Technical Support Document (TSD) for 

New Source Performance Standards for Carbon Pollution from 

Electric Utility Generating Units (EGUs) 

Docket ID No. EPA-HQ-OAR-2013-0495 

Combustion Turbine Permit Review 

for New Natural Gas Combined Cycle Projects 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

August 3, 2015 
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Summary 

To establish an appropriate carbon dioxide (CO2) emissions standard for natural gas-fired base 

load combustion turbines under the section 111 Standards of Performance for Greenhouse Gas 

Emissions from New, Modified, and Reconstructed Stationary Sources within the category for 

Electric Utility Generating Units (EGUs), we reviewed the CO2 and greenhouse gas (GHG) 

emissions limits included in recently issued pre-construction permits. We focused our review on 

federally enforceable limits issued under the authority of 40 CFR Parts 51 and 52, specifically, 

Best Available Control Technology (BACT) emission limits and associated monitoring and 

testing requirements. We reviewed 36 permits and the associated Statements of Basis associated 

with natural gas combined cycle (NGCC) stationary combustion turbines. 

In summary, the EPA reviewed recent BACT permit limits for GHG emissions to evaluate the 

structure of these limitations (e.g., as mass emission rates or heat rate limitations), the averaging 

periods, treatment of startups and shutdowns, and associated testing and monitoring 

requirements. We found a number of variations in the way permitting authorities had structured 

these BACT limits. Some of the BACT permit conditions had separate numeric limits that 

applied during startups and shutdowns with associated limitations on the total duration of 

startups and shutdowns. The most common compliance period was 12-months. Some permits 

only included heat rate type limits (i.e., MMBtu heat input per MWh output or lbs CO2/MWh) 

with ongoing monitoring based on periodic performance tests at greater than 90 percent of 

maximum output with associated numeric limits that were significantly more stringent than the 

final NSPS. 

Additionally, while the EPA did review recently issued permits when evaluating the level of the 

standard, the EPA also reviewed actual performance data to determine the degree of limitation 

that is actually being achieved after the commencement of operations (as required by section 

111(a)(1)). The docket includes information on the actual emission rates that are being achieved 

by combustion turbines with capacity factors greater than 50 percent. For example, in 2013, 

based on EIA 923 final data[3] for combined cycle plants firing natural gas with capacity factors 

greater than 50 percent, only 5 combined cycle plants (each with only 1 combined cycle power 

block) had emission rates that exceeded 1030 lbs of CO2 MWh-net based strictly on electrical 

output (ORIS codes 7266, 7527, 96, 7697, 7698); these units began operations from 1977 

through 2003 and three of these units are combined heat and power facilities that would be 

eligible to include useful thermal output in their compliance calculations. The average emission 

rates at 43 plants (which also each had only 1 combined cycle power block) ranged from 795 to 

992 lbs of CO2 per net MWh with a median annual average emission rate of 845 lbs of CO2 per 

net MWh. These data support the EPA’s conclusion that available operating data and recently 

issued permits indicate the final standard is achievable by modern combined cycle units during 

12-month periods when capacity factors exceed 50 percent. It is also worth noting that the 

average emission rates at 17 plants (with plant-wide capacity factors greater than 50 percent) 

with multiple combined cycle power blocks, ranged from 802 to 965 lbs of CO2 per net MWh. 

While the average emission rates across multiple affected sources at these plants is not directly 

comparable to the NSPS for individual affected sources, these averages indicate that combined 

cycle units are also achieving the final NSPS emission rate for CO2 at these 17 generating 

facilities. 
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Introduction 

We found 36 permits issued since 2011 for construction of new NGCC power blocks1. We 

reviewed these permits to identify the form of the limit(s) for GHGs; the case-by-case factors 

considered in the BACT analysis; treatment of startups, shutdowns, and malfunctions, 

allowances for performance degradation over the life of the facility, and allowances for 

efficiency losses at part load. 

An initial review of the 36 permits revealed that 5 permits did not include conditions limiting 

GHG emissions. For the remaining 31 facilities, we found construction and operating permits 

delineating various BACT limits for GHG emissions largely based on the following project 

characteristics: 

 Combined cycle combustion turbine design 

o Intended function as base load or load-following unit; 

o Electrical output capacity in megawatts (MW); 

o Heat input capacity in million British thermal units per hour (MMBtu/h); 

o Manufacturer’s design specifications and heat rates; 

o Size and operation of duct burners. 

 Operating Modes 

o Permitted fuels for combustion turbine (primary and backup); 

o Permitted fuels for duct burners; 

o Restrictions on fuel use or duct burner firing; 

o Expected duty cycles (number of starts). 

o Limitations on the duration of startups and shutdowns. 

 Case-by-case design and operating characteristics. 

o Achievable mass emission rates (e.g., tons CO2 per year); 

o Achievable efficiency standards (e.g., maximum heat rate limit in 

MMBtu/kWh); 

The projects reviewed typically included one or more combustion turbines with heat recover 

steam generators (HRSGs) and duct burner systems, a steam turbine, fuel piping and metering, 

an emergency generator, firewater pump engine, auxiliary boiler, cooling water system, electrical 

equipment, an SCR for controlling NOx and an oxidation catalyst for controlling CO emissions 

at part load. Typically, emissions from the NGCC are measured from the HRSG stack, but some 

permits allow operation of the combustion turbine in simple cycle mode with emissions from a 

second stack that precedes the HRSG. Total electrical output is the sum of the output from the 

combustion turbine-generator(s) plus the output from the steam turbine-generator. Gross 

electrical generation accounts for all electricity generated by the unit. Net electric generation is 

the gross electrical generation less the electricity used to supply the plants auxiliary loads. 

BACT Analysis 

In order to comply with the New Source Review pre-construction permitting programs (NSR), 

applicants used the five-step analysis prescribed by the EPA for determining the best available 

control technology under section 165 of the act: 

                                                            

1 A combined cycle power block is comprised of one or more combustion turbines, heat recovery steam generators

(HRSGs), and an associated steam turbine. Some power blocks also include supplemental burners in the HRSG

called duct burners.
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1. Identify all control technologies; 

2. Eliminate technically infeasible options; 

3. Rank remaining control technologies by control effectiveness; 

4. Evaluate most effective controls; 

5. Select BACT. 

The control technologies identified for the 31 NGCC projects with GHG emissions limits 

included carbon capture and storage (CCS) technology, use of renewable resources with hybrid 

power designs, and inherently lower emitting processes and practices. For the CCS evaluations, 

applicants typically followed the EPA’s guidance that this option should only be eliminated 

based on technical feasibility and costs. This technology could be applied as pre-combustion 

capture, post-combustion capture, or oxy-combustion capture. In addition, the transportation and 

storage costs were evaluated. 

Inherently lower emitting processes and practices included technologies or processes that 

maximize the energy efficiency of the individual emissions unit or across the entire facility. The 

available control technologies and energy efficiency measures evaluated included: 

 Boiler design-employ efficient boiler design to meet expected demand needs using 

efficient burners. 

 Periodic maintenance and tuning-per manufacturers' recommendations for 

inspections and maintenance for optimal efficiency. 

 Reduce heat losses-installing insulation on steam turbine and HRSG parts. 

 Instrumentation and controls-control systems to monitor and optimize fuel and air 

flows over a range of load and ambient temperature. 

 Air and fuel flow adjustment-if an appropriate control system is not available, 

manually adjust flows to maximize combustion. 

 Steam cycle efficiency-employ reheat steam cycle with high steam temperatures to 

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

 Heat exchanger design-design to optimize waste heat transfer between the 

combustion turbine exhaust and reduce corrosion at the HRSG outlet. 

 Minimize fouling of heat exchanger surfaces-install air filters, maintain proper water 

chemistry and clean tube surfaces 

 Reduce steam losses-routinely check for and repair steam leaks 

 Use of clean fuels-natural gas has the lowest carbon content of any fossil fuel that 

could be used in this unit. 

The consideration of renewable resources was considered as BACT for some permits. In 

particular, solar-thermal technology was mentioned in several BACT analyses as an alternative 

to using duct burners. Many of these hybrid-type power plant designs were disregarded due to 

lack of available space, lack of reliable renewable resources, or the cost of the technology. 

Each of the 31 permits identified inherently lower emitting processes and practices for a 

highly efficient NGCC as their BACT. Many facilities incorporated the use of only natural gas 

for the NGCCC units to incorporate clean fuels into their BACT. The Palmdale facility also 

identified the incorporation of a 50 MW of solar-thermal plant to be part of their BACT. In 

addition, each facility ruled out CCS technology as BSER because the technology was 

technically infeasible or economically infeasible and had other negative energy and 

environmental impacts. 
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Facility Permits 

Most permit applicants had already selected the manufacturers for their projects, but several 

applications included parallel analyses with multiple manufactures’ emissions and performance 

data to allow subsequent selection. Some applications and permits treated CO2 as the regulated 

pollutant other permits treated CO2e (CO2 + CH4 + N2O with each multiplied by the respective 

GWP) as the regulated pollutant. For NG combustion in NGCC units, the majority of emissions 

are CO2 and many permits used CO2 as a surrogate for calculating emission rates of the other 

two GHGs or assumed that CO2 was equivalent to CO2e. For example, one permit said that since 

the emissions from their unit are calculated to be 99.9 percent CO2, the remaining pollutants 

(CH4 and N2O) are not represented, but still listed the emission limit as CO2e. 

The emission limits in the permits were expressed as output-based limits (mass of CO2 per MWh 

of electrical output) or as a traditional hourly emission rate mass of CO2 per hour. The efficiency 

limits were typically expressed as heat rate limits (British thermal units of heat input per 

kilowatt-hour of electrical output (Btu/kWh). We evaluated limits expressed consistent with the 

form of the NSPS standard (mass of CO2/MWh) or those that were easily converted to this form. 

If a permit included a heat rate limit, then the limit in Btu/kWh was multiplied by 

117 lb CO2/MMBtu (default CO2 emission factor for natural gas from 40 CFR 98 Table C-1) 

and divided by 1,000 kW/MW*MMBtu/Btu to obtain lb CO2/MWh. 

Of the 31 permits, five permits only included limits in the form lbs CO2/hr and were excluded 

from further analyses. One facility was for a combined heat and power unit for which all steam 

generated in the HRSG is routed to an existing utility plant steam header to combine with steam 

produced by the existing utility plant. This plant was also excluded from further analyses. 

For the remaining 25 permits, the nominal plant sizes ranged from 180 MW to 1,620 MW with 

the average plant size around 760 MW. The number of combustion turbines included in each 

permit ranged from one to four. Two of the facilities were permitted to have both combined 

cycle and simple cycle combustion turbines. One plant, Palmdale Hybrid Energy Center, was 

designed to operate with two NGCC units and one 50 MW solar-thermal plant for combined 

generating capacity of 570 MW. This was the only permit that included a facility-wide limit in 

lbs CO2/MWh. The remaining permit limits were specific to individual combustion turbines or 

power blocks. Each permit also included limits for auxiliary equipment that are not discussed in 

this TSD. 

The forecasted capacity factors included in the permit applications for these facilities ranged 

from 50 percent to base load. Several units had specific design features to accommodate more 

efficient cycling and shorter startup cycles to better support the use of intermittent renewable 

generating assets. 

The permits included one or more of the following manufacturers: Alstom, General Electric, 

Mitsubishi and Siemens. Most of the turbine models that were permitted were of the heavy frame 

design. The Alstom model GT24 was included in one permit. From General Electric, most 

models were the 7FA turbine with one permit for an LM6000. Mitsubishi's M501 turbine was 

permitted at four facilities. Finally, the Siemens SGT6-5000 models were permitted at four 

facilities, the FD3-501 at one facility and the SC6-8000H at another facility. The maximum heat 

input ratings ranged from 1,736 MMBtu/h to 11,816 MMBtu/h with an average value of 

3,370 MMBtu/h. 
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Natural gas is permitted as the primary fuel at all facilities. Only three permits allowed the use of 

a fuel other than natural gas; ultra-low sulfur diesel fuel and biodiesels were permitted as backup 

fuels with strict limits on annual usage. 

Twenty-one of the twenty-five permits allowed installation of duct burners. Every duct burner 

was limited to only firing natural gas. Some permits limited the heat input to the duct burners, 

limited operation of the duct burners to periods when ambient temperatures were above a 

specified value, or limited the hours of operation of the duct burners. Duct burner sizes ranged 

from 80 to 770 MMBtu/h with an average of 470 MMBtu/h. 

The permit limits ranged from 774 to 1,100 lb CO2/MWh, as shown in Figure 1. Fifteen permits 

specified CO2 mass limits per gross MWh, while eight specified mass limits per net MWh. The 

highest numerical limit provided on a net basis was 936 lb CO2/MWh-net. This value is about 

100 lb/MWh-net more stringent than the NSPS of 1,030 lb/MWh-net. The auxiliary load 

requirements for NGCC units are typically about a three percent of gross output. There was only 

one permit issued on a gross basis that had a numerical values larger than the final NSPS. This 

value of 1,100 lb/MWh-gross was for a small unit forecasted to operate with a 50 percent 

capacity factor. As discussed later in this document, early operating data indicates this unit is 

actually operating with emission rates lower than 1,000 lbs of CO2 per MWh. 

Figure 1: Permit Limits (lbs CO2 / MWh) 

The monitoring and compliance calculations in these permits were similar to those required in 

the final NSPS. The majority of facilities required CO2 to be continuously monitored via CO2

CEMS. Two permits included monitoring conditions based on Part 75 heat input monitoring in 

conjunction with an emission factor from 40 CFR Part 98 Table C-1 or another designated 

emission factor. All but one of the emission limits were based on a 12-month averaging period or 

 ‐

200

400

600

800

1,000

1,200
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a 365-day rolling average. The Deer Park Energy Center was the one facility that had a permit 

requiring compliance on a 30-day rolling average. 

All of the permits included limits that applied at all times, with the exception of the La Paloma 

Energy Center. The La Paloma Energy Center's limits apply at all times except during startups 

and shutdowns; startups and shutdowns are limited to 500 hours per year. Many permits included 

specific limits for startup and shutdowns. These limits were either expressed as mass per year of 

CO2 or as total hours per year of startups and shutdowns. 

Determination of the permit emission and efficiency limits 

For most permits evaluated, we were able to find additional documentation, typically a GHG 

statement of basis (SOB), detailing how the limits were calculated. The determinations included 

detailed calculations with manufacturers design and guaranteed turbine operating values and fuel 

data to calculate achievable limits over the lifetime of the NGCC unit with manufacturerprovided maintenance and replacements. In arriving at these limits, the permittees accounted for 

expected periods of startup and shutdown, varying loads and cycling due to frequently changing 

demand and energy from renewable resources, and expected unit degradation due to NGCC unit 

wear and operating at non-optimal conditions. Most of the facilities used the same methods and 

percent margins for each of these factors, and usually referred to previously completed BACT 

determinations. The compliance and degradation margins were mostly 10 to 13 percent. These 

percentages typically included a 3 percent design margin reflecting the possibility that 

constructed facility will not be able to achieve the design heat rate, and a 6 percent design margin 

reflecting efficiency losses due to equipment degradation prior to maintenance overhauls, and a 3 

percent degradation margin reflecting the variability in operation of auxiliary plant equipment 

due to use over time. 

Some permits based their limits on the design efficiency and emission limits at 50 percent 

load with full operation of control equipment (for other pollutants) and added a 5 percent 

compliance margin for degradation of the unit over time. The total variance from the design 

conditions for these units ranged from 14 to 17 percent. See the Plant GHG Basis section of this 

document for more detailed permit and SOB discussion of the factors evaluated for each facility. 

Cheyenne Prairie Generating Station 

To directly address commenters concerns that the permit for the Cheyenne Prairie Generating 

Station included a limit of 1,100 lbs of CO2 per MWh compared to the final standard of 1000 lbs 

of CO2/MWh, the EPA reviewed the most recently available operating data for this new loadfollowing unit. During February and March of 2015 this unit operated a total of 54 hours with an 

actual emission rate of 983 lbs of CO2/MWh. It is important to note that the capacity factor[2] of 

this unit during this operating period would have classified this unit as a non-base load unit if the 

unit sustained this capacity factor for 12-months. However despite this low capacity factor the 

unit was capable of operating below the 1,100 lbs of CO2/MWh permit limit and below the level 

of the final NSPS. The EPA must consider these operating data as required by section 111(a)(1). 
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Plant GHG Basis 

The GHG limits determined in the facility permits listed above included detailed 

information the permittees used to arrive at the emission limits. The permit or SOB discussion 

for the CO2 emission limit for each of the 25 facilities with output-based emission limits is 

excerpted below. 

Palmdale Hybrid Energy Center (PHPP)-Emission Limit for CO2 at 774 lb/MWh-net 

The PHPP is designed to use solar technology to generate a portion of the Project’s 

output. The facility will be operated in combined-cycle mode and will be equipped with duct 

burners firing natural gas to increase steam output from the HRSG during periods of peak 

demand. Each CT has a maximum heat input capacity of 1,736 MMBtu/hr (at ISO conditions) 

and will have a dedicated heat recovery steam generator (HRSG) with a 550 MMBtu/hr duct 

burner. Each duct burner will be limited to 2,000 hours of operation per year. On sunny days, the 

solar array is capable of providing 50 MW of the total electrical generation from the steam 

turbine. Based on a review of the available control technologies for GHG emissions from natural 

gas-fired combustion turbines, BACT for this source is the use of new thermally efficient CTs 

and emission limits of 774 lb CO2/MWh for source-wide net output, and 117 lb CO2/MMBtu 

heat input for each gas turbine and duct burner (both based on a 30-day rolling average). The 

emission limits are based on the emission factor provided by the applicant of 53.06 kg/MMBtu, 

the 1,736 MMBtu/hr heat input of each CT operating 8,760 hours per year, and the 550 

MMBtu/hr duct burner for each CT operating 2,000 hours per year. 

In addition, we have determined that the startup duration limits also constitute BACT for 

GHG emissions, because the shorter startup time increases the overall thermal efficiency of the 

facility. Therefore, BACT for the PHPP’s GHG emissions during startup is 110 minutes for a 

cold startup and 80 minutes for a warm/hot startup. 

Based on a review of the available control technologies for GHG emissions from natural 

gas-fired combustion turbines, we have concluded that BACT for this source is the use of new 

thermally efficient CTs and emission limits of 774 lb CO2/MWh for source-wide net output, and 

117 lb CO2/MMBtu heat input for each gas turbine and duct burner (both based on a 30-day 

rolling average). The emission limits are based on the emission factor provided by the applicant 

of 53.06 kg/MMBtu, the 1,736 MMBtu/hr heat input of each CT operating 8,760 hours per year, 

and the 550 MMBtu/hr duct burner for each CT operating 2,000 hours per year. 

A number of issues regarding these limits bear clarification. First, the pollutant that is 

subject to regulation under the Clean Air Act for PSD permitting purposes is a group of six 

gases: carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur 

hexafluoride. As a general matter, it may thus be appropriate to establish BACT limits on a 

CO2e basis. In this case, however, we have elected to establish the BACT limit for CO2 

specifically. The purpose of this is to enable the use of CO2 CEMS for monitoring purposes. 

Because the CEMS are required for other regulatory purposes, they offer a cost-effective and 

reliable method for monitoring compliance. Using CO2 as a surrogate for the total emissions on 

a CO2e basis is appropriate in this case because nitrous oxide and methane are emitted from CTs 

in minor amounts and the majority of the GHG emissions actually are CO2. For example, EPA’s 
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emission factors for CO2, methane, and nitrous oxide from the combustion of natural gas are 

53.06 kg/MMBtu, 0.0059 kg/MMBtu, and 0.0001 kg/MMBtu, respectively. The emission factor 

for all GHGs on a CO2e basis is 53.21 kg/MMBtu. Thus, even after accounting for the global 

warming potential of methane and nitrous oxide, the CO2 emission factor accounts for 99.7% of 

the emission on a CO2e basis. Further, an emission limitation that limits CO2 emissions from the 

combustion of natural gas inherently limits the emission of methane and nitrous oxide. As a 

result, we believe that for this particular source, formulating the emission limits and monitoring 

requirements in terms of CO2 rather than on a CO2e basis is appropriate. The applicant has 

proposed a BACT limit of 1,020,000 tons of CO2 per year for each CT. However, a limit based 

on the amount of CO2 generated per MWh will ensure that the CTs are operating at peak 

efficiency. An input-based limit is also necessary to ensure peak operating efficiency of the gas 

turbine because the solar thermal operation will at times contribute to the electric output. 

Oregon Clean Energy Project (OCE)-Emission limit for CO2e at 833 lb/MWh-gross 

The Project is designed for baseload electricity generation and will utilize state-of-the-art 

combustion turbine technology in combined cycle mode. The Project is proposing to use 

combustion turbines which utilize highly efficient combustion technology. In addition, the 

combustion turbines will combust natural gas as their only fuel source, since this effectively 

minimizes the production of CO2 from combustion relative to other fuels. The proposed project 

has a “Design Base Heat Rate” of approximately 6,687 British thermal units per kilowatt-hour 

(Btu/kW-hr), HHV at ISO conditions (59°F, 71 percent relative humidity) with no duct firing. 

Other permits incorporating GHG requirements were reviewed with GHG emissions limits based 

upon engine efficiency expressed as heat rate and ranged from 7,522 to 7,730 Btu/kW-hr 

(operating at 100 percent load, ISO conditions without duct firing). Several of these permits also 

incorporated emission limits for CO2 in lb CO2/MW-hr. These limits ranged from 887 lb 

CO2/MW-hr gross to 918 lb CO2/MW-hr net, while combusting natural gas. Based on their 

analysis, Bay Area Air Management District (BAAMD) concluded that 12.8 percent was a 

reasonable compliance margin to add to the design base heat rate to develop a numerical BACT 

limit. 

The turbines operating in combined-cycle mode proposed for the Project have a design 

base heat rate of approximately 6,687 Btu/kW-hr at ISO HHV conditions with no duct firing. 

This value is superior to the efficiency proposed in the Russell City Energy Center BACT 

analysis and Cricket Valley Energy design base heat rate. Based upon this design, and adding a 

reasonable margin of compliance consistent with the BAAQMD analysis for Russell City Energy 

Center, OCE proposed BACT to be 7,409 Btu/kW-hr HHV (ISO conditions without duct 

firing);and 896 lb CO2/MW-hr gross (ISO conditions while firing natural gas). These limits are 

consistent with recently permitted projects and can reasonably be assured under all operating 

scenarios. This level of emissions will be achieved through utilization of high efficiency, stateof-the-art, combustion turbine technology and combusting only commercially available, pipeline 

quality natural gas in the turbines. 

One commenter stated that the EPA had inappropriately cited the permit for the Oregon Clean 

Energy Center as evidence of achievability of the standard. Based on this permit analysis, the 

EPA disagrees with this commenter. The EPA directs the commenters attention to page 84 of 86 

under permit condition (gg)(2)(d) which states, 
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“[Compliance] test(s) shall be conducted under those representative conditions that 

challenge to the fullest extent possible a facility’s ability to meet the applicable emissions limits 

and/or control requirements, unless otherwise specified or approved by the appropriate Ohio 

EPA District Office or local air agency. Although this generally consists of operating the 

emissions unit at its maximum material input/production rates and results in the highest emission 

rate of the tested pollutant, there may be circumstances where a lower emissions loading is 

deemed the most challenging control scenario. Failure to test under these conditions is 

justification for not accepting the test results as a demonstration of compliance.” 

The EPA believes that this testing condition in conjunction with the associated numeric 

limit of 833 lbs CO2/MWh is sufficient to ensure that the design and operation of the permitted 

facility will result in an emission limit that does not exceed 1000 lbs CO2/MWh. Additionally, 

the EPA disagrees with the commenters statements that the permit limits expressed in the form 

of a heat rate (e.g., 7,605 Btu/kWh) are significantly different than the form of the final NSPS 

(lbs CO2/MWh) because all recently permitted combined cycle combustion turbines primarily or 

strictly fire pipeline natural gas. Given this fuel a limitation expressed as a heat rate can be 

converted directly to the form of the NSPS using the standard methods of 40 CFR Part 75 as 

allowed by the final rule. 

Carroll County Energy-Emission Limit for CO2e of 859 lb/MWh-gross 

This emissions limitation is based on the following anticipated worst case emissions: 50 

cold startups per year, with a minimum downtime preceding cold startup of 72 hours and a cold 

startup duration of 245 minutes, 250 hot startups per year with a duration of 83 minutes each, 

and hourly CO emissions at ISO conditions during steady state operation of 11.90lbs/hr based on 

manufacturer’s data and steady state operating hours was determined by the following equation. 

(Included here (p. 68 of the PDF) was an equation). Similar equations were derived for NOx. 

Newark Energy Center (NEC)-Emission Limit for CO2 at 887 lb/MWh-gross 

NEC is proposing a limit of 6,774 Btu/kWh LHV (ISO conditions without duct firing) 

(7,523 Btu/kWh at HHV) as well as 887 pounds of CO2 per megawatt hour (gross output) as 

BACT for the proposed project. These limits represent the lowest heat input rate that can 

reasonably be assured under all operating scenarios for these turbines. This level of emissions 

would be achieved through utilization of high efficiency, state-of-the-art, combustion turbine 

technology and combusting only commercially available, pipeline quality natural gas in the 

turbines. The proposed net heat rate for NEC turbines of 6,774 Btu/kWh LHV at ISO conditions 

without duct firing is consistent with other recent GHG BACT determinations that have been 

made in the US. 

FGE Power-Emission Limit for CO2e at 889 lb/MWh-gross 

To determine the appropriate heat-input efficiency limit, FGE started with the turbine’s 

design base load net heat rate for combined cycle operation and then calculated a compliance 

margin based upon reasonable degradation factors that may foreseeably reduce efficiency under 

real-world conditions. The design base load gross heat rates for the combustion turbines being 

considered for this project are as follows: 

 Alstom 
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o 7,625 Btu/kWhr (HHV) without duct burner firing 

o 7,567 Btu/kWh (HHV) with duct burner firing 

These rates reflect the facility’s “gross” power production, meaning the amount of power 

provided to the grid. It does not reflect the total amount of energy produced by the plant, which 

also includes auxiliary load consumed by operation of the plant. To be consistent with other 

recent GHG BACT determinations, the gross heat rate without duct burner firing is used to 

calculate the heat-input efficiency limit. 

To determine an appropriate heat rate limit for the permit, the following compliance 

margins are added to the base heat rate limit: 

 A 3.3% design margin reflecting the possibility that the constructed facility will not 

be able to achieve the design heat rate. 

 A 6% performance margin reflecting efficiency losses due to equipment degradation 

prior to maintenance overhauls. 

 A 3% degradation margin reflecting the variability in operation of auxiliary plant 

equipment due to use over time. 

Design Margin - Design and construction of a combined-cycle power plant involves 

many assumptions about anticipated performance of the many elements of the plant, which are 

often imprecise or not reflective of conditions once installed at the site. Typically, the market for 

contracting the engineering and construction of combined cycle power plants has a design 

margin of 5% for the guaranteed net MW output and net heat rate. This is the condition for 

which the contractor has a "make right" obligation to continue tuning the facility's performance 

to achieve this minimum value. Therefore, the contractor must deliver a facility that is capable of 

generating 95% of the guaranteed MW and must have a heat rate that is no more than 105% of 

the guaranteed heat rate. Given FGE's confidence surrounding the expertise and experience of 

combined cycle power plant construction, FGE has elected to reduce the 5% design margin to 

3.3%. 

Performance Margin on Combustion Turbine and Steam Turbine Generators - The 

performance margin for equipment degradation relates to the combustion turbine and steam 

turbine generators. According to Figure 24 of the California Energy Commission publication 

CEC-200-2010-002, Cost of Generation Model Users Guide Version 2 (March 2010), the 

“sawtooth curve” indicates that the degradation will be limited to 2% between inspections and 

that 75% of that performance will be recovered, resulting in a 20-year degradation of 4.5%. 

According to the combustion turbine vendor (Alstom Power), typically, performance degradation 

during the first 36,000 hours (the normally recommended interval for inspection and 

maintenance) is 2.01% (heat rate degradation) to 2.64% (power output degradation). Alstom also 

indicated that, depending on the equivalent operating hours (EOH), approximately 28% to 44% 

of that performance will be recovered and would result in a 20-year degradation of 

approximately 2.23% and a 25-year degradation of approximately 2.32%. Considering the 

atmospheric conditions at the project location (e.g., high ambient temperature, humidity, and 

~2,200 foot elevation, etc.); FGE has taken a slightly more conservative view of this degradation. 

FGE projects the potential degradation to be 3.5% between the 36,000 EOH inspections 

(considerably less than the potential 4.5% stated in the CEC publication) and, assuming a 44% 

performance recovery, FGE calculated a 20-year degradation of 6%. 
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Degradation Margin for the Auxiliary Plant Equipment - The degradation margin for the 

auxiliary plant equipment encompasses the HRSGs. This margin accounts for the scaling and 

corrosion of the boiler tubes over time as well as minor potential fouling of the heating surface of 

the tubes. Similar to the HRSGs, scaling and corrosion of the condenser tubes will also degrade 

the heat transfer characteristics, thus degrading the performance of the steam turbine generator. 

Because combustion turbine degradation accounts for the majority of the performance loss and 

as well as the large variation in operating parameters (fuels, temperatures, water treatment, 

cycling conditions, etc.), little operating data has been gathered and published that illustrate a 

clear performance degradation characteristic for this auxiliary plant equipment. 

The calculation of the gross heat rate and the equivalent lb CO2/MWh is provided in 

Tables 7 and 8 of the supplemental information provided by FGE on January 17, 2014. The 

BACT limit will apply during startup conditions, shutdown and periods of maintenance (MSS 

will account for no more than 1,460 hours of operation a year). The BACT limit will apply to the 

turbines during all operational conditions, with and without duct burner firing. FGETP shall meet 

the BACT limit on a 12-month rolling average. Each combined MSS event is expected to not 

exceed 240 minutes (including cold startup and shutdown) during combined cycle operations. 

MSS events are estimated as follows: 180 minutes for a cold startup, 151 minutes for a warm 

startup, 56 minutes for a hot startup, and 60 minutes for a shutdown. The MSS emissions will 

also have a per event emission limit of 48 tons CO2/hr during startup, 1,735 lb CH4 per startup, 

192 tons CO2/hr during shutdown, and 510 lb CH4 per shutdown. 

Since the plant heat rate varies according to turbine operating load and amount of duct 

burner firing, FGETP proposes to demonstrate compliance with the proposed heat rate with an 

annual compliance test at 90% load, corrected to ISO conditions. 

FGE requested the BACT limit to be expressed in lb CO2/MWh. When converting the 

BACT limits to tons CO2/MWh, FGETP provides a value of 889 lb CO2/MWh with or without 

duct burner firing. When compared to other BACT limits established for other combined 

cycle/heat recovery steam generating units, and when taking into account the mode of operation 

for the FGE facility, the proposed limits for FGETP are comparable to the limits established for 

LCRA, Calpine Deer Park, Calpine Channel Energy Center, Pioneer Valley Energy Center, and 

PacifiCorp Energy Lake Side Power Plant. The differences in BACT limits between La Paloma 

and LCRA and Cricket Valley Energy Center (CVEC) are related to the net heat rate for the 

turbines. The net heat rate of the turbines proposed by FGETP is higher than those at LCRA and 

CVEC. The BACT limit proposed for FGETP is higher than the limit proposed for Pioneer 

Valley Energy Center (PVEC). PVEC is more likely to operate at base load conditions, whereas 

FGETP will operate as a load cycling unit. The BACT for FGETP (889 lb CO2e/MWh) is less 

than that established for both Calpine facilities (920 lb CO2e/MWh). 

St. Joseph Energy Center-Emission Limit for CO2e 7,646 Btu/kWh-net (894 lb/MWh-net) 

The heat rate BACT limit of 7,646 Btu/kW-hr (HHV) was determined by applying a 

“reasonable margin of compliance” of 12.8 percent to the design net base heat rate of the CCCT 

blocks. A margin of compliance of 12.8 percent over the design base heat rate is consistent with 

the GHG BACT analyses performed for the Russell City Energy Center project, a proposed 600 

MW natural gas fired combined-cycle power plant proposed to be located in Hayward, 

California, and the Cricket Valley Energy Center project, a nominal 1,000 MW natural gas fire 

combined cycle power plant to be located in Dover, New York. For a backup fuel, Diesel fuel 
Page | 13                                                                                                                                          August 3, 2015

was used because it is an independent source of fuel not related to the operation of the facility. 

As such, it is the most reliable fuel source and its use in this application is fundamental to 

meeting power and water requirements in an emergency situation. For this reason, it is the most 

common fuel used for these types of emergency backup applications. 

Pioneer Valley Energy Center-Emission Limit for CO2e at 895 lb/MWh-grid 

Based on the design low heat release rate of 5,948 Btu/kWhgrid, a CO2 emission factor 

of 116 lb/MMBtu, and the fact that 98.5 % of all GHG emissions on a CO2e basis are CO2,16 

EPA calculated an emission rate of 776 lb CO2e/MWh-grid. To determine the emission limit 

which must be demonstrated during PVEC’s initial stack test, accuracy in measuring CO2 and 

the correction curves used to convert stack tests results to ISO conditions must be taken into 

account. Based on these factors, which are outside of PVEC’s control, EPA has calculated an 

emission limit of 825 lbs CO2e/MWhgrid. Since a turbine’s efficiency will degrade with time 

and fluctuate due to ambient conditions, the emission limit of 825 lbs CO2e/MWhgrid will only 

apply during the initial stack test. 

The greenhouse gas emission limit established for installation cannot feasibly be used for 

continuous operations due to a number of factors such as partial load, startups, shutdowns, and 

weather conditions which all affect the turbine’s efficiency. To ensure PVEC operates its facility 

to minimize greenhouse gases, EPA is proposing to establish an ongoing CO2e emission 

limit/MWh to the electric grid. Due to the factors previously listed affecting efficiency, the 

emission limit shall be determined by averaging the emissions for each day and averaging the 

day’s emissions with the previous 364 days of emissions. These factors, along with system 

degradation, will also cause fluctuations with the combined cycle turbine efficiency. 

EPA expects a decrease in efficiency of 2.5% over time even for a well-operated 

turbine.17 In its March 9, 2011 application supplement, PVEC claimed a performance margin of 

6%. EPA understands the performance margin addresses factors affecting the efficiency which 

cannot be controlled by PVEC such as ambient temperature. The actual effect of temperature on 

a combined cycle turbine will vary depending on the turbine’s design. The variation can be as 

much as 10%.18 Based on the information PVEC provided and on EPA’s own research 

regarding unavoidable decreases in efficiency and variability of performance under a reasonable 

range of conditions, EPA has determined that BACT is met by an emissions limit that is 8.5% 

higher than the corrected value which must be met during the initial test. EPA is proposing an 

ongoing emission limit of 895 lbs CO2e/MWhgrid averaged over each 365 consecutive day 

period. 

Green Energy Partners-Emission Limit for CO2e of 903 lb/MWh-gross 

The permit for Green Energy Partners had no special provisions for SSM events, other than 

to minimize them. The plant burns natural gas as the primary fuel and diesel fuel as a backup 

fuel. To determine the heat rate limit for the permit, the following compliance margins were 

added to the base heat rate of 6,550 Btu (HHV)/gross kWh without duct burning and 6,940 

MMBtulhr with duct burning: 

 A 3.4% performance margin reflecting the efficiency losses due to permanent and 

recoverable combustion turbine degradation 
Page | 14                                                                                                                                          August 3, 2015

 A 1.2% degradation margin reflecting operational variation and auxiliary power 

degradation. The operational variation assumes differences in operating techniques 

including but not limited to CT operation, degradation in catalyst life, HRSG tube leaks, 

excessive wear on equipment and design issues causing temporary derates, etc. Auxiliary 

power degradation includes efficiency losses over time of auxiliary (balance of plant) 

equipment including but not limited to pumps, motors, fans, etc. 

 A 7.1% degradation margin reflecting the efficiency losses over time of the steam turbine 

system including but not limited to CT gas performance (i.e., less mass flow), the HRSG, 

the cooling tower, etc. 

Based on these margins a 7,340 Btu (HHV)/gross kWh heat rate limit at full load, without 

duct burning, and a 7,780 Btu (HHV)/gross kWh heat rate limit at full load, with duct burning, 

adjusted to ISO conditions, which will be demonstrated once per Title V permit term. This falls 

into the range of BACT for recently issued or drafted GHG PSD permits. 

The emission rate is 118.28 lb CO2e/MMBtu. The GHG emission limit includes startups, 

shutdowns, and low load operations. To establish a permit limit for continuous performance a 

3% operational margin was added to the heat rate margins cited above. This operational margin 

accounts for dispatch variability and start-up and shut-down events. During startup and shutdown 

events, the combustion turbine power production efficiency is low and the steam turbine is not in 

operation until late in the event resulting in a much higher heat rate. The proposed annual 

average GHG emission rate is 903 lb CO2e/MWh (118.28 lb/MMBtu x 6,612 Btu/kWh x 1.034 x 

1.012 x 1.071 x 1.03 x 1,000 kWh/MW x 1 MMBtu/1,000,000 Btu). 

IPL Eagle Valley-Emission Limit for CO2e of 7,750 Btu/kWh-net (906 lb/MWh-net) 

The exclusive use of pipeline quality natural gas and procurement, installation and 

operation of a high efficiency, low heat rate combined cycle generation facility is GHG BACT 

for this facility. The expected net heat rate for the system operating at full load with duct firing is 

not more than 7,750 Btu/kW-hr (HHV-net), which is consistent with best design practices of 

other similar facilities. This figure is based upon a reasonable margin of compliance (total 

12.8%) for the equipment including a 3.3% design margin, reflecting the possibility that the 

constructed facility may not achieve the design heat rate, a 6% performance margin reflecting 

efficiency losses due to equipment degradation prior to maintenance overhauls, as well as a 3.5% 

degradation margin reflecting the variability in operation of auxiliary plant equipment (e.g. the 

cooling towers) due to use over time. 

LA Paloma Energy-Emission Limit for CO2 of 934.5, 913, and 909.2 lb/MWh-gross 

LPEC requested the BACT limit to be expressed in lbs CO2/MWh. When converting the 

BACT limits to tons CO2/MWh gives a range of 0.455 tons CO2/MWh to 0.467 tons CO2/MWh 

with duct burning. When compared to other BACT limits established for other combined 

cycle/heat recovery steam generating units, the proposed limits for LPEC are comparable to the 

limits established for LCRA, Calpine Deer Park, Calpine Channel Energy Center, Pioneer Valley 

Energy Center, and PacifiCorp Energy Lake Side Power Plant. The differences in BACT 

between La Paloma and LCRA and Cricket Valley Energy Center (CVEC) are related to the net 

heat rate for the turbines. The net heat rate of the turbines proposed by LPEC are higher than 

those at LCRA and CVEC. The BACT limit proposed for LPEC is higher than the limit proposed 

for Pioneer Valley Energy Center (PVEC). PVEC is more likely to operate at base load 
Page | 15                                                                                                                                          August 3, 2015

conditions, whereas LPEC will operate as a load cycling unit. The BACT for LPEC (without 

duct burner firing is 0.437 to 0.443 tons CO2e/MWh) is less than that established for both 

Calpine facilities (0.46 tons CO2e/MWh). 

The LA Paloma plant consists of two turbines rated between 183 and 232 MW each and 

the steam from the HRSGs driving a third electric generator with an electricity output capacity of 

271 MW. As energy efficiency measures, LA Paloma is using Fuel Gas Preheating, drain 

operation, multiple combustion turbine/HRSG trains, and Boiler feed pump variable speed 

drives. To determine the appropriate heat-input efficiency limit, LPEC started with the turbine’s 

design base load net heat rate for combined cycle operation and then calculated a compliance 

margin based upon reasonable degradation factors that may foreseeably reduce efficiency under 

real-world conditions. The design base load net heat rates for the combustion turbines being 

considered for this project are as follows: 

 General Electric 7FA 

o 6674 Btu/kWhr (HHV) without duct burner firing 

o 7051 Btu/kWhr (HHV) with duct burner firing 

 Siemens SGT6-5000F(4) 

o 6782 Btu/kWhr (HHV) without duct burner firing 

o 7045 Btu/kWhr (HHV) with duct burner firing 

 Siemens SGT6-5000F(5) 

o 6891 Btu/kWhr (HHV) without duct burner firing 

o 7204 Btu/kWhr (HHV) with duct burner firing 

These rates reflect the facility’s “net” power production, meaning the amount of power 

provided to the grid; it does not reflect the total amount of energy produced by the plant, which 

also includes auxiliary load consumed by operation of the plant. To be consistent with other 

recent GHG BACT determinations, the net heat rate without duct burner firing is used to 

calculate the heat-input efficiency limit. 

To determine an appropriate heat rate limit for the permit, the following compliance 

margins are added to the base heat rate limit: 

 A 3.3% design margin reflecting the possibility that the constructed facility will not be 

able to achieve the design heat rate. 

 A 6% performance margin reflecting efficiency losses due to equipment degradation 

prior to maintenance overhauls. 

 A 3% degradation margin reflecting the variability in operation of auxiliary plant 

equipment due to use over time. 

Design and construction of a combined-cycle power plant involves many assumptions 

about anticipated performance of the many elements of the plant, which are often imprecise or 

not reflective of conditions once installed at the site. As a consequence, the facility also 

calculates an “Installed Base Heat Rate,” which represents a design margin of 3.3% to address 

such items as equipment underperformance and short-term degradation. 

To establish an enforceable BACT condition that can be achieved over the life of the 

facility, the permit limit must also account for anticipated degradation of the equipment over 

time between regular maintenance cycles. The manufacturer’s degradation curves project 

anticipated degradation rates of 5% within the first 48,000 hours of the gas turbine’s useful life; 
Page | 16                                                                                                                                          August 3, 2015

they do not reflect any potential increase in this rate which might be expected after the first 

major overhaul and/or as the equipment approaches the end of its useful life. Further, the 

projected 5% degradation rate represents the average, and not the maximum or guaranteed, rate 

of degradation for the gas turbines. Therefore, LPEC proposes that, for purposes of deriving an 

enforceable BACT limitation on the proposed facility’s heat rate, gas turbine degradation may 

reasonably be estimated at 6% of the facility’s heat rate. This degradation rate is comparable to 

the rates estimated by other natural gas fired power plants that have received a GHG PSD permit. 

Finally, in addition to the heat rate degradation from normal wear and tear on the 

combustion turbines, LPEC is also providing a reasonable compliance margin based on potential 

degradation in other elements of the combined cycle plant that would cause the overall plant heat 

rate to rise (i.e., cause efficiency to fall). Degradation in the performance of the heat recovery 

steam generator, steam turbine, heat transfer, cooling tower, and ancillary equipment such as 

pumps and motors is also expected to occur over the course of a major maintenance cycle. 

Lower Colorado River Authority (LCRA) Ferguson-Emission Limit for CO2e at 0.459 

ton/MWh-net (918 lb/MWh-net) 

LCRA identified the use of combined cycle power generation technology, the use of CCS 

and, as a supplement to the permit application, the General Electric Rapid Response System and 

solar thermal generating equipment. LCRA identified a GHG BACT analysis that was completed 

for the Russell City Energy Center and the Palmdale Hybrid Power Project. The Russell City 

Energy Center project included two SiemensWestinghouse 501 FD3 combustion turbines and a 

GHG BACT permit condition was established which set the heat rate limit to 7,730 Btu/kWh. 

The Palmdale project consists of two General Electric 7FA natural gas-fired CTGs rated at 154 

MW each, one steam turbine generator rated at 267 MW and 251 acres of parabolic solar-thermal 

collectors with associated heat-transfer equipment. The proposed LCRA GHG PSD permit, if 

finalized, requires a combustion turbine annual net heat rate limit of 7, 720 Btu/kWh (HHV). 

LCRA notes that the solar thermal generating equipment should not be considered for these 

emission units. The solar thermal generating equipment would require an additional auxiliary 

boiler and a heat transfer fluid heater for the solar steam unit. Therefore, the C02 emission from 

these sources could exceed the GHG reductions resulting from the anticipated reduction in 

startup time. CCS was ruled out due to cost and inadequate demonstration. It was determined 

that the most efficient method to generate electricity from a natural gas fuel source is the use of a 

combined-cycle design. The major components incorporated into a combined-cycle unit are a 

combustion turbine, a heat recovery generator (HRSG) and a steam turbine. Specific energy 

efficiency processes, practices and designs are included in the permit application for each 

component of the combined cycle unit. 

The GHG BACT limit is calculated from emission factors and the annual average heat 

rate (HHV), 7,720 Btu/kWh, and includes a 5 percent degradation factor and seasonal variation. 

From the calculations, with the emission units running at 100 percent gross load and a heat rate 

of 7720 Btu/kWh, the facility base load efficiency is calculated to be approximately 50 percent. 

However, it is anticipated that the facility will operate at a range of loading scenarios and a 50 

percent gross load may be more characteristic of normal operations. LCRA has submitted an 

analysis of the facility's heat input rate for 50 percent, 75 percent and 100 percent gross load 

scenarios. At 50 percent gross load, the facility efficiency is calculated to be approximately 44 

percent. The permit application indicates 50 percent efficiency and for this efficiency the gross 
Page | 17                                                                                                                                          August 3, 2015

load is 100 percent. The calculation method proposed by LCRA to calculate the BACT limit 

contains only one variable, the amount of beat going to the CTG averaged on a 12-month basis 

assuming 50 percent gross load (includes seasonal variation averages). With LCRA's proposed 

BACT calculation method, relying only on the quantity and quality of fuel being consumed does 

not demonstrate the operation of a unit in an efficient manner. In order to more accurately 

measure efficiency, EPA is requiring LCRA to measure the actual heat input in MMBtu per hour 

and measure the pounds of C02 on an hourly basis with a C02 emissions monitor. This analysis 

can be completed utilizing the updated Fe factor, 40 CFR Part 75, Appendices F and G, and a 

conversion methodology similar to the equations provided for S02 and NOx in the Air 

Calculations and Conversions Guide. 

For startup and shutdown, short term (hourly) limits are provided. The startup and 

shutdown annual emissions are not expected to exceed the normal operations annual emissions. 

All emissions during startup and shutdown are minimized by limiting the duration of operation. 

Deer Park Energy Center-Emission Limit for CO2 of 7,730 Btu/kWh (920 lb/MWh-net) 

Calpine intends to initially construct and install an FD2-series combustion turbine with 

plans to modify it within an eighteen (18) month period to the FD3-series combustion turbine. 

Since CCS was eliminated as BACT for CTG5, then BACT for the new combined-cycle 

combustion turbine is the high efficiency processes, practices and designs which are made 

enforceable by output-based and annual BACT limits. The average heat rate in terms of Btu/kWh 

(HHV) will be the same for the FD2 configuration as the FD3 configuration when in continuous 

operation, since the FD2-series and FD3-series combustion turbines have the same efficiency. 

However, the FD3 configuration provides greater output at high ambient temperatures during 

base load periods. Therefore, for the FD3, the potential annual electric generation (MWh) and 

fuel usage, as well as corresponding GHG emissions, will be higher on an annual basis, 

maximum CO2e potential emissions will increase by only two percent (2%) from 1,045,635 tons 

for the FD2-series to 1,063,650 tons of CO2e for the FD3-series combustion turbine. 

The permit limit accounts for the anticipated degradation of the equipment over time 

between regular maintenance cycles. A 48,000-operating-hour degradation curve provided by the 

manufacturer, Siemens, reflects anticipated recoverable and non-recoverable degradation in heat 

rate between major maintenance overhauls of approximately five percent (5%). The results of the 

degradation curves differentiate between “recoverable” and “non-recoverable” degradation. 

Components of the turbine and combustion system subject to high thermal and mechanical stress 

are designed for periodic refurbishment or replacement. The turbine components most affected 

by the combustion process include combustion liners, fuel nozzle assemblies, transition pieces, 

turbine nozzles, stationary shrouds, and turbine buckets. These components are often referred to 

as “hot gas path” components. “Recoverable” degradation is mostly attributable to turbine blade 

fouling due to impurities in intake air and fuel. This type of degradation can be mitigated through 

inspection programs, on-line turbine water washes, instrument calibration, and other 

maintenance activities. “Non-recoverable” degradation is mainly attributed to blade surface 

roughness, erosion and blade tip rubs and cannot be restored upon a maintenance overhaul. The 

manufacturer’s degradation results only account for the anticipated degradation within the first 

48,000 hours of the gas turbine’s useful life; they do not reflect any potential increase in this rate 

of degradation which might be expected after the first major overhaul and/or as the equipment 

approaches the end of its useful life. Further, the projected 5% degradation rate represents the 
Page | 18                                                                                                                                          August 3, 2015

average, and not the maximum or guaranteed rate of degradation for the turbines. Therefore, for 

the purposes of deriving an enforceable BACT limit on the proposed facility’s heat rate, gas 

turbine degradation may be reasonably be estimated at six percent (6%) of the facility’s heat rate. 

A compliance margin based on potential degradation in other elements of the combinedcycle plant that would cause the overall plant heat rate to rise (i.e., cause efficiency to fall) of 3% 

degradation rate to account for these factors. The other elements of the combined-cycle plant 

degradation in turbine exhaust flow, degradation in performance of steam turbine and other 

equipment 

To determine an appropriate heat rate limit for continuous operations, the baseline annual 

average heat rate (HHV) of 6,852 Btu/kWh is used with the 3.3% design margin taken into 

account followed by a six percent (6%) performance margin reflecting efficiency losses due to 

equipment degradation prior to maintenance overhauls, and then a three percent (3%) 

degradation margin reflecting the variability in operation in auxiliary plant equipment due to use 

over time, resulting in the annual average heat rate (HHV) of 7,728 Btu/kWh (See Appendix, 

Table 4). Additionally, to determine the heat input limit for this facility, the heat rate is 

calculated assuming that all steam generated in the heat recovery steam generator is used to 

generate electricity in the existing on-site steam turbine even though there are periods when 

some or all of the generated steam is sold to a neighboring facility rather than sent to the on-site 

steam turbine. 

The proposed GHG PSD permit requires an output-based BACT limit of 0.460 tons 

CO2/MWh (net) for both the FD2 and FD3 engines on a 30-day rolling average and an annual 

GHG BACT limit of 1,045,635 tons CO2e per year for the FD2 series engine and 1,063,650 tons 

of CO2e per year for the FD3 series engine on a 365-day rolling average. This is with the 

understanding that the FD2 series will be upgraded to the FD3 series within a statutory 

timeframe of 18 months under the conditions of this permit. In establishing an enforceable 

BACT limit over the lifetime of the turbine, Calpine accounted for the anticipated degradation of 

the equipment over time between regular maintenance cycles, as discussed in this section. 

Brunswick Plant-Emission Limit for CO2e of 920 lb/MWh-net 

This plant will provide baseload power from its location in Brunswick, VA. For BACT 

determination, efficient power generation and the use of low carbon fuels, were proposed for this 

facility and were accepted as BACT. Due to differences in size, manufacturer, configuration, 

cooling practice, elevation, and the method used to determine the heat rate among the permitted 

power plants across the country, some variability in BACT determinations is expected, however, 

DEQ determines that the proposed emission level of CO2e and level of energy efficiency are 

BACT for this facility. The plant will be required to operate at a higher heating value heat rate of 

no more than 7,500 Btu/KWh (based on a degradation estimate for a new 6,695 Btu/kWh unit – 

HHV/net), and emit CO2e at an average annual rate not to exceed 920 lb CO2e/MWh (which 

reflects a 119.12 lb CO2/MMBtu average monitored emission rate at similar facilities adjusted 

by a 3% margin to account for emissions from SU/SD and low load operation) - both of which 

fall into the range of BACT of recently issued or drafted GHG PSD permits. The degradation 

estimate is based on a 3.4% performance margin of the combustion turbines, a 1.2% degradation 

margin for the auxiliary power, and a 7.1% degradation margin for the steam turbine system – 

6695 x 1.034 x 1.012 x 1.071 = 7500 Btu/kWh net HHV. And 119.2 lb/MMBtu x 7500 Btu/kWh 

x 1.03 x 1,000 kWh/MW x 1 MMBtu/1,000,000 Btu = 920.2 lb/MWh HHV net. 
Page | 19                                                                                                                                          August 3, 2015

Woodbridge Energy Center-Emission Limit for CO2 of 925 lb/MWh-gross 

The appropriate heat rate limit for the WEC turbines was determined by applying the 

following compliance margins to the base heat rate, consistent with other recent GHG BACT 

applications: a 3.3% design margin reflecting the possibility that the constructed facility will not 

be able to achieve the design heat rate, a 6% performance margin reflecting efficiency losses due 

to equipment degradation prior to maintenance overhauls, and a 3% degradation margin 

reflecting the variability in operation of auxiliary plant equipment due to use over time. This heat 

rate is equivalent to a net plant efficiency of 56.2% Lower Heating Value (LHV). The heat rate 

and efficiency is based on the gas turbines at base load without duct firing. Assumes 6% 

performance margin, 3.3% design margin, and 3% degradation margin. Based on the above 

criteria, Woodbridge Energy Center proposes as BACT net heat rate for the Project of 7,605 

Btu/kWh (HHV), corrected to ISO conditions with ambient dry bulb temperature of 59oF, 

ambient relative humidity of 60%, barometric pressure of 14.69 psia, fuel lower heating value of 

20,646 Btu/lb LHV, fuel HHV/LHV ratio of 1.109, and gas turbines at base load with duct firing 

off. The proposed net heat rate for WEC turbines of 7,605 Btu/kWh (HHV) is consistent with 

other recent GHG BACT determinations. 

CPV Valley-Emission Limit for CO2 of 925 lb/MWh-gross 

This plant limit represents the maximum firing rate (2,234 MMBtu/hr at -5 degrees F) 

and the quantity per year throughput represents the turbine at the firing rate at the annual average 

ambient temperature of 51 degrees F (1,998 MMBtu/hr). Natural Gas higher heating value is 

assumed to be 1,048 Btu/Cubic Foot. To minimize GHG operates the combustion turbines in 

combined cycle mode with natural gas as the primary fuel and proposes a heat rate limit of 7,605 

Btu/kW-hr (57.4% efficiency (LHV)) at full load ISO conditions without duct firing (based on 

net output). Compliance with the heat rate limit will be determined through stack testing prior to 

commercial operation. 

Total annual CO2e emissions from the two combined cycle units will be limited to 

2,183,223 tons/year (or 1,091,611.5 tons/year/unit). This limit reflects full load 8,760 hours of 

operation per year per turbine with the maximum amount of duct firing and backup fuel oil firing 

proposed. 

Troutdale Energy Center-Emission limit for GHG (CO2e) at 1,000 lb/MWh-gross 

Lower GHG limits were not appropriate for this facility because it is intended to operate 

with frequently changing loads rather than operating at relatively steady loads, and this mode of 

operation would make it difficult to meet lower limits. This facility will be used to integrate with 

power generated by wind turbines which have a variable output due to changes in the wind, and 

will therefore experience frequent load changes. During load increases, the power output of the 

turbine must be increased to match the higher load. Increasing the power output of the turbine 

requires the use of extra fuel over the amount required to run at steady-state at the higher power 

output, which also increases GHG emissions over the steady-state emission rate. In addition, the 

GHG emission limit proposed by the applicant accounts for the use of ULSD, which has higher 

GHG emissions, up to 720 hours per year in each turbine. This limit is for all times including 

startup, shutdown and malfunction. The BACT determination is based on thermal efficiency and 

clean fuels, although carbon capture and storage was also evaluated and dismissed. 
Page | 20                                                                                                                                          August 3, 2015

The combined-cycle power plant is intended to provide base load power. However, as 

with most generation units in the Pacific Northwest, due to the variability of renewable and 

hydro-generation output, the combined-cycle power plant at the Troutdale Energy Center could 

also be load following. The combined-cycle plant is therefore not comparable to base load 

resources in other parts of the country where intermittent renewable energy resources do not 

represent a significant portion of the region’s capacity and energy. The combined-cycle plant 

will follow net load after hydropower and wind generation which are typically the first call 

resources. The combined-cycle power plant is not designed to provide power for short term, 

sudden demand surges. That sort of peak duty cycle would normally be met through simplecycle combustion turbines. However, the combined-cycle plant is expected to operate as low as 

50 percent load (burning natural gas) so as to be able to ramp up more efficiently and fill base 

load needs as wind and hydro resources diminish. This flexibility reduces the need to operate less 

efficient resources and makes the combined-cycle unit an optimal reserve generation resource for 

balancing unscheduled variations in output from variable output generation resources like wind 

turbines. 

DEQ notes that pollutant emission rates are typically at a maximum when equipment is 

operated at its maximum rate, and indeed the tables indicate that GHG emission in tons per hour 

are at their maximum at full load and are lower at low loads. However, and perhaps counterintuitively, GHG emissions in pounds per megawatt-hour are at their minimum at full load and 

are higher at low loads. DEQ understands that all combustion turbines exhibit the same basic 

performance characteristics; that is, they operate at maximum efficiency at full load and at lower 

efficiency at lower loads. Lower efficiency at lower loads means using more fuel per MWh 

generated. Since GHG emissions are directly related to the amount of fuel used, using more fuel 

per MWh at lower loads also means emitting more GHGs per MWh. 

DEQ recognizes that operating combustion turbines at low load, where they are less 

efficient, seems to contradict the idea that BACT for combustion-derived GHGs is generally 

considered to be the use of equipment that exhibits the highest energy efficiency.GHG BACT for 

this type of facility must be considered within the context of electrical power generation overall, 

particularly wind energy. Availability and reliability of wind may vary unexpectedly resulting in 

variable output from wind generation resources. One of the stated purposes of the Troutdale 

Energy Center is to integrate with wind power, which means this facility is intended to provide 

rapidly available energy to “fill in” when wind power declines. This results in the need to operate 

this facility at varying loads, a mode of operation that is inherently less efficient than operating 

continuously at full load. This is an unavoidable consequence that will often result in a higher 

GHG emission rate, on a lb/MWh basis, when the facility is operating. The fact that wind power 

is available at times means that, generally, less fuel overall must be burned to generate 

electricity. So, while an individual generating facility may have to operate in a less efficient 

manner, the electrical generating system as a whole is able to be more energy efficient, thus 

broadly achieving the energy efficiency goal of GHG BACT. Finally, DEQ notes that while lowload operation is less efficient, the actual GHG emission rate on a ton per hour basis is lower 

when operating at low load. 

DEQ reviewed the GHG BACT limits for the facilities identified by the commenters, Port 

Everglades Energy Center5, Pio Pico Energy Center6 and Puget Sound Energy Fredonia 

Generating Station Expansion Project7. The GHG BACT limits for these facilities are show 
Page | 21                                                                                                                                          August 3, 2015

below, along with the full load GHG emission rates for the turbines at the proposed Troutdale 

Energy Center (TEC): 

Simple Cycle Combustion Turbine 

Proposed BACT: Annual Average 1,707 CO2 lb/MWh 

Fuel Type NG NG NG NG ULSD ULSD ULSD NG ULSD 

Load Level (%) 100 75 50 25 100 75 50 SUSD SUSD 

Gross Plant Output 

(kW/hr, with 10% 

Degradation factor) 

95,663 72,545 47,467 23,341 91,574 68,675 45,791 

Fuel Flow 

(MMBtu/hr, HHV) 

929.5 736.4 555.2 356.6 893.6 716.4 541 

CO2 Emissions 

(lb/MWh equivalent 

gross w/10% 

degradation) 

1,136 1,203 1,367 1,786 1,591 1,701 1,927 

CO2 (tons/hr) 54 43 32 21 73 58 44 30 40 

Hours/Yr 0 438 1,840 4,713 0 0 1,440 203 127 

CO2 (tons) 0 18,854 59,702 98,239 0 0 63,350 6,097 5,081 

Output (MWh 

equivalent gross) 

0 31,337 87,319 110,00

1 

0 0 65,946 0 0 

Combined Cycle Combustion Turbine 

Proposed BACT: Annual Average 1,002 CO2 lb/MWh

HRSG Firing Unfired Fired Unfired Unfired Unfired Unfired 

Fuel Type NG NG NG NG ULSD ULSD NG ULSD 

Load Level (%) 100 100 75 50 100 60 SUSD SUSD 

Gross Plant Output (kW 

hr, with 10% 

degradation factor) 

359,622 411,660 278,514 210,618 285,777 185,508 
Page | 22                                                                                                                                          August 3, 2015

Fuel Flow (MMBtu/hr, 

HHV) 

2,595 3,092 2,106 1,662 2,298 1,599 

CO2 Emissions (lb/MWh 

equivalent gross w/10% 

degradation) 

844 878 884 923 1,311 1,406 

CO2 (tons/hr) 152 181 123 97 187 130 97 130 

Hours/Yr 613 613 613 5,158 0 1,440 277 45 

CO2 (tons) 93,027 110,827 75,485 501,178 0 187,760 26,851 5,853 

Output (MWh 

equivalent, gross) 

220,520 252,430 170,785 1,086,45

5 

0 267,158 0 0 

DEQ notes that the GHG emission rates for the turbines at the proposed Troutdale Energy 

Center at full load when firing natural gas are generally comparable to the BACT limits shown 

above. DEQ further notes that the documents referenced by the commenters did not discuss 

GHG emission rates in lb/MWh at low load, nor did DEQ find any other documents related to 

these facilities that discussed GHG emission rates in lb/MWh at low load. It appears to DEQ that 

the BACT limits were set at the full load emission rates, and that the BACT limits above would 

limit the operation of these facilities to full or close to full load at all times. As discussed above, 

consideration of emission rates at low load is appropriate in the BACT determination for the 

TEC facility given its relation to wind power. 

A BACT determination cannot be used to redefine a facility. The stated purpose of the 

proposed Troutdale Energy Center is to provide base load, load following and peaking power, 

and this requires the facility to operate all combustion turbines at low loads much of the time. 

DEQ believes that setting GHG BACT limits at levels that can only be achieved at or near full 

load would require the applicant to operate only at or near full load at all times. This would 

prevent the facility from operating in the intended manner and would constitute redefining the 

facility to a base-load only generating plant. Therefore DEQ cannot set GHG BACT limits at or 

near levels that can only be achieved at full load. 

The applicant has presented potential operating scenarios in Tables 1 and 2 (on page 23) 

which might reasonably occur in practice and which DEQ believes represent reasonable worstcase scenarios. The GHG BACT limits proposed in the draft permit are based on these scenarios 

and properly take into account the higher GHG emission rates (on a lb/MWh basis) at lower 

loads. 

In consideration of all of the above, DEQ does not agree with commenters and finds that 

the GHG BACT limits proposed for Troutdale Energy Center’s combustion turbines are 

reasonable and correct for the way this particular facility is intended to operate. 
Page | 23                                                                                                                                          August 3, 2015

With respect to the comment that DEQ should establish separate GHG BACT limits for 

natural gas and ULSD operation, DEQ notes that the proposed GHG BACT limits differ 

significantly from other proposed BACT limits in the draft permit in that the GHG BACT limits 

are long-term limits (annual average) as opposed to short-term limits (averaged over hours). 

DEQ also notes that the proposed GHG BACT limits are based on a reasonable annual operating 

scenario that accounts for all potential modes of operation. If separate GHG limits were 

established for natural gas and ULSD, they would be established in much the same way, based 

on potential operating scenarios that are reasonably possible and reflect the stated purpose of the 

facility. Recalculating limits in this manner will not serve to further limit GHG emissions from 

this facility. DEQ therefore does not agree with commenters that there is a legal requirement to 

establish separate GHG BACT limits in terms of lb/MWh for natural gas and ULSD. 

CPV Energy St. Charles – GHG limit of 3,217,553 TPY CO2e based on a 12 m.r.a. 

5.2.5.1 Step 1—Identify Available Control Options 

Step 1 of the top-down BACT analysis is the identification of available control technologies or 

techniques, including inherently lower-emitting processes/practices/designs, addon controls, and 

a combination of inherently lower-emitting processes/practices and addon controls, that have a 

practical application to the control of GHG emissions. These control technologies must include 

control technologies for the pollutant under evaluation, GHG, regardless of the source category 

type. For example, control technologies must be identified not only for those demonstrated on 

other combined-cycle CT facilities but also for control technologies determined through 

technology transfer applied to source categories with similar exhaust stream characteristics. 

Technologies that formed the basis of an applicable NSPS should also be considered in the 

BACT analysis, since a BACT emissions limit cannot be less stringent than an applicable NSPS 

emissions limit. The CT/HRSGs are subject to the NSPS for stationary CTs, 40 CFR 60, Subpart 

KKKK. 

It is important to note and must be emphasized that available control technologies should not 

include inherently lower-emitting processes/practices/designs that would fundamentally redefine 

the nature of the proposed source. A BACT analysis should not consider those control 

technologies that would change or redefine that applicant’s goal, objectives, purpose, or basic 

design. A BACT analysis may consider control technologies that change aspects of the proposed 

facility but do not redefine the nature of the proposed facility. 

The available control technologies for GHG emissions for the 7FA.05 CT/HRSG at CPV St. 

Charles are high thermal efficiency system design and carbon capture and sequestration (CCS). 

High Thermal Efficiency System Design 

Increased energy efficiency is a potential means of reducing GHG emissions and should be 

considered as a potential control technology for GHG emissions. There are generally two types 

of categories of energy efficiency improvement categories. The first category consists of 

technologies, process improvements, or other means of increasing the energy efficiency of the 

new source. Increased energy efficiency of the new source will result in less quantity of fuel 

combusted per unit of output. In the case of a combined-cycle CT, the unit of output would be 

kilowatt-hour or megawatt-hour of electrical output. In the case of a process boiler, the unit of 
Page | 24                                                                                                                                          August 3, 2015

output would be pound per hour of steam generated. It is EPA’s opinion that the available 

technologies for this first category will not be significantly different than those technologies 

considered for other NSR pollutant BACT analyses. 

The second category of energy efficiency improvements consists of technologies, process 

improvement, or other means of improving the amount of energy that is generated or used on the 

site. This second category does not look at the direct GHG emissions from the new source 

(which was evaluated in the first category of energy efficiency options) but looks at other facility 

processes or ancillary equipment that could reduce the amount of energy consumed. Potential 

technologies included in this category may include increasing the efficiency of process 

equipment such as a heat exchanger, fans, pumps, etc., as well increasing the energy efficiency 

of ancillary equipment such as standalone emergency generators, firewater pumps, hot water 

heaters, lighting, etc. EPA does not recommend an individual evaluation of each and every 

energy efficiency option in this second category due to the potentially large number of options. 

Rather, EPA recommends new facilities evaluate their overall energy efficient technologies 

against a high-level performance facility in the industry to demonstrate that the facility will 

achieve comparable levels of energy efficiency. 

Carbon Capture and Sequestration 

CCS consists of the separation and capture of CO2 from the flue gas, pressurization of the 

captured CO2, transportation of the CO2 as a fluid via pipeline, and injection and longterm 

geologic storage. 

The capture technologies applicable for fossil fuel combustion include the following: 

 Precombustion systems designed to separate CO2 and hydrogen in the highpressure 

syngas typically produced at integrated gasification combinedcycle power plants. 

 Postcombustion systems designed to separate CO2 from the flue gas produced by the 

combustion process. 

 Oxy-combustion systems that use high-purity oxygen rather than air in the combustion 

process to produce a highly concentrated CO2 stream. 

Precombustion systems are not technically feasible for CPV St. Charles, since they would 

fundamentally redefine the nature of the proposed source. Both post- and oxy-combustion 

systems would be considered technically feasible, and both are currently in development as 

demonstration projects at coal-fired power plants using amine and ammonia capture systems to 

remove the CO2 from the flue gas. These capture systems are associated with high-energy 

penalties. 

There are several technologies at various stages of development with the potential to separate 

and capture CO2. Some have been demonstrated at the pilot scale, while others are at the benchtop or laboratory stage of development. Most of the existing applications,\ and those in the 

planning stage, are designed to control CO2 from the combustion of fossil fuels, primarily coal 

and natural gas. EPA considers municipal solid waste to be a biomass fuel that can be cofired 

with fossil fuels to reduce the CO2 emissions from boilers (EPA, 2010). Several demonstration 

projects are being supported through the U.S. Department of Energy’s Clean Coal Power 

Initiative, but these facilities will exclusively burn coal (Interagency Task Force, 2010). 

Carbon sequestration usually involves the injection of CO2 into deep geological formations of 

porous rock that are capped by one or more nonporous layers of rock. Injected at high pressure, 
Page | 25                                                                                                                                          August 3, 2015

the CO2 exists as a liquid that flows through the porous rock to fill the voids. Saline formations, 

exhausted oil and gas fields, and unmineable coal seams are candidates for CO2 storage. Also, 

CO2 injected for enhanced oil recovery projects can result in long-term sequestration depending 

on the geologic conditions. Other schemes include liquid storage in the ocean, solid storage by 

reactions leading to the creation of carbonates, and terrestrial sequestration. 

Clean Fuels 

The CAA includes clean fuels in the definition of BACT; therefore, clean fuels should be 

considered as a potential control technology for GHG emissions. Fuels that reduce GHG 

emissions of a new source should be considered in a BACT analysis provided they do not 

redefine the source. For example, a proposed new coal plant should not have to consider 

switching fuels from coal to natural gas as that would redefine the source. However, different 

types of coal may be considered to evaluate the benefits of combusting various types of coal in 

reducing GHG emissions. 

5.2.5.2 Step 2—Eliminate Technically Infeasible Options 

Step 2 of the top-down BACT analysis is the elimination of technically infeasible options. EPA 

considers a technology to be technically feasible if: (1) it has been demonstrated and operated 

successfully on the same type of source under review, or (2) it is available and applicable to the 

source type under review. A control technology should also be considered technically available 

or applicable if it has been demonstrated on an exhaust stream with similar physical and 

chemical characteristics. 

CCS is not considered technically feasible for a natural gas-fired combined cycle facility. Carbon 

capture technology has not been demonstrated on a full-scale power generation facility and is not 

currently commercially available. In addition, there has been no demonstration of carbon capture 

technology on a similar exhaust gas stream. There are no known carbon sequestration geological 

storage sites commercially available in close proximity to the St. Charles project site. 

5.2.5.3 Step 3—Ranking of Controls 

Step 3 of the top-down BACT analysis is the ranking of technically feasible options. The energy 

efficiency must look at the high thermal efficiency design of the CT as well as various energy 

efficiency improvements throughout the facility. CPV Maryland has elected to propose the 

higher thermal efficient GE 7FA.05 CT in lieu of the previously proposed and permitted GE 

7FA.04 CT. The GE 7FA.05 CT provides a lower heat rate, expressed in units of Btu/kWh, and 

thus combusts less fuel per kilowatt-hour (kWh) of electrical power output. Combusting less fuel 

produces less GHG emissions per kWh electrical power output. 

Combustion sources proposed for the St. Charles project will be newly manufactured equipment. 

There will be no equipment that was previously used at another location. Therefore, combustion 

equipment will meet the most current efficiency and emissions standards for each type of 

combustion source. 

5.2.5.4 Step 4—Economic, Energy, and Environmental Impacts 

Step 4 of the top-down BACT analysis is the consideration of economic, energy and 

environmental impacts. The CPV St. Charles facility will use the higher efficiency GE 7FA.05 

CT and is committed to the exclusive combustion of pipeline-quality natural gas in the 
Page | 26                                                                                                                                          August 3, 2015

CT/HRSGs, auxiliary boiler, and fuel gas heater and ULSD in the emergency ICEs. Therefore, 

no further analysis of economic, energy or environmental impacts is necessary. 

5.2.5.5 Step 5—Selecting BACT 

Step 5 of the top-down BACT analysis is the selection of BACT. 

5.2.5.6 Proposed GHG BACT Emissions Limits 

CT/HRSG 

CPV St. Charles proposes a GHG BACT emissions limit of 3,217,553 short tons of CO2e per 

year for two CT/HRSGs based on a rolling 12-month average. This GHG BACT emissions limit 

is based on the GE 7FA.05 high efficiency CT and the exclusive use of pipeline-quality natural 

gas. Compliance with this GHG BACT emissions limit will be demonstrated by the total heat 

input, expressed in MMBtu/yr, for the two CT/HRSG units. EPA-recommended emissions 

factors and global warming potentials will be used to calculate GHG emissions as shown in 

Appendix C, Table C-16. 

Austin Energy Sandhill – GHG limit of 0.81 ton CO2e/MWh without duct burning 

The City of Austin (dba Austin Energy) proposes as BACT for this project, the following energy 

efficiency processes, practices, and designs for the proposed combined cycle combustion turbine: 

 Use of Combined Cycle Power Generation Technology 

 Use of natural gas as the exclusive fuel 

 Efficient turbine design 

The proposed GE 7FA.04 combustion turbine is the most efficient unit available that is suitable 

for incorporation into the existing combined cycle unit as described above, with a gross heat rate 

at base load ranging from 9,744 to 10,639 Btu/kWh, HHV, at base load without evaporative 

cooling, depending on ambient conditions (refer to Table 5‐3). For comparison, the existing SH5 

unit combustion turbine, as GE 7FA.03 model, has a heat rate ranging from 10,004 to 11,055 

Btu/kWh, HHV, across the same range of conditions, so the newer model is about 3 to 4% more 

efficient, translating to 3 to 4% lower GHG emissions. Other manufacturers have made similar 

improvements: a chief competitor to the GE 7FA, the Siemens 5000F (Westinghouse 501F) 

turbine; has improved simple cycle efficiency from approximately by approximately 4% over the 

last 20 or so years. In combined cycle mode, with the benefit of the HRSG and additional output 

from the STG, the gross heat rate of the proposed GE 7FA.04 unit is expected range to from 

7,044 to 7,328 Btu/kWh, HHV without evaporative cooling. 

Because the new combustion turbine will be added to an existing combined cycle unit and its 

HRSG will provide steam to a steam turbine generator that is shared with the existing turbine, it 

is not possible to determine a combined cycle heat rate standard and output‐based GHG limit that 

is separate from the performance of the existing SH5 turbine and HRSG performance. The SH5 

unit was permitted prior to GHG BACT requirements and as such has no GHG emission limit or 

heat rate limit in its permit conditions. Therefore, the City of Austin is proposing GHG BACT 

limits based on the new combustion turbine alone (simple cycle basis) without duct burner firing: 
Page | 27                                                                                                                                          August 3, 2015

 Simple cycle output‐based GHG limit of 0.81 ton CO2e/MWh combustion turbine gross 

output basis; equivalent to 0.458 ton CO2e/MWh (or 916 lb/MWh) gross output basis for 

the combined cycle unit that shares the STG with the existing SH5 combustion turbine, 

with unfired HRSG 

 Simple cycle combustion turbine gross output heat rate of 13,872 Btu/kWh (HHV); 

equivalent to 7,833 BTU/kWh (HHV) gross heat rate for the combined cycle unit that 

shares the STG with the existing SH5 combustion turbine, at 68°F with unfired HRSG 

The proposed output‐based GHG emission limits are equivalent to the most recent GHG permit 

limits for similar combined cycle units as summarized in Table 5‐1 (approximately 0.466 ton 

CO2e/MWh or 932 lb/MWh, combined cycle basis) and the proposed heat rate limit is 

comparable to the most recent limits for similar units. 

As with other recent GHG permits for combined cycle units, compliance with these performance 

standards is determined for operation at 100% load at ISO conditions, without evaporative 

cooling or duct burner firing. This provides a standard basis for comparison of the GHG limits 

that are permitted for different projects. In order to demonstrate that the proposed simple cycle 

GHG limit corresponds to the combined cycle performance indicated above, the City of Austin 

proposes to perform the initial compliance test with only the new combined cycle unit operating 

(i.e., with SH5 off line). In order to regulate GHG emissions from all operating conditions, 

including those using evaporative cooling and with duct burner firing, the City of Austin is also 

proposing a GHG BACT limit on total annual GHG emissions for the combined cycle 

combustion turbine and duct burner: 

 Annual emission cap of 1,461,818 tons CO2e per year, for the addition of the second 

combustion turbine, HRSG and duct burner 

The proposed GHG BACT limits for the proposed new unit are summarized in Table 5‐4 below. 

This approach of a combination of output based CO2e limits and heat rate limits at standard 

conditions and an annual emission cap to cover other operating conditions and emissions has 

been used in other recent GHG BACT permit limits for combined cycle units. 

Each of the proposed limits is calculated to include a 10% margin to account for measurement 

error, equipment and site variations, and degradation over time. 

Compliance with the output based emission limits will be based on a 30‐day rolling average. 

Compliance with the annual tons/year limit will be based on a rolling 365‐day total. In each case, 

SHEC proposes to calculate GHG emissions based on continuous monitoring of the fuel flow to 

the combustion turbine and duct burner using calibrated fuel flow meters, with heat input 

calculated based on weighted average monthly heating values provided by the pipeline natural 

gas supplier, and emissions of CO2e calculated based on emission factors and GWPs from 40 

CFR 98 (greenhouse gas monitoring rule). Gross output (kW) will be continuously measured and 

recorded at the combustion turbine generator. 
Page | 28                                                                                                                                          August 3, 2015

Victoria Power – GHG Basis of 940 lb CO2/MWh (gross) on a 12 m.r.a. 

Pursuant to the provisions of this permit, Victoria WLE, L.P. (Victoria) will carry out a major 

modification at the existing Victoria Power Station (VPS) located in Victoria, Victoria County,

Texas. The existing VPS is a natural gas-fired combined cycle base load power generating 

station that currently operates in a 1 by I by 1 (1 x 1 x 1) configuration (one combustion turbine, 

one HRSG and one steam turlbine) with a gas turbine (M50 lf), heat recovery steam generator 

(HRSG) equipped with duc1t burners and a steam generator (General Electric 05). The project 

would add a new gas turbine (GE.7FA.04 or equivalent) and HRSG equipped with duct burners. 

After these additions, the facility will be able to operate in a natural gas-fired combined cycle 

generating unit in a 2 by 2 by l (2 x 2 x 1) configuration (two combustion turbines, two HRSG 

and one steam turbine) that utilizes the existing non-modified M501 F combustion turbine and 

HRSG and the existing non-modified steam turbine. The VPS plant is authorized to operate in a 

1 x 1 x 1 combined cycle configuration with the new gas turbine and new HRSG, and it retains 

ab11 ity to operate in Tts orTglnal 1 x 1 x 1 combined cycle configuration-without an assigned 

GHG BACT limit. VPS operations covered by the permit will consist of the following sources of 

GHG emissions: 

 Natural Gas-Fired Combined Cycle Combustion Turbine (GE.7F A.04 or equivalent). 

The combustion turbine is equipped with a heat recovery steam generator (BRSG) and 

duct burners, dry low NOx (DLN) combustion system, and selective catalytic reduction 

(SCR), and oxidation catalyst; 

 Process Fugitives; and, 

 Electrical equipment insulated with sulfur hexafluoride (SFG). 

Pinecrest Energy Center – GHG basis of 909.2-942.0 lb CO2/MWh 

 

PCEC proposes as BACT for this project, the following energy efficiency processes, practices, 

and designs for the proposed combined cycle combustion turbines: 

 Use of Combined Cycle Power Generation Technology 

 Combustion Turbine Energy Efficiency Processes, Practices, and Designs 

o Efficient turbine design 

o Turbine inlet air cooling 

o Periodic turbine burner tuning 

o Reduction in heat loss 

o Instrumentation and controls 

 HRSG Energy Efficiency Processes, Practices, and Designs 

o Efficient heat exchanger design 

o Insulation of HRSG 

o Minimizing Fouling of heat exchange surfaces 

o Minimizing vented steam and repair of steam leaks 

 Steam Turbine Energy Efficiency Processes, Practices, and Designs 

o Use of Reheat Cycles 
Page | 29                                                                                                                                          August 3, 2015

o Use of Exhaust Steam Condenser 

o Efficient Blading Design 

o Efficient Generator Design 

 Plant-wide Energy Efficiency Processes, Practices, and Designs 

o Fuel gas preheating 

o Drain operation 

o Multiple combustion turbine/HRSG trains 

o Boiler feed pump fluid drive design 

To determine the appropriate heat-input efficiency limit, PCEC started with the turbine’s design 

base load net heat rate for combined cycle operation and then calculated a compliance margin 

based upon reasonable degradation factors that may foreseeably reduce efficiency under realworld conditions. The design base load net heat rate for the combustion turbines being 

considered for this project are as follows: the General Electric 7FA design base load net heat rate 

is 6674 Btu/kWhr (HHV) without duct burner firing and 7051 Btu/kWhr (HHV) with duct burner 

firing; the Siemens SGT6-5000F(4) design base load net heat rate is 6782 Btu/kWhr 

(HHV) without duct burner firing and 7045 Btu/kWhr (HHV) with duct burner firing; and the 

Siemens SGT6-5000F(5) design base load net heat rate is 6845 Btu/kWhr (HHV) without duct 

burner firing and 7050 Btu/kWhr (HHV) with duct burner firing. Note that these rates reflect the 

facility’s “net” power production, meaning the denominator is the amount of power provided to 

the grid; it does not reflect the total amount of energy produced by the plant, which also includes 

auxiliary load consumed by operation of the plant. To be consistent with other recent GHG 

BACT determinations, the net heat rate without duct firing is used to calculate the heat-input 

efficiency limit. 

To determine an appropriate heat rate limit for the permit, the following compliance margins are 

added to the base heat rate limit: 

 A 3.3% design margin reflecting the possibility that the constructed facility will not be 

able to achieve the design heat rate. 

 A 6% performance margin reflecting efficiency losses due to equipment degradation 

prior to maintenance overhauls. 

 A 3% degradation margin reflecting the variability in operation of auxiliary plant 

equipment due to use over time. 

Design and construction of a combined-cycle power plant involves many assumptions about 

anticipated performance of the many elements of the plant, which are often imprecise or not 

reflective of conditions once installed at the site. As a consequence, the facility also calculates an 

“Installed Base Heat Rate”, which represents a design margin of 3.3% to address such items as 

equipment underperformance and short-term degradation. 

To establish an enforceable BACT condition that can be achieved over the life of the facility, the 

permit limit must also account for anticipated degradation of the equipment over time between 

regular maintenance cycles. The manufacturer’s degradation curves project anticipated 

degradation rate of 5% within the first 48,000 hours of the gas turbine’s useful life; they do not 

reflect any potential increase in this rate which might be expected after the first major overhaul 

and/or as the equipment approaches the end of its useful life. Further, the projected 5% 

degradation rate represents the average, and not the maximum or guaranteed, rate of degradation 
Page | 30                                                                                                                                          August 3, 2015

for the gas turbines. Therefore, PCEC proposes that, for purposes of deriving an enforceable 

BACT limitation on the proposed facility’s heat rate, gas turbine degradation may reasonably be 

estimated at 6% of the facility’s heat rate. 

Finally, in addition to the heat rate degradation from normal wear and tear on the combustion 

turbines, PCEC is also providing a reasonable compliance margin based on potential degradation 

in other elements of the combined cycle plant that would cause the overall plant heat rate to rise 

(i.e., cause efficiency to fall). Degradation in the performance of the heat recovery steam 

generator, steam turbine, heat transfer, cooling tower, and ancillary equipment such as pumps 

and motors is also expected to occur over the course of a major maintenance cycle. 

As a result of these adjustments, PCEC is proposing the following output based CO2/MWh 

BACT limits for the Project, on a 12 month rolling average, excluding startup hours: 

Turbine Model Gross Heat Rate With Duct 

Firing (Btu/kWh) (HHV) 

Output Based Emission Limit 

With Duct Firing (lb 

CO2/MWh) gross 

General Electric 7FA.05 7925.0 942.0 

Siemens SGT6-5000F(4) 7649.0 909.2 

Siemens SGT6-5000F(5) 7679.0 912.7 

While energy efficiency will be a consideration for final selection of a turbine, other 

considerations will include the capacity of the turbine, cost, reliability, and bpredicted longevity 

of the turbines. 

While starting up the combustion turbines following ignition, a large portion of the energy input 

to the combustion turbine is used for heating the turbine casings and rotors, boiler tubes, main 

steam piping, and other portions of the thermal system rather than the production of electricity. 

During this startup period, the steam turbine does not generate electricity in a combined cycle 

mode until the thermal equipment is at an appropriate operating temperature and sufficient steam 

is produced in the heat recovery steam generator. Therefore, PCEC proposes that the 12 month 

rolling average output based BACT limits exclude startup hours. For purposes of compliance 

with the emission limits for non-GHG pollutants, the startup period is defined as the period of 

time when there is measurable fuel flow to the combustion turbine and ends when the 

combustion turbine load reaches 60 percent. However, for purposes of an output based GHG 

emission limit, the plant startup period will be defined as the period of time when there is 

measurable fuel flow to the combustion turbine and ends when the steam turbine is synchronized 

to the electrical grid. 

Pacificorp Energy Lakeside 2 Project – GHG Basis of 950 lb/MWh(g) on a 12 m.r.a. 

Total CO2e emissions from Lake Side block 2 shall not exceed 950 lb/MWh(g) on a 12-month 

rolling average basis. Hourly heat input for each turbine and the HSRG will be obtained from the 

data submitted to the Acid Rain database and summed over the appropriate 12-month period. 

This total heat input will then be multiplied by an emission factor of 121.723 lb CO2e/MMBtu to 
Page | 31                                                                                                                                          August 3, 2015

obtain the total CO2e emissions during the 12-month period. The 12-month gross generation for 

each turbine and HSRG will be obtained from the data reported to the Acid Rain database. This 

hourly generation will be summed over the twelve-month period to obtain the total gross 

generation. The CO2e per MWH(g) value is calculated by dividing the 12-month total CO2e 

emissions by the 12-month total gross generation. 

Berks Hollow – GHG Basis of 1,000 lb CO2/MWh on a 365 d.r.a. 

CCS has not been demonstrated on a facility of this size, therefore it has been determined that it 

is infeasible. Energy efficiency utilization will include: combine cycle technology (significantly 

higher levels of electric generation efficiency than traditional fossil fuel generating facilities); 

equipment maintenance; instrumentation & control systems; HRSG design consideration; and 

high efficiency auxiliary equipment. Energy efficiency is the only technical feasible option 

remaining. The BACT determination is use of energy efficiency with an emission limitation of 

1,000 lb C02/MW-hr (gross) on a 365-day rolling average which is based on proposed NSPS. 

Please see the attached comment and response document for a detailed discussion of the 

selection of this limit. 

Hickory Run – GHG Basis of 1,000 lb CO2/MWh on a 365 d.r.a. 

CCS has not been demonstrated on a facility of this size, therefore it has been determined that it 

is infeasible. Energy efficiency utilization will include: combine cycle technology (significantly 

higher levels of electric generation efficiency than traditional fossil fuel generating facilities); 

equipment maintenance; instrumentation & control systems; HRSG design consideration; and 

high efficiency auxiliary equipment. Energy efficiency is the only technical feasible option 

remaining. The energy efficiency for the various units are provided in Appendix A of the 

application and are as follows: 

 GE 7FA: net plant heat rate of 6,700 btu/kWh, HHV @ ISO conditions at 59F ambient 

temperature with no duct firing 

 Siemens F: net plant heat rate of 6,842 btu/kWh, HHV @ ISO conditions at 59F ambient 

temperature with no duct firing 

 Mitsubishi G: net plant heat rate of 6,702 btu/kWh, HHV @ ISO conditions at 59F 

ambient temperature with no duct firing 

 Siemens H: net plant heat rate of 6,577 btu/kWh, HHV @ ISO conditions at 59F ambient 

temperature with no duct firing 

The BACT determination is use of energy efficiency with an emission limitation of 1,000 # 

CO2/MW-hr (gross) on a 365-day rolling average which is based on proposed NSPS. 
Page | 32                                                                                                                                          August 3, 2015

Black Hills Power, Cheyenne Prairie – 1,100/1,600 lb CO2/MWh annual average basis 

The only feasible option is the “Electrical Generation Efficiency” option, which, therefore, is selected as 

BACT. This option determined to consist of the CGS project as proposed with new state-of-the-art 

combustion turbines. Consistent with the review criteria presented above, the CGS project evaluated 

combustion turbine exhibits comparable efficiency with most of the evaluated alternative combustion 

turbines, and superior efficiency over the Pratt & Whitney and Siemens machines. Therefore, Black Hills 

proposes that CGS GHG BACT consist of installation of combustion turbines from any manufacturer 

with a rating of nominal 40 MW. However, the annual CO2 emissions limit for the five new combustion 

turbines will be based upon the BACT emission limits proposed below, which are based upon a 

combustion turbine from the top of the efficiency range shown. The proposed permit limit of annual total 

tons of CO2e and lb/MWh would remain fixed regardless of the combustion turbine selected. 

The estimated total annual CO2e emissions from the combustion turbines are 936,588 tpy, and this value 

is proposed to be the annual CO2e permit limit for the five combustion turbines. 

EPA’s PSD permitting guidance for GHGs suggests use of output-based BACT emission limits and 

longer-term averaging periods for GHGs. Based on Black Hills’ analysis of conservative scenarios for 

number of turbine startups and shutdowns, partial load operation, and ambient temperature during 

operations, and considering the range of normalized GHG emissions noted above and eventual turbine 

degradation, proposed BACT permit limits are 1,100 lb/MWh for each combined-cycle combustion 

turbine and 1,600 lb/MWh for each simple-cycle combustion turbine on an annual average basis. If the 

averaging time is less than 1 year, these permit limits should be increased accordingly. 

FROM PREAMBLE-WILL REMOVE 

In total 31 major permits were identified with 39 discrete limits on GHG emissions. Eight 

of the limits were expressed as lbs/h or tons per year and were not included in the analysis. In 

addition, one CHP unit that generates electricity and supplies steam to a chemical plant was in 

the set with a limit of 1,362 lb CO2/MWh based only on the gross electrical portion of output and 

does not account for the useful thermal output. Therefore, it was also not included in this 

analysis. Two of the permits did not clearly specify if the output based standard was on a gross 

or net basis and were therefore also excluded. 

The remaining 28 permit standards were expressed on a lb CO2/MWh or a heat rate basis 

that could be converted to a lb CO2/MWh basis. Eight permit limits were based on net output 

ranging from 774-936 lb CO2/MWh-n. The lowest emission limit was for a hybrid power plant 

with a solar component of heat input that could contribute up to 50 MW. Twenty permit limits 

were based on gross output ranging from 833-1,100 lb CO2/MWh-g. Of these 28 permit limits, 

only one unit had a heat input capacity less than 1,500 MMBtu/h (366 MMBtu/h); this unit also 

had the highest emission limit of 1,100 lb CO2/MWh. 

Each of the permit limits discussed above that is 1,000 lb CO2/MWh or include all 

periods of operation (i.e., including startup, shutdown and malfunction). In addition, all permit 

limits were set considering the backup and additional fuel use. Specifically, some permits 

restricted fuel use to only natural gas, while others limited the available usage (duration and 

type) of backup and other fuels. For example, the Pioneer Valley Energy Center has unrestricted 

use of natural gas while restricting operation with ultra-low sulfur diesel (ULSD) to 1,440 hours 

per 12-month period. This permit allows up to 16 percent use of a fuel other than natural gas and 
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the facility accepted a permit limit of 895 lb CO2/MWh-net. Each permit limit also considered 

the mode of operation for the combustion turbine. In some cases the permit limit was determined 

to be appropriate because the combustion turbine is intended to operate with frequently changing 

loads rather than operating at relatively steady loads, and this mode of operation would make it 

difficult to meet lower limits. In the instances for most of the units with the lower emission 

limits, their permits specified that the combustion turbines will be operating at base load, so they 

will be able to operate closer to their most efficient load levels. For example, the Lower 

Colorado River Authority's Ferguson plant evaluated emission limits for the plant at 50, 75 and 

100 percent gross load, since the expected operation is 50 percent gross load, the plant accepted 

an emission limit of 918 lb CO2/MWh-n for the corresponding evaluation. For the combined 

cycle combustion turbine units with duct burners on their HRSG, the hours of operation with 

duct burners was included in the determination of the permit limits. Typically, the hours of 

operation and heat input were limited to ensure that the units are operated in the most efficient 

way and reduce their CO2 emissions. Finally, most off these permits included an allowance for 

efficiency losses due to degradation The sum of these allowances was in the range of 10 to 13 

percent reduction in the design efficiency.