Bertron 

Generating Station, Laporte, Harris County, Texas (November 26, 2012), 6-3, 6-4.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-5

that an applicant proposes to use for its primary combustion process.12

3.2 STEP 2 – ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

 Unit 12 is 

currently designed and permitted to burn natural gas (the lowest carbon content 

fossil fuel available) and will continue to do so after the conversion to combined 

cycle.

The second step of the top-down analysis is to identify the technical feasibility of the control 

options identified in Step 1, which are evaluated with respect to source-specific factors. A control 

option that is determined to be technically infeasible is eliminated. “Technically infeasible” is 

defined as a clearly documented case of a control option that has technical difficulties that would 

preclude the successful use of the control option because of physical, chemical, and engineering 

principles. After completion of this step, technically infeasible options are then eliminated from the 

BACT review process. 

Conversely in Step 2, the control option may be identified as technically feasible. A 

“technically feasible” control option is defined as a control technology that has been installed and 

operated successfully at a similar type of source of comparable size under review (demonstrated). 

If the control option cannot be demonstrated, the analysis gets more involved. When determining if 

a control option has not been demonstrated, two key concepts need to be analyzed. The first 

concept, “availability,” is defined as technology that can be obtained through commercial channels 

or is otherwise available within the common sense meaning of the term. A technology that is being 

offered commercially by vendors or is in licensing and commercial demonstration is deemed an 

available technology. Technologies that are in development (concept stage/research and 

patenting) and testing stages (bench-scale/laboratory testing/pilot scale testing) are classified as 

not available. The second concept, “applicability,” is defined as an available control option that can 

reasonably be installed and operated on the source type under consideration. In summary, the 

commercially available technology is applicable if it has been previously installed and operated at a 

similar type of source of comparable size, or a source with similar gas stream characteristics.

3.2.1 Carbon Capture and Storage

While many of the CO2 capture technologies discussed previously are at various stages of 

bench or pilot scale deployments, and none to-date have been applied to full-scale natural gas-fired 

power generation, the USEPA has indicated that CCS should be evaluated beyond technical 

feasibility. As such, this analysis will continue under the assumption that post-combustion capture 

using absorption technology such as amine/MEA is technically feasible while other capture 

technologies including pre-combustion and oxy-combustion are not. These other technologies are 

infeasible because they have not to-date been applied at the appropriate scale (e.g., postcombustion adsorption or gas separation membrane technologies); or because they would 

fundamentally redefine the source (e.g., pre-combustion and oxy-combustion) by either requiring 

 12 USEPA, 27.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-6

new combustion units capable of combusting low CO2 fuels (such as hydrogen) of which the existing 

unit is not capable. This is commensurate with other recent GHG BACT determinations made by the 

USEPA for similar natural gas fired generation technologies.13 The non-commercial availability of 

these technologies is further evidenced by DOE/NETL research as recent as 2011 which confirms 

that commercial CO2 capture technology for large-scale power plants is not yet available and 

indicates that it may take until 2020 to become so. 14

CO2 transportation via pipeline and shipping is considered technically feasible as these are 

the primary transportation methodologies utilized for compressed CO2 today for many industrial 

applications (pipelines more so than shipping). In fact, a pipeline is currently under construction in 

southeast Kansas which will transport CO2 from a fertilizer plant in Coffeyville, KS to Burbank, OK 

for EOR15 making it the nearest CO2 pipeline to Riverton according to the National Energy 

Technology Laboratory.16

CO2 storage is also considered technically feasible since such practices with respect to EOR 

have been used for decades (although of concern today is the permanent sequestration of the CO2

once it has done the EOR). Other potential storage options such as gas/oil fields and saline 

formations are currently being evaluated across the United States including Kansas. However, 

these are still in the research and development stage17

3.2.2 Inherently Lower Emitting Process and Practices

and are not yet commercially available. All 

other storage options listed in Section 3.1.1 are still in the research and development phase with 

small scale bench and pilot scale deployment and as such are considered infeasible. Regardless of 

whether various storage options are feasible or not, including the distance a pipeline must traverse 

to find a suitable storage solution, CO2 capture must still first prove economical before any more 

detailed consideration of storage options is warranted. A discussion of such economic 

consideration for CO2 capture is provided in Section 3.4.

With the exception of the use of low carbon content fuels other than natural gas, all of the 

energy efficiency improvements discussed in Section 3.1.2 are commonly utilized in CCCT facilities 

across the country and are thus considered feasible.

 13 USEPA Region 6, 13. 14 DOE/NETL, Carbon Sequestration Program: Technology Program Plan (February 2011), 10. 15 Walton, Rod. “Chaparral Energy to pipe CO2 to help extract Osage County oil,” Tulsa World, December 26, 2012, 

http://www.tulsaworld.com/business/article.aspx?subjectid=49&articleid=20121226_49_A16_CUTLIN234763. 16 NETL. “Carbon Storage.” http://www.netl.doe.gov/technologies/carbon_seq/FAQs/carboncapture3.html

(Accessed March 7, 2013).

17 Graff, Trevor. "Kansas Geological Survey begins testing for CO2 underground," The University Daily Kansan, 

September 12, 2012, http://kansan.com/news/2012/09/12/kansas-geological-survey-begins-testing-for-co2-

storage-in-underground-saline-reservoirs/?print=26693005342.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-7

3.3 STEP 3 – RANK REMAINING CONTROL TECHNOLOGIES BY CONTROL 

EFFECTIVENESS

The third step of the top-down analysis is to rank all the remaining control alternatives not 

eliminated in Step 2, based on control effectiveness for the pollutant under review. If the BACT 

analysis proposes the top control alternative, there would be no need to provide cost and other 

detailed information in regard to other control options that would provide less control. Otherwise, 

the analysis should proceed to Step 4. 

The following list ranks the remaining control technologies not eliminated in Step 2 (listed

in order of greatest control to least control):

 Carbon Capture and Storage – Post-combustion capture using absorption techniques 

such as amine/MEA are generally capable of 85 to 90 percent CO2 reduction.

 Conversion to Combined Cycle Operation – Inherent in the project design Unit 12 

will experience an efficiency improvement by implementing waste heat recovery via 

installation of an HRSG for combined cycle operation. Increases in thermal 

efficiency from around 30 percent for simple cycle operation to 50 percent for 

combined cycle operation are typical; resulting in approximately 40 percent 

reduction in GHG emissions.

 Inherently Lower Emitting Process and Practices – While not readily quantifiable, 

the measures listed in Section 3.1.2 will provide additional efficiency improvements 

to the converted CCCT.

3.4 STEP 4 – EVALUATE MOST EFFECTIVE CONTROLS

 Once the control effectiveness is established in Step 3 for all the feasible control 

technologies identified in Step 2, additional evaluations of each technology are performed to make a 

BACT determination in Step 4. The impacts of the technology implementation on the viability of the 

control technology at the source are evaluated. The evaluation process of these impacts is also 

known as an “Impact Analysis.” The following impact analyses may be performed:

 Energy evaluation of alternatives

 Environmental evaluation of alternatives

 Economic evaluation of alternatives

The first impact analysis addresses the energy evaluation of alternatives. The energy 

impact of each evaluated control technology is the energy penalty or benefit resulting from the 

operation of the control technology at the source. Direct energy impacts include such items as the 

auxiliary power consumption of the control technology and the additional draft system power 

consumption to overcome the additional system resistance of the control technology in the flue gas 

flow path. The costs of these energy impacts are defined either in additional fuel costs or the cost of 

lost generation, which impacts the cost-effectiveness of the control technology. 

The second impact analysis addresses the environmental evaluation of alternatives. Nonair quality environmental impacts are evaluated to determine the cost to mitigate the 

environmental impacts caused by the operation of a control technology. Examples of non-air 
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-8

quality environmental impacts include polluted water discharge and solids or waste generation. 

The procedure for conducting this analysis should be based on a consideration of site-specific 

circumstances. 

The third and final impact analysis addresses the economic evaluation of alternatives. This 

analysis is performed to indicate the cost to purchase and operate the control technology. 

Information should be obtained from established sources that can be referenced. The estimated 

cost of control is represented as an annualized cost ($/year) and, with the estimated quantity of 

pollutant removed (tons/year), the cost-effectiveness ($/tons) of the control technology is 

determined. The cost-effectiveness describes the potential to achieve the required emissions 

reduction in the most economical way. The cost-effectiveness compares the potential technologies 

on an economical basis. 

3.4.1 Carbon Capture and Storage

The addition of CCS to a power generation facility will have negative energy and 

environmental impacts upon the plant and its surroundings. Auxiliary power is required to operate 

the CO2 capture technologies thereby decreasing the net electrical output of the plant and reducing 

net plant efficiency; auxiliary power is also required for CO2 compression. Studies estimate that use 

of CCS at a power generating facility could decrease power generating capacity by as much as one 

third and net plant efficiency by 7 to 10 percent depending on the type of facility.18 Additionally, to 

meet the facility’s power output requirements, additional/larger combustion sources would need to 

be installed at the plant or replacement power sourced from the grid ultimately resulting in 

additional GHG emissions (as well as traditional criteria pollutants) per MW of generation. As for 

negative environmental impacts, the addition of amine or MEA post-combustion CCS would require 

significant additional water usage and land resources 19

The biggest detractor to installation of a CCS system, however, is the cost. The majority of 

the cost associated with CCS is due to the post-combustion capture and compression system. Costs 

for post-combustion CO2 capture, transport, and storage are shown in Table 3-1. As illustrated in 

Table 3-1, the cost of CO2 capture is approximately $95 per ton of CO2 removed (without 

transportation and storage which are small comparatively) which is not cost effective. In fact, this 

equates to an annualized cost of approximately $88 million for installation and operation of CCS. 

Research done by the government’s Interagency Task Force indicates that adding carbon capture to 

a 550 MW reference natural gas fired CCCT would increase capital cost by $340 million.

, as well as amine emissions from the stack 

and a solid/sludge waste from the cleanup of the amine solution.

20

 18 DOE/NETL, Advanced..., 6.

 Scaling 

this data to the appropriate size for Unit 12 would indicate an increase in capital cost of 

approximately $211 million which would more than double currently estimated capital cost of the 

Project without CO2 capture. The research further indicates the unit could experience as much as a 

19 DOE/USEPA (Co-task Force Leaders), Report of the Interagency Task Force Carbon Capture and Storage (August 

2010), 35.

20 DOE/USEPA, 33.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-9

57 percent increase in cost of electricity ($/MWh) by adding CCS.21

Table 3-1 Estimated Costs for Post-combustion CCS

Therefore, based on the 

evaluation of negative energy, environmental, and economic impacts assessed here, CCS shall not be 

considered BACT for the Project

CCS COMPONENT

COST OF 

CONTROL

($/TON CO2

REMOVED)1

CO2 REMOVED 

PER YEAR

(TONS)2

TOTAL 

ANNUALIZED COST

($)

Capture and Compression $95 919593 $87,361,335

Transport3 $0.91/100 km 919,593 at 80 km $669,464

Storage $0.51 919,593 $468,992

Total CCS Costs $96.24 919,593 $88,499,791

Project Modification Cost Total Capital Cost Capital Recovery Factor Annualized Capital Cost

Cost Comparison without CCS $140,000,000 0.1099 $15,386,000

Notes:

1. Cost values are from DOE/USEPA (Co-task Force Leaders), Report of the Interagency Task Force Carbon Capture and 

Storage (August 2010), 34, 37, 44. Where ranges of values were given, the lowest bound was conservatively used. 

Capture and compression cost data includes all costs over the generating system’s lifetime: initial investment, 

operations and maintenance, cost of fuel, and cost of capital. All cost data was converted from $/tonne to $/ton.

2. Project-specific CO2 emission information is derived from calculations presented in Appendix A for the CCCT 

(combustion turbine plus HRSG) assuming a 90 percent control for post-combustion capture.

3. Pipeline length was selected based on distance (as the crow flies) from Riverton, KS to Coffeyville, KS, the site of the 

nearest pipeline (currently under construction) assuming the pipeline could accommodate additional CO2 which it may 

not thereby requiring an even longer pipeline for this Project.

3.4.2 Inherently Lower Emitting Process and Practices

The remaining control technologies (heat recovery and good combustion practices

including energy efficiency improvements), however, have no appreciable negative energy or 

environmental impacts and are considered cost effective for implementation. Therefore, they will 

not be eliminated here and will continue on to Step 5.

3.5 STEP 5 – SELECT BACT

The highest ranked control technology that is not eliminated in Step 4 is proposed as the 

BACT for the pollutant and emission unit under review. In addition to the conversion of Unit 12 

from simple cycle to a more efficient combined cycle operation (a more than 30 percent 

 21 Ibid.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3-10

improvement in heat rate), the following good combustion practices to promote energy efficiency 

are proposed as GHG BACT:

 Follow manufacturer recommendations regarding inspection and maintenance 

activities to maintain efficiency.

 Install insulation on both the steam turbine and HRSG components to minimize heat 

loss. In addition, the HRSG stack shall have a damper and insulation below the 

damper to minimize heat loss.

 Employ the use of the latest computer-based control systems (including upgrade of 

present combustion turbine control system) to monitor and optimize fuel and air 

flows.

 Select a steam turbine and HRSG design that maximizes efficiency while meeting 

Empire District’s needs.

 Clean heat exchanger surfaces as needed.

3.5.1 Proposed CCCT BACT Emission Limit

BACT for the converted CCCT is good combustion practices including selected energy 

efficiency measures which are proposed to be made enforceable with an annual ton per year BACT 

limit. The USEPA in its GHG guidance has recommended that because the environmental concern 

with GHG emissions is their cumulative impact upon the environment, emission limitations should 

focus on longer-term averages (e.g., 12-month or 365-day rolling average) rather than short-term 

averages.22

3.5.2 Proposed Compliance Monitoring

As such, Empire District proposes an annual CO2 emission limit of 1,021,770 tons per 

year on a 12-month rolling average basis. The limit is proposed as CO2 which accounts for 99.9 

percent of total CO2e emissions.

Empire District proposes to continue its current CO2 monitoring methodology by 

determining the CO2 mass emissions using an oxygen (O2) concentration monitor in accordance 

with 40 CFR Part 75. Appropriate formulas and F and Fc (carbon-based) fuel factors found in 40 

CFR Part 75 are used in combination with the oxygen monitor data (which meets the quality 

assurance requirements listed in 40 CFR Part 75) to determine the mass-based CO2 emissions. This 

method is consistent with the CO2 reporting requirements of 40 CFR 98, Subpart D – GHG 

Mandatory Reporting Rule for Electricity Generation.

 22 USEPA, 46.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Auxiliary Boiler 4-1

4.0 Auxiliary Boiler

The 18.6 MMBtu/hr auxiliary boiler will be fired exclusively on natural gas. Given the small 

size of this unit, the fact that it is already proposed to burn natural gas (the lowest carbon-content 

fossil fuel available), and the only true identified GHG control measures are CCS and good 

combustion practices to promote energy efficiency, there is no reason to believe that the outcome 

for GHG BACT for the auxiliary boiler will have a different result than that for the combustion 

turbine. Specifically, CCS has been ruled out as BACT based on cost and other negative impacts, 

leaving only general design and operational practices remaining to maximize and maintain energy

efficiency thereby minimizing GHGs to the most practicable extent possible. Therefore, the full 5-

step top-down BACT approach is not presented again here as Empire District proposes to select the 

top control technologies presented below available to small natural gas-fired boilers such as the 

one proposed herein.

Empire District proposes the following good combustion practices as BACT for the auxiliary 

boiler:

Selection of BACT and Compliance

 Boiler Design



– Employ an efficient boiler design that meets Empire’s needs using 

efficient burners and proper insulation materials in the boiler components to 

minimize heat losses thereby increasing efficiency.

Periodic Boiler Tune-ups



– Follow manufacturer recommendations regarding 

inspection and maintenance activities including cleaning burners and convection 

tubes as needed to maintain efficiency.

Air and Fuel Flow Adjustments

Empire District proposes to limit the CO2 emissions from the auxiliary boiler on an annual 

basis to 9,512 tpy (annual averaging period) with compliance demonstrated by recording fuel 

usage and using emission factors presented in Appendix A of this BACT analysis to determine 

resulting emissions. Detailed GHG emission calculations for the auxiliary boiler are provided in 

Attachment A.

– Manually adjust flows to maximize combustion 

(automated controls were assumed to not be warranted given the small size of the 

boiler and the fact that the magnitude of CO2e emissions from the boiler is less than 

1 percent of the CO2e emissions from the CCCT).
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Emergency Diesel Generator 5-1

5.0 Emergency Diesel Generator

The exact capacity of the emergency diesel generator has not yet been determined, but for 

permitting purposes, Empire District has assumed the capacity to be 1,102 break horsepower 

(BHP) or 750 kW electrical output. Because of its small size, infrequent operation, and status as 

emergency equipment, GHG emissions from this unit will be insignificant at an estimated 59 tpy. 

Also, there are no pre-combustion or post-combustion controls for reducing GHGs from internal 

combustion engines indicating the full 5-step BACT evaluation for the engine is not warranted. 

Empire District proposes the only GHG control available as BACT for sources such as this 

which is to select the most efficient engine available that meets the plant’s emergency needs. 

Empire District also proposes to limit annual operations to no more than 100 hours per year for 

maintenance and readiness testing. 

Selection of BACT and Compliance
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | SF6 Insulated Circuit Breakers 6-1

6.0 SF6 Insulated Circuit Breakers

The Project will require the installation of two new SF6-insulated circuit breakers. SF6, or 

sulfur hexafluoride, is a potent GHG with a Global Warming Potential (GWP) of 23,900. Even so, 

estimated emission loses of SF6 from circuit breakers is extremely low at only 6.9 tpy of CO2e (only 

0.0006 percent of the total Project CO2e emissions).

6.1 STEP 1--IDENTIFY ALL CONTROL TECHNOLOGIES

 Use of dielectric oil or compressed air circuit breakers which contain no SF6 or other 

GHG pollutants.

 Use of modern SF6 circuit breakers designed to be totally enclosed systems with 

density alarms that sound when 10 percent of the SF6 has escaped.

6.2 STEP 2--ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

Circuit breakers with insulating gases other than SF6 are not yet commercially available23

6.3 STEP 3--RANK REMAINING CONTROL TECHNOLOGIES BY CONTROL 

EFFECTIVENESS

and certainly any use of less effective insulation material to control just 6.9 tpy of CO2e would not be 

warranted if available. As such non-SF6 circuit breakers will be eliminated.

The only remaining feasible control is to use a modern, totally enclosed SF6 circuit breakers

with leak detection alarms.

6.4 STEP 4--EVALUATE MOST EFFECTIVE CONTROLS

With only one control option there is no need for this evaluation step.

6.5 STEP 5--SELECT BACT

Empire District proposes to use modern, totally enclosed SF6 circuit breakers with density 

(leak detection) alarms having a threshold of 10 percent.

 23 Christophorous, L.G., J.K. Olthoff, and D.S. Green, Gases for Electrical Insulation and Arc Interruption: Possible 

Present and Future Alternatives to Pure SF6: NIST Technical Note 1425 (November 1997).
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Suggested Permit Conditions 7-1

7.0 Suggested Permit Conditions

BACT Emission Limitations

 BACT for the CCCT is good combustion practices and selected energy efficiency 

measures. The emissions of CO2 shall not exceed 1,021,770 tpy on a 12-month 

rolling average basis.24

 BACT for the auxiliary boiler is good combustion practices. The emissions of CO2

shall not exceed 9,512 tpy on a 12-month rolling average basis. 

 BACT for the emergency diesel generator shall be the selection of the most efficient 

engine that meets the facility’s emergency needs.

 BACT for SF6 circuit breakers shall be installation of modern, totally enclosed SF6

circuit breakers with density (leak detection) alarms and a guaranteed loss rate of 

0.5 percent by weight or less per year.

Monitoring Requirements

 The owner or operator shall monitor CO2 mass emissions from the CCCT using an 

oxygen (O2) concentration monitor in accordance with CO2 calculation provisions 

provided in 40 CFR Part 75. 

 The owner or operator shall monitor CO2 mass emissions from the auxiliary boiler 

by recording fuel usage and using emission factors presented in air permit 

application to determine resulting emissions.

 The owner or operator shall implement a density (leak detection) alarm system on 

the SF6 circuit breakers with a threshold of 10 percent. In the event of an alarm, the 

owner or operator will investigate the event and take any necessary corrective 

action to address any problems.

 24 The limit is proposed as CO2 which accounts for 99.9 percent of total CO2e emissions.
Empire District Electric Company | ADDENDUM – GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | GHG Emission Calculations A-1

Appendix A. GHG Emission Calculations
Empire Riverton Power Station

Greenhouse Gas Emissions Estimate

Summary of GHG Mass and CO2e Emissions

Table A-1

Emission Source

GHG Mass 

Emissios 1

 (tpy)

GHG CO2e 

2 

(tpy)

CTG and Duct Burner 1,021,791.3 1,022,755.9

Auxiliary Boiler 9,512.3 9,521.5

Emergency Generator 59.3 59.5

SF6 Insulated Circuit Breakers 0.00029 6.9

Total Estimated Emissions (tpy): 1,031,363 1,032,344

1. The GHG Mass Emissions are based on the sum of estimated emissions of GHGs

Global Warming Potential Factors for each GHG.

Notes [ ]

from each emission source.

2. The GHG CO2e emission are based on the sum of GHG CO2e emissions using
Empire Riverton Power Station

Greenhouse Gas Emissions Estimate

Combustion Turbine and Duct Burner

Table A-2

Pollutant Emission Source

Annual Heat 

Input 1 

(MMBtu/hr)

Emission 

Factor 2, 3 

(lb/MMBtu)

Hours of 

Operation 4 

(Hrs/Yr)

Mass 

Emissions 5 

(tpy)

Global 

Warming 

Potential 6

CO2e (tpy)

CTG 1679.2 118.86 8760 874,181.9 1 874,181.9

Duct Burner 283.5 118.86 8760 147,588.5 1 147,588.5

CTG 1679.2 0.002205 8760 16.21 21 340.5

Duct Burner 283.5 0.002205 8760 2.74 21 57.5

CTG 1679.2 0.0002205 8760 1.62 310 502.7

Duct Burner 283.5 0.0002205 8760 0.27 310 84.9

1,021,791.3 -- 1,022,755.9

CO2

CH4

N2O

1. Annual heat input for the CTG and Duct Burner is based on performance data at 100 percent load and ambient temperature

Total Estimated Emissions (tpy):

N2O for CTG (tpy) = 1,679.2 MMBtu/hr x 0.0002205 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 1.62

6. The Global Warming Potential factors for CO2, CH4, and N2O are from Table A-1 of 40 CFR Part 98, Subpart A.

Notes [ ]

5. The mass emissions for CO2, CH4, and N2O are calculated using the annual heat input, emission factor, and hours 

of operation as follows: 

CO2 for CTG (tpy) = 1,679.2 MMBtu/hr x 118.86 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 874,181.9

CH4 for Duct Burner (tpy) = 283.5 MMBtu/hr x 0.002205 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 2.74

2. Emission factor for CO2 was calculated from constants for natural gas in Section 2.3 of 40 CFR Part 75, Subpart G as follows:

CO2 (lb/MMBtu) = 1040 scf/MMBtu x 1 lb-mol/385 scf x 44 lb CO2/lb-mol = 118.86

3. Emission factors for CH4 and N2O were calculated using specified values from Table C-2 of 40 CFR Part 98, Subpart C 

CH4 (lb/MMBtu) = 0.001 kg CH4/MMBtu x 2.20462 lb/kg = 0.002205

N2O (lb/MMBtu) = 0.0001 kg N2O/MMBtu x 2.20462 lb/kg = 0.0002205

4. This estimate assumes the CT and Duct Burner will operate 8,760 hours per year.

as follows: 

of 59°F firing natural gas.
Empire Riverton Power Station

Greenhouse Gas Emissions Estimate

Auxiliary Boiler

Table A-3

Pollutant Emission Source

Annual Heat 

Input 1 

(MMBtu/hr)

Emission 

Factor 2, 3 

(lb/MMBtu)

Hours of 

Operation 4 

(Hrs/Yr)

Mass 

Emissions 5 

(tpy)

Global 

Warming 

Potential 6

CO2e 

(tpy)

CO2 Auxiliary Boiler 18.58 116.89 8760 9,512.2 1 9,512.2

CH4 Auxiliary Boiler 18.58 0.002205 8760 0.18 21 3.8

N2O Auxiliary Boiler 18.58 0.0002205 8760 0.0179 310 5.56

9,512.3 -- 9,521.5

6. The Global Warming Potential factors for CO2, CH4, and N2O are from Table A-1 of 40 CFR Part 98, Subpart A.

CO2 for Aux. Boiler (tpy) = 18.58 MMBtu/hr x 116.89 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 9,512.2

CH4 for Aux. Boiler (tpy) = 18.58 MMBtu/hr x 0.002205 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 0.18

Notes [ ]

1. The Auxiliary Boiler annual heat input is based on specifications for the conceptual design.

2. Emission factor for CO2 was calculated using default CO2 emissions factors for natural gas fuel from Table C-1 of 

40 CFR Part 98, Subpart C as follows:

N2O (lb/MMBtu) = 0.0001 kg N2O/MMBtu x 2.20462 lb/kg = 0.0002205

4. This estimate assumes the auxiliary boiler will operate 8,760 hours per year.

5. The mass emissions for CO2, CH4, and N2O are calculated using the annual heat input, emission factor, and hours 

of operation as follows: 

CH4 (lb/MMBtu) = 0.001 kg CH4/MMBtu x 2.20462 lb/kg = 0.002205

CO2 (lb/MMBtu) = 53.02 kg CO2/MMBtu x 2.20462 lb/kg = 116.89

3. Emission factors for CH4 and N2O were calculated using specified values for natural gas fuel from Table C-2 of 

40 CFR Part 98, Subpart C as follows: 

Total Estimated Emissions (tpy):

N2O for Aux. Boiler (tpy) = 18.58 MMBtu/hr x 0.0002205 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 0.0179
Empire Riverton Power Station

Greenhouse Gas Emissions Estimate

Emergency Generator

Table A-4

Pollutant Emission Source

Annual Heat 

Input 1 

(MMBtu/hr)

Emission 

Factor 2, 3 

(lb/MMBtu)

Hours of 

Operation 4 

(Hrs/Yr)

Mass 

Emissions 5 

(tpy)

Global 

Warming 

Potential 6

CO2e 

(tpy)

CO2 Emergency Generator 7.27 163.05 100 59.3 1 59.3

CH4 Emergency Generator 7.27 0.006614 100 0.0024 21 0.1

N2O Emergency Generator 7.27 0.001323 100 0.0005 310 0.15

59.3 -- 59.5

as follows:

Model QST30-G5 NRT 60 Hz Diesel Generator Set and the default high heat value for distillate fuel oil No. 2 displayed in Table C-1

of 40 CFR 98, Subpart C. The heat input is calculatedas follows:

6. The Global Warming Potential factors for CO2, CH4, and N2O are from Table A-1 of 40 CFR Part 98, Subpart A.

CO2 (lb/MMBtu) = 73.96 kg CO2/MMBtu x 2.20462 lb/kg = 163.05

3. Emission factors for CH4 and N2O were calculated using specified values from Table C-2 of 40 CFR Part 98, Subpart C 

as follows: 

CH4 (lb/MMBtu) = 0.003 kg CH4/MMBtu x 2.20462 lb/kg = 0.006614

N2O (lb/MMBtu) = 0.0006 kg N2O/MMBtu x 2.20462 lb/kg = 0.001323

4. This estimate assumes the auxiliary boiler will operate 100 hours per year.

5. The mass emissions for CO2, CH4, and N2O are calculated using the annual heat input, emission factor, and hours 

of operation as follows: 

CO2 for Emerg. Gen. (tpy) = 7.27 MMBtu/hr x 163.05 lb/MMBtu x 100 hrs/yr x 1 ton/2000 lb = 59.3

CH4 for Emerg. Gen. (tpy) = 7.27 MMBtu/hr x 0.006614 lb/MMBtu x 100 hrs/yr x 1 ton/2000 lb = 0.0024

N20 for Emerg. Gen. (tpy) = 7.27 MMBtu/hr x 0.001323 lb/MMBtu x 100 hrs/yr x 1 ton/2000 lb = 0.0005

Heat Input (MMBtu/hr) = 52.7 gallons/hour x 0.138 MMBtu/gallon = 7.27

Notes [ ]

1. The annual heat input for the emergency generator is based on fuel consumption data at full standby for a Cummins Inc. 

2. Emission factor for CO2 was calculated using default CO2 emissions factors from Table C-1 of 40 CFR Part 98, Subpart C 

Total Estimated Emissions (tpy):
Empire Riverton Power Station

Greenhouse Gas Emissions Estimate

Electrical Equipment Insulated with SF6

Table A-5

Pollutant Emission Source Count 

(Breakers)

Mass of SF6 

per Breaker 

(lb/Breaker)

Annual SF6 Leak 

Rate 

(% by weight)

Mass 

Emissions 1 

(tpy)

Global 

Warming 

Potential 2

CO2e 

(tpy)

SF6 Electrical Breakers 2 58 0.5 0.00029 23,900 6.9

Total Estimated Emissions (tpy): 0.00029 -- 6.9

3. The Global Warming Potential factors for SF6 is from Table A-1 of 40 CFR Part 98, Subpart A.

Notes [ ]

1. The annual mass emissions of SF6 from electrical breakers is calculated using the number of breakers, mass of SF6 per 

breaker, and annual leak rate as follows:

SF6 for Electrical Breakers (tpy) = 2 breakers x 58 lb/breaker/year x 0.5% x 1 ton/2,000 lbs = 0.00029