Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 1

COMBUSTION TURBINE POINT SOURCE CATEGORY 4-FACTOR ANALYSIS 

I. Source Description 

Combustion turbines fueled by natural gas or oil are either co-located with coal-fired 

electric generating units or as stand-alone facilities. These units are primarily used to 

supplement power supply during peak demand periods when electricity use is highest. 

Combustion turbine units start quickly and usually operate only for a short time. 

However, they are capable of operating for extended periods. Combustion turbine units 

are also capable of operating together or independently. 

Information regarding combustion turbine emissions is well recorded in the State’s air 

emissions inventory. Typical emissions for this source type may be significant for NOx, 

but pipeline quality natural gas is inherently clean and low-emitting for SO2 and PM10 

emissions. Combustion turbines are subject to 40 CFR Part 60, Subpart GG – 

Standards of Performance for Stationary Gas Turbines, which limit sulfur content to 0.8 

percent by weight, supported by monitoring and testing. Subpart GG also limits 

nitrogen oxides to 117.8 percent by volume at 15 percent oxygen on a dry basis 

(60.332(a)(1)), supported by monitoring and testing. The majority of combustion 

turbines are installed with Continuous Emissions Monitoring Systems (CEMs). 

Control strategies for this source category are: 

NOx – Steam or water injection, advanced dry low NOx combustion system, and 

selective catalytic reduction (SCR) 

Cumulatively, this emissions source category is projected to be a minimal single 

category of Colorado point sources with a total of 56 turbines. Of this total, turbines 

located as single sources at Reasonable Progress facilities are 18. Total state-wide 

NOx emissions (2007 inventory) are approximately 284,037 tons/year. This source 

category is about 0.7% of total statewide emissions; therefore, the Division considers 

this source category to be nominal. Regardless, the Division evaluated all combustion 

turbines, regardless of fuel type, at Reasonable Progress facilities. The majority of 

combustion turbines (assumed 17 out of 18 based on inventory limitations) are naturalgas fired. 

II. Source Emissions 

Pollutant 

Total 2006 – 2008 

Averaged Annual 

Emissions (tpy) 

Total RP Turbine 

2006 – 2008 

Averaged Annual 

Emissions (tpy) 

RP Turbine 

Emissions 

compared to 

total state-wide 

turbine 

emissions (%) 

NO2 2,003 473 24% 

The Division analyzed total state-wide combustion turbine emissions averaged over the 

2006 – 2008 Reasonable Progress baseline period. There are 5 Reasonable Progress 

facilities with combustion turbines – PSCo Valmont Generating Station, PSCo Arapahoe 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 2

Generating Station, Colorado Springs Utilities Nixon Plant, Platte River Power Authority 

Rawhide Energy Station, and PSCo Pawnee Generating Station. Of these, only two 

emit over federal significance levels as depicted below. 

For the purposes of evaluating RP, the Division has elected to set de minimis thresholds 

for any emission unit at a subject-to-RP source with actual baseline emissions of NOx 

equal to or exceeding the federal Prevention of Significant Deterioration (PSD) 

significance levels. The Division has established de minimis thresholds for SO2, NOx

and PM10 to focus the technical emission control analysis on significant emission 

sources where potential controls could provide a meaningful improvement in visibility if 

emission controls are determined to be cost effective. 

The de minimis levels are applicable to individual emission units at a stationary source. 

The Division defines “emissions unit” as “any part or activity of a stationary source that 

emits or has the potential to emit any air pollutant regulated under the state or Federal 

Acts. This term is not meant to alter or affect the definition of the term “unit” for 

purposes of Title IV (acid deposition control) of the federal act, or of the term “source” 

for purposes of the Air Pollutant Emission Notice requirements of Regulation Number 3, 

Part A, Section II.B.3. 1 .” These de minimis levels are as follows: 

• NOx – 40 tons per year 

• SO2 – 40 tons per year 

• PM10 – 15 tons per year 

Facility – 

Turbine

Total 2006 – 2008 

Averaged NOx 

Annual Emissions 

(tpy)

Total 2006 – 

2008 Averaged 

SO2 Annual 

Emissions (tpy)

Total 2006 – 

2008 

Averaged 

PM10 Annual 

Emissions 

(tpy)

Greater 

than de 

minimis

levels?

Valmont – 

Turbine #6

12.6 0.4 0.1 No

Valmont – 

Turbine #7 

27.4 0.2 2.8 No

Valmont – 

Turbine #8

1.5 0.0 0.1 No

Arapahoe – 

Turbine #5

25.5 0.4 5.0 No

Arapahoe – 

Turbine #6

15.3 0.4 5.0 No

Arapahoe – 

Turbine

4.1 0.2 3.7 No

Nixon – Turbine 

#2

0.7 0.0 0.2 No

Nixon – Turbine 

#3

1.2 0.0 0.3 No

Nixon – Front 

Range Power 

159.6 2.9 4.9 Yes – NOx 

only

 

1

 Colorado Department of Public Health and Environment. Air Quality Control Commission Common Provisions 

Regulation 5 CCR 1001-2. Amended December 17, 2009. Effective January 30, 2010. Page 19. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 3

Plant – 

Turbine #1

Nixon – Front 

Range Power 

Plant – 

Turbine #2

147.9 2.8 4.9 Yes – NOx 

only

Rawhide Turbine 

A

2.5 0.1 0.5 No

Rawhide Turbine 

B

4.0 0.1 0.8 No

Rawhide Turbine 

C

2.7 0.1 0.5 No

Rawhide Turbine 

D

2.9 0.1 0.5 No

Pawnee – 

Turbine #1

25.4 0.3 3.3 No

Pawnee – 

Turbine #2

25.0 0.2 2.7 No

Therefore, for the purposes of this RP planning period, the Division will evaluate the 

Nixon – Front Range Power Plant – Turbines #1 and #2 as they are the two combustion 

turbines emitting over de minimis levels. 

III. Control Technology Evaluation

Step 1: Identify All Available Technologies

Four technologies have been identified to lower emissions from combustion turbines: 

1. Wet controls using steam or water injection to reduce combustion temperatures 

for NOx control 

2. Dry controls using advanced combustor design to suppress NOx formation 

and/or promote CO burnout 

3. Adding post combustion technology – selective non-catalytic reduction (SNCR) 

or selective catalytic reduction (SCR) 

Technology #2: This technology (retrofitting with low-NOx burners) was identified by 

the EPA and is documented in the AP-42 “Compilation of Air Pollutant Emission 

Factors.” The following is from the 5th Edition, Volume 1, Chapter 1, Section 3.1.4.1: 

“Water or steam injection is a technology that has been demonstrated to effectively 

suppress NOx emissions from gas turbines. The effect of steam and water injection is to 

increase the thermal mass by dilution and thereby reduce peak temperatures in the 

flame zone. With water injection, there is an additional benefit of absorbing the latent 

heat of vaporization from the flame zone. Water or steam is typically injected at a waterto-fuel weight ratio of less than one.” 

Technology #3: This technology was identified by the EPA and is documented in the 

AP-42 “Compilation of Air Pollutant Emission Factors.” The following is from the 5th
Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 4

Edition, Volume 1, Chapter 1, Section 3.1.4.2: “Since thermal NOX is a function of both 

temperature (exponentially) and time (linearly), the basis of dry controls are to either 

lower the combustor temperature using lean mixtures of air and/or fuel staging, or 

decrease the residence time of the combustor. A combination of methods may be used 

to reduce NOx emissions such as lean combustion and staged combustion (two stage 

lean/lean combustion or two stage rich/lean combustion). 

Lean combustion involves increasing the air-to-fuel ratio of the mixture so that the peak 

and average temperatures within the combustor will be less than that of the 

stoichiometric mixture, thus suppressing thermal NOX formation. Introducing excess air 

not only creates a leaner mixture but it also can reduce residence time at peak 

temperatures. 

Two-stage lean/lean combustors are essentially fuel-staged, premixed combustors in 

which each stage burns lean. The two-stage lean/lean combustor allows the turbine to 

operate with an extremely lean mixture while ensuring a stable flame. A small 

stoichiometric pilot flame ignites the premixed gas and provides flame stability. The NOx 

emissions associated with the high temperature pilot flame are insignificant. Low NOx 

emission levels are achieved by this combustor design through cooler flame 

temperatures associated with lean combustion and avoidance of localized "hot spots" 

by premixing the fuel and air. 

Two stage rich/lean combustors are essentially air-staged, premixed combustors in 

which the primary zone is operated fuel rich and the secondary zone is operated fuel 

lean. The rich mixture produces lower temperatures (compared to stoichiometric) and 

higher concentrations of CO and H2, because of incomplete combustion. The rich 

mixture also decreases the amount of oxygen available for NOx generation. Before 

entering the secondary zone, the exhaust of the primary zone is quenched (to 

extinguish the flame) by large amounts of air and a lean mixture is created. The lean 

mixture is pre-ignited and the combustion completed in the secondary zone. NOx 

formation in the second stage are minimized through combustion in a fuel lean, lower 

temperature environment. Staged combustion is identified through a variety of names, 

including Dry-Low NOx (DLN), Dry-Low Emissions (DLE), or SoLoNOx.” 

Technology #4: This technology (adding SNCR or SCR) involves adding control 

equipment and reagent to treat turbine exhaust. 

Step 2: Eliminate Technically Infeasible Options

Technology #1: This technology is technically feasible. 

Technology #2: This technology is technically feasible. 

Technology #3: This technology is technically feasible and is already installed at the 

Nixon – Front Range Power Plant combustion turbines. 

Technology #4: This technology is technically feasible, although a Division of the 

EPA’s RBLC database revealed SCR is the predominant post-combustion control 

technology for combustion turbines and did not find any examples of SNCR postcombustion technology applied to combustion turbines.
Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 5

Step 3: Evaluate Control Effectiveness of Each Remaining Control Technology

Technology #1: Since this control technology is specific fuel type usage, control 

efficiency are not applicable. 

Technology #2: EPA’s AP-42 factor database cites this technology as achieving control 

efficiencies of 60% or greater. However, this technology will not be evaluated in this 

analysis further since the dry low-NOx combustion systems already installed on the 

turbines at the Front Range Power Plant achieve greater than 85% control, which is 

greater than the 60% estimate achievable by wet controls. 

Technology #3: The Division calculated that the controlled-uncontrolled ratio for 

advanced dry-low NOx combustions using EPA’s AP-42 emission factors is 

approximately 70% and may be greater in site-specific cases. The combustion turbines 

at the Nixon – Front Range Power Plant were installed with these systems, and based 

on 2006 – 2008 CEMs data and AP-42 emission factors, are achieving 89.4% and 

90.1% NOx reductions (calculated using the 2006 – 2008 RP baseline period), 

respectively. 

Technology #4: EPA’s AP-42 emission factor description indicates that a SCR in good 

working order can achieve removal efficiencies ranging from 65 – 90 percent from the 

NOx exhaust stream. AP-42 is silent on control efficiencies regarding SNCR. During a 

research review, the Division could not find any instances of a commercial-scale SNCR 

applied at a natural-gas fired combustion turbine. Therefore, SNCR will not be 

considered further in this analysis. 

Step 4: Evaluate Impacts and Document Results

The Division reasons that SCR requires significant capital expenditures and will result in 

minimal additional NOx reductions, if any. Regardless, the Division analyzed additional 

achievable NOx reductions if SCR was installed at these two turbines. Applying SCR at 

90% to both turbines would result in about 275 additional tons of NOx reduced annually. 

Using another Colorado SCR analysis from the same utility (Colorado Springs Utilities), 

the Division estimates that annualized costs for installing SCR to both turbines will be 

approximately $8 million each, resulting in about $57,000 - $62,000 per ton of NOx 

reduced annually. 

The time necessary for compliance will depend on the type of control implemented. 

Based on other Colorado facility submittals, the Division anticipates that the time 

necessary for completing design, permitting, procurement, pipeline installation, and 

system startup and shutdown, after SIP approval, it would take CSU approximately 3 – 

5 years to implement any of the SCR control option. This timeframe may vary 

somewhat due to regional demand for natural gas and to schedule the necessary major 

maintenance outage with other regionally affected utilities. 

There are no energy or non-air quality impacts for fuel usage of pipeline quality natural 

gas or for advanced dry low-NOx combustion systems. The energy and non-air quality 

impacts of SCR and SNCR are increased power needs, potential for ammonia slip, 

potential for visible emissions, hazardous materials storage and handling. 
Colorado Department of Public Health and Environment - Air Pollution Control Division

Source Category Analysis – Combustion Turbines Page 6

There are no remaining useful life issues for the alternatives as the sources will remain 

in service for the 20-year amortization period. 

Step 5: Select Reasonable Progress Control

The Division determines that any potential reductions from this source category are 

minimal, if any. Pipeline quality natural gas is inherently clean for SO2 and PM10. For 

NOx, the majority of combustion turbines already apply advanced dry-low NOx 

combustion systems, especially the larger turbines. 

Based on its consideration of the four factors summarized herein, the state has 

determined that NOx RP for combustion turbines is existing controls and emission 

limits. Though other controls achieve better emission reductions, the expense of these 

options coupled with predicted minimal visibility improvement were determined to be 

excessive.