Riverton 12 Conversion to Combined Cycle

January 25, 2013

1

Empire District Electric Company

Riverton Unit 12 Conversion to 

Combined Cycle Project

Construction Permit Application

January 25, 2013

602 Joplin St., PO Box 127, Joplin, MO 64802
Riverton 12 Conversion to Combined Cycle

January 25, 2013

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1.0 Riverton Power Station Introduction

The Empire District Electric Company (Empire District) owns and operates the Riverton 

Power Station (0210002) located in Riverton, Kansas which currently consists of two boilers and 

four simple cycle combustion turbines. The boilers are identified as unit 7 (38 MW, 426 

MMBtu/hr) and unit 8 (54 MW, 600 MMBtu/hr) and were designed to combust natural gas as 

well as coal. In September 2012 units 7 and 8 transitioned from combusting coal while co-firing

with natural gas to combusting 100% natural gas. A construction permit for the transition to 

100% natural gas was issued by KDHE September 25, 2012.

The simple cycle combustion turbines are identified as unit 9 (12 MW, 199 MMBtu/hr), 

unit 10 (16 MW, 236 MMBtu/hr), unit 11 (16 MW, 228 MMBtu/hr), and unit 12 (150 MW, 1627 

MMBtu/hr). Please note that all unit descriptions listed above are based on net capabilities as per 

Southwest Power Pool Criteria 12 summer ratings.

Units 7 and 8 were constructed in 1954 and 1955, respectively, and unit 9 was 

constructed in the 1970’s. Units 10 and 11 were constructed in 1967 and 1968, respectively, and 

then commenced commercial operation at the Riverton Power Station in the 1989 time-frame. 

Finally, unit 12 was manufactured April 5, 2002 and commenced commercial operation at 

Riverton in 2007.

Riverton is located in the southeast corner of Kansas in Cherokee County. Figure 1-1 

provides a U.S. Geological Survey (USGS) map showing the facility location and the 

surrounding area.

Figure 1-1
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2.0 Project Description

The existing Riverton unit 12 is a Siemens V84.3A(2) natural gas-fired combustion 

turbine that commenced commercial operation in 2007. Its nominal rating is 150 MW. At the 

time of original construction, provisions were made to allow its eventual conversion to combined 

cycle operation. Empire plans to complete this conversion by June 2016 to replace capacity and 

energy provided by the boiler units 7 and 8 which will be retired in conjunction with the 

completion of this project. Dry low-NOx burners were included to control NOx when unit 12 

was first installed at Riverton. 

The proposed Riverton combined cycle unit will have a nominal capacity of 250 MW. 

This will require the addition of a heat recovery steam generator (HRSG) with supplemental 

natural gas duct firing (duct burners) and a condensing steam turbine generator. Other emissions 

sources that will be constructed as part of the project include a cooling tower and an emergency 

diesel generator. The capacity of the emergency diesel generator has not yet been determined, 

but for permitting purposes, Empire District will assume the capacity to be 1102 horsepower 

(HP) or 750 Kw electrical output. This is a conservative estimate and the actual unit that will be 

installed could be smaller. Except in the case of an actual emergency, Empire District does not 

anticipate operating the emergency diesel generator more than 100 hours per year in a nonemergency capacity to accommodate maintenance and readiness testing. The project is designed 

to include the installation of selective catalytic reduction (SCR) system to control NOx and CO 

catalyst to control carbon monoxide (CO) and volatile organic compound (VOC) emissions from 

the turbine and HRSG.

In addition to the above mentioned sources, the project may include a natural gas-fired 

auxiliary boiler with the capacity to produce 15,000 pounds of steam per hour. The auxiliary 

boiler would be designed to operate when the combined cycle unit is in a brief period of 

shutdown and for startup. For permitting purposes, Empire District has included the emissions 

from the auxiliary boiler which would be designed with its own stack.

3.0 Project Emissions

A facility is considered to be a major source with respect to the Prevention of Significant 

Deterioration (PSD) regulation if the potential emissions of any PSD pollutant from the facility 

exceed the major source threshold. The major source threshold for Riverton is 100 tons per year 

(tpy). Because Riverton currently has the potential to emit more than 100 tpy of at least one PSD 

pollutant, it is considered to be an existing major source. For an existing major source, PSD 

review is triggered any time the facility makes a major modification. Any project resulting in an 

increase in emissions at a facility in excess of the PSD significant emission rates (SER) is 

considered to be a major modification. As summarized in Table 3-0, the emission increases for 

PM, PM10, PM2.5, and CO2e associated with the project exceed the PSD SER. Accordingly, 
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these pollutants are subject to full PSD review including Best Available Control Technology 

(BACT) analyses and air quality analyses. Appendix A, Table A-9 provides a copy of the 

worksheet used to determine the estimated emissions increases using the baseline actual 

emissions, potential to emit, and netting out emissions associated with the retirement of unit 7 

and unit 8. Please note that the BACT and air quality analyses are being submitted in addendum.

Table 3-0 Annual Project Emission Increases and PSD SER

NOx

(tpy)

SO2

(tpy)

CO

(tpy)

VOC

(tpy)

Lead

(tpy)

SAM

(tpy)

HF

(tpy)

PM

(tpy)

PM10

(tpy)

PM2.5

(tpy)

CO2e

(tpy)

Unit 12 Combined 

Cycle Project

33 12 60 37 .000047 6.93 .000017 34 59 99 247976

PSD SER 40 40 100 40 0.6 7 3 25 15 10 75000

PSD Triggered? No No No No No No No Yes Yes Yes Yes

3.1 Baseline Actual Emissions (BAE)

Baseline actual emissions (BAE), as they relate to an electric utility generating unit are 

defined in 40 CFR 52.21 and adopted by reference in K.A.R. 28-19-350. For this analysis the 

BAE was determined using monthly CEMS data and KDHE-reported annual emissions reporting 

for the look-back period.

The BAE for each pollutant associated with units 7, 8, and 12 and how they are derived 

are presented in copies of the worksheets in Appendix A, Table A-1 through Table A-4

3.2 Potential to Emit (PTE)

In order to determine the maximum emissions from the project, PTE was determined 

using fleet average performance data from Siemens for the conversion of unit 12 simple cycle 

turbine to combined cycle. 

The converted unit 12 projected emissions include the controlled emissions from both the 

turbine and the HRSG. Siemens case number five, as represented in Appendix A, Table A-10,

was selected from the operational data to determine the emissions combined cycle emissions. 

Case number five represents steady- state operation at an ambient dry-bulb temperature of 50.0 

degrees Fahrenheit; ambient relative humidity of 60.0 percent; combustion turbine operating at 

base load; and maximum firing of the duct burners. The emissions, in tons per year are 

calculated assuming 8,760 hours of operation per year for both the unit 12 combustion turbine 

and the HRSG. The emissions from the combustion turbine and HRSG are calculated at 8,760 
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hours per year to allow for unlimited operating hours. A dry ambient air composition of 0.98 

percent Ar; 78.03 percent N2; and 20.99 percent O2 is assumed. The fuel gas used to determine 

the emissions is based on natural gas with a sulfur content of 0.5 gr/100scf and lower heating 

value of 20,426 Btu/lb. The fuel is unheated and supplied at 60.0 degrees Fahrenheit. The PTE 

for unit 12 are represented in Appendix A, Table A-5

Although the exact equipment has not been determined, in order to estimate the PTE for

the auxiliary boiler and cooling tower, emission rates for pollutants typically emitted from these 

type sources were provided by vendors of the equipment and an assumed operation of 8,760 

hours per year was applied. The auxiliary boiler emissions are calculated at 8,760 hours per year 

to allow for unlimited operating hours. The PTE estimates for the auxiliary boiler and cooling 

tower are represented in Appendix A, Table A-6.1, Table A-6.2, and Table A-8.

For the emergency generator, the PTE were determined using emission rates provided by 

a vendor of this type equipment for pollutants expected to be emitted assuming 100 hours of 

operation per year for non-emergency use including maintenance and readiness testing. The 

emissions are calculated based on the emergency generator size mentioned in the project 

description at full standby operation and the PTE estimates are represented in Appendix A, Table 

A-7.

Also, Appendix A, Tables A-11, A-12.1, and A- 12.2 contain the conceptual equipment 

vendor data used in estimating emissions for the auxiliary boiler and emergency generator. 

Table A-13 contains a pipeline natural gas sample analysis used to estimate emissions from the 

auxiliary boiler.

4.0 Regulatory Applicability Analysis

The proposed project will be subject to certain federal and state air quality regulations. 

This section of the application summarizes the air permitting requirements and the key air quality 

regulations that will apply to the proposed project. Applicability of the PSD regulations, NSPS, 

NESHAP, ARP, and KAR are addressed.

4.1 PSD Applicability 

Riverton is located in Cherokee County, which has been designated by the U.S.EPA as 

“attainment” or “unclassifiable” for all criteria pollutants. As such, new construction or 

modifications that result in emission increases are potentially subject to PSD permitting.

PSD applicability for a proposed project depends on the existing facility’s source 

classification (whether the facility is an existing PSD major source or an existing PSD minor 

source) and the emission increases for a proposed project. The PSD regulations define 28 source 

categories (List of 28) for which the PSD major source threshold is 100 tons per year of potential 

emissions of any PSD pollutant. Sources not on the List of 28 have a PSD major source 
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threshold of 250 tons per year of potential emissions of any PSD pollutant. A major source that 

has a proposed project with emission increases that exceed the PSD significant rates is subject to 

PSD review for the project.

The Riverton plant falls into the category of the List of 28, the PSD major source 

threshold is 100 tons per year. Further, since Riverton has the potential to emit more than 100 

tons per year, the facility is a major PSD source. Therefore, any PSD pollutants with emission 

increases resulting from the proposed project that exceed the PSD SER are subject to PSD 

review.

Table 3-0 shows that the emission increases for PM, PM10, PM2.5, and CO2e from the 

proposed project will exceed the PSD SER. Therefore, these pollutants are subject to PSD 

review. Accordingly, air quality and BACT analyses will be included as addendums in this 

permit application. 

4.2 Federal Regulatory Applicability

NSPS Part 60 Subpart KKKK- Stationary Gas Turbines

40 CFR part 60 subpart KKKK 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. 

Only the heat input to the combustion turbine should be included when determining applicability 

of this subpart. Any additional heat input to associated HRSG or duct burners should not be 

included when determining the peak heat input. However, subpart KKKK does apply to 

emissions from any associated HRSG and duct burners.

Stationary combustion turbines regulated under this subpart are exempt from the 

requirements of subpart GG of part 60. Heat recovery generators and duct burners regulated 

under this subpart are exempt from the requirements of subparts Da, Db, and Dc of part 60.

Following the modification of the existing unit 12 from simple cycle to combined cycle, 

the heat input of the combustion turbine is expected to be approximately 1,677 MMBtu/hr. 

Based on 40 CFR part 60 subpart KKKK Table 1-A modified turbine firing natural gas greater 

than 850 MMBtu/hr has a NOx emission limit of 15 ppm at 15 % O2 or 54 ng/J of useful output 

(0.43 lb/MWhr). The SO2 emissions limit would be not discharge into the atmosphere any gases 

which contain SO2 in excess of 78 ng/J (6.2 lb/MWhr gross output, or not burn any fuel which 

contains total sulfur with potential sulfur emissions in excess of 180 ng SO2/J (0.42 lb 

SO2/MMBtu) heat input.

NSPS Part 60 Greenhouse Gas Standards of Performance for Greenhouse Gas 

Emissions for New Stationary Sources: Electric Utility Generating Units

On March 27, 2012 the USEPA proposed to amend the NSPS for electric generating units 

and establish the first NSPS for greenhouse gas emissions. The rule would establish CO2 
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emission standards for certain new and reconstructed fossil fuel-fired electric generating units 

and is expected to be published in the Federal Register March 2013. As previously stated, this 

rule is only proposed at the time of this permit application submittal. In addition, this rule 

applies to new fossil fuel-fired electric generating units and will not apply to the modification of 

Riverton unit 12 as it is converted from simple cycle to combined cycle operation.

NSPS Part 60 Subpart Dc-Standards of Performance for Small IndustrialCommercial-Institutional Steam Generating Units

40 CFR Part 60 Subpart Dc applies to steam generating units that fire between 10 – 100 

MMBtu/hr. If constructed, the auxiliary boiler would fire at approximately 18.5 MMBtu/hr 

therefore; the SO2 and PM standards of Subpart Dc would apply. 

NSPS Part 60 Subpart IIII –Stationary compression ignition internal combustion 

engines

40 CFR Part 60 Subpart IIII applies to compression ignition internal combustion engines 

and will apply to the emergency diesel generator associated with the proposed project.

NESHAP Part 63 Subpart DDDDD- Industrial, Commercial, and Institutional 

Boilers and Process Heaters (Boiler MACT)

40 CFR Part 63 Subpart DDDDD would apply only to the auxiliary boiler, if installed. 

Since the auxiliary boiler would fire solely natural gas it will not be subject to any emissions 

limits, but rather would be subject to a work practice standard that requires an annual tune-up in 

lieu of emission limits.

NESHAP Part 63 Subpart YYYY-Stationary Combustion Turbines

40 CFR Part 63 Subpart YYYY, 63.6145 requires initial notification. In accordance with 

63.6095(d) there are no other applicable requirements of the subpart until EPA takes final action 

to require compliance and publishes a document in the Federal Register. As of the date on this 

application, the EPA has not published such a document in the Federal Register.

NESHAP Part 63 Subpart ZZZZ-Stationary Reciprocating Internal Combustion 

Engines (RICE)

40 CFR Part 63 Subpart ZZZZ applies to stationary RICE at major or area source of 

hazardous air pollutant emissions. Subpart ZZZZ will apply to the emergency diesel generator 

associated with the proposed project.

Acid Rain Program (ARP)

The ARP regulations are located in 40 CFR Part 72 through Part 78, and apply 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 
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operation, will continue to be subject to the ARP. The ARP requires various pollutant monitors 

in addition to possession of SO2 allowances for each ton of SO2 emitted. The current ARP 

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

4.3 Kansas Administrative Regulations

K.A.R. 28-19-350 Prevention of Significant Deterioration of Air Quality

Section 28-19-350 of the Kansas Administrative Regulations adopts by reference the 

following federal requirements for PSD review that are located in 40 CFR 52.21, as in effect on 

July 1, 2000:

- 52.21(b) -Definitions (Incorporated into this PSD application as appropriate)

- 52.21(c) - PSD Increments (Refer to the air dispersion modeling analysis section of 

 this permit application)

- 52.21(d) -NAAQS (Refer to the air dispersion modeling analysis section of this

 permit application)

- 52.21(e) -Designation of Class I Areas (No applicable requirements)

- 52.21(g) -Designation of Class II Areas (No applicable requirements)

- 52.21(i) - Exemptions for PSD review (No applicable requirements)

- 52.21(j) - Requirement to conduct BACT analysis (Refer to the BACT analysis 

 section of this permit application)

- 52.21(k) -Requirement to demonstrate compliance with NAAQS and PSD 

 increments (Refer to the air dispersion modeling analysis section of this 

 permit application)

- 52.21(n) -Requirement to submit source information (Refer to the air dispersion 

 modeling analysis section of this permit application)

- 52.21(o) -Requirement to conduct additional impact analysis (Refer to the additional 

 Impacts analysis section of this permit application)

- 52.21(p) -Requirement for sources impacting Class I areas (No applicable 

 requirements)

- 52.21(r) – Requirement to operate source in accordance with PSD application

The requirements of KAR Section 28-19-350 are addressed in this PSD application as 

indicated above for each requirement.

K.A.R. 28-19-650 Emission Opacity Limits

KAR 28-19-650 includes opacity limits for all emission units. Specifically, KAR 28-

19-650 states:
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Opacity of visible air emissions from any emission unit shall not exceed the 

following limits: (1) 40% opacity for any portable source existing on or before 

January 1, 1971; (2) 40% opacity for any emission unit, other than a portable source, 

that existed on or before January 1, 1971 and that has not been relocated after 

January 1, 1971; and (3) 20% opacity for any other emission unit.

Exceptions, air emissions opacity levels that exceed the specified limits in 

subsections (a) and (b) of this regulation shall not be considered a violation of this 

regulation if the owner or operator of the emission unit demonstrates to the 

satisfaction of the department that the opacity exceedance is due solely to the 

presence of uncombined water in the plume.

Since unit 12 is being modified and converted to combined cycle after 1971, it will be 

subject to a 20 percent opacity limit.