Technical Support Document (TSD) for

New Source Performance Standard s 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, 2015Page | 2 August 3, 2015 Summary

To establish an appropr iate carbon dioxide (CO 2 ) 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 CO 2 and greenhouse gas (GHG) emissions limits included in recently issued pr e-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 Technol ogy (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 (NG CC) stationary combustion turbines.

In summary, the EPA reviewed recent BACT pe rmit limits for GHG emissions to evaluate the structure of these limitations (e.g., as mass emissi on rates or heat rate lim itations), the averaging periods, treatment of start ups and shutdowns, and associated testing and monitoring requirements. We found a number of variations in the way permitti ng authorities had structured these BACT limits. Some of the BACT permit c onditions had separate numeric limits that applied during startups and shutdowns with a ssociated limitations on the total duration of startups and shutdowns. The mo st 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 perf ormance tests at greater than 90 percent of maximum output with associated numeric limits th at were significantly more stringent than the
final NSPS.

Additionally, while the EPA did review recently is sued permits when evaluating the level of the standard, the EPA also reviewed actual performa nce data to determine the degree of limitation that is actually being achieved after the comm encement of operations (as required by section 111(a)(1)). The docket includes information on the actual emission rates th at are being achieved by combustion turbines with cap acity 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); thes e units began operations from 1977 through 2003 and three of these units are combined heat and power facil ities that would be eligible to include useful thermal output in th eir 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 conclusi on that available operating data and recently issued permits indicate the final standard is ac hievable 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, rang ed from 802 to 965 lbs of CO2 per net MWh. While the average emission rates across multiple aff ected 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.Page | 3 August 3, 2015 Introduction

We found 36 permits issued since 2011 fo r construction of new NGCC power blocks 1 . We reviewed these permits to identify the form of the limit(s) for GHGs; the case-by-case factors considered in the BACT analysis; treatmen t of startups, shutdowns, and malfunctions, allowances for performance degradation over th e life of the facilit y, 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 emissi ons 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 Bri tish thermal units per hour (MMBtu/h);

o Manufacturer’s design specifi cations 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 us e 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 ope rating characteristics.

o Achievable mass emission rates (e.g., tons CO 2 per year);

o Achievable efficiency standards (e.g., maximum heat rate limit in MMBtu/kWh);

The projects reviewed typically included one or more combusti on turbines with heat recover steam generators (HRSGs) and duct burner system s, 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 oxi dation catalyst for controlling CO emissions at part load. Typically, emissi ons from the NGCC are measured from the HRSG stack, but some permits allow operation of the co mbustion turbine in simple cycle mode with emissions from a second stack that precedes the HRSG. Total electr ical output is the sum of the output from the combustion turbine-generator(s) plus the outpu t from the steam turbine-generator. Gross electrical generation accounts for al l electricity generated by the uni t. Net electric generation is the gross electrical generation less the electricit y used to supply the pl ants auxiliary loads.

BACT Analysis

In order to comply with the New Source Revi ew pre-construction permitting programs (NSR), applicants used the five-step analysis prescrib ed by the EPA for determining the best available control technology under sect ion 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.Page | 4 August 3, 2015 1. Identify all control technologies;

2. Eliminate technically infeasible options;

3. Rank remaining control technolog ies by control effectiveness;

4. Evaluate most effective controls;
5. Select BACT.

The control technologies identified for th e 31 NGCC projects with GHG emissions limits included carbon capture and storag e (CCS) technology, use of rene wable resources with hybrid power designs, and inherently lower emitting pr ocesses 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-combusti on 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 em issions unit or across the entire facility. The available control technologies and energy e fficiency 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 monito r 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 genera ted from the recovered waste heat.

 Heat exchanger design -design to optimize waste heat transfer between the
combustion turbine exhaust and redu ce 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 rene wable 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 facili ties incorporated the us e 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 sola r-thermal plant to be part of their BACT. In addition, each facility ruled out CCS tec hnology as BSER because the technology was technically infeasible or economically inf easible and had other negative energy and environmental impacts.Page | 5 August 3, 2015 Facility Permits

Most permit applicants had already selected th e manufacturers for thei r projects, but several applications included parallel analyses with multiple manufactures’ emissions and performance data to allow subsequent select ion. 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 combus tion in NGCC units, the majority of emissions

are CO 2 and many permits used CO 2 as a surrogate for calculating emission rates of the other
two GHGs or assumed that CO 2 was equivalent to CO 2 e. For example, one permit said that since
the emissions from their unit ar e calculated to be 99.9 percen t CO2, the remaining pollutants (CH 4 and N 2 O) are not represented, but still listed the emission limit as CO 2 e.
The emission limits in the permits were expresse d as output-based limits (mass of CO2 per MWh of electrical output) or as a trad itional hourly emission rate mass of CO2 per hour. The efficiency limits were typically expressed as heat rate li mits (British thermal un its 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 CO 2 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 lim its in the form lbs CO2/hr and were excluded from further analyses. One facility was for a co mbined 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 pl ant was also excluded fr om 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. On e 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 spec ific 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 follo wing 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 perm it 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 f acility and the SC6-8000H at anot her 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.Page | 6 August 3, 2015 Natural gas is permitted as the primary fuel at all facilities. Only three permits allowed the use of a fuel other than natural gas; ul tra-low sulfur diesel fuel and biodiesels were permitted as backup fuels with strict limits on annual usage.

Twenty-one of the twenty-five permits allowe d installation of duct bur ners. Every duct burner was limited to only firing natural gas. Some perm its 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 operati on 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 CO 2 /MWh, as shown in Figure 1 . Fifteen permits specified CO2 mass limits per gross MWh, while eight specified mass lim its per net MWh. The highest numerical limit provided on a net basis was 936 lb CO 2 /MWh-net. This value is about 100 lb/MWh-net more stringent than the N SPS of 1,030 lb/MWh-net. The auxiliary load requirements for NGCC units are ty pically about a three percent of gross output. There was only one permit issued on a gross basis that had a nume rical values larger than the final NSPS. This value of 1,100 lb/MWh-gross was for a small uni t forecasted to operate with a 50 percent capacity factor. As discussed late r in this document, early operati ng 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 thes e permits were similar to those required in the final NSPS. The majority of facilities required CO 2 to be continuously monitored via CO 2 CEMS. Two permits included monitoring conditions based on Part 75 heat input monitoring in conjunction with an emission factor from 40 CF R 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 1,200Page | 7 August 3, 2015 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 s hutdowns are limited to 500 hours per year. Many permits included specific limits for startup and shutdowns. These lim its 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 docume ntation, typically a GHG statement of basis (SOB), detailing how the limits were calculated. The determinations included
detailed calculations with manuf acturers design and guaranteed turb ine operating values and fuel
data to calculate achievable limits over th e lifetime of the NGCC unit with manufacturerprovided maintenance and replacements. In arrivi ng at these limits, the permittees accounted for expected periods of startup and shutdown, varyin g loads and cycling due to frequently changing demand and energy from renewabl e 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 a nd degradation margins were mo stly 10 to 13 percent. These percentages typically included a 3 percent design margin refl ecting 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 de gradation prior to maintenance overhauls, and a 3 percent degradation margin reflecting the variab ility in operation of auxiliary plant equipment
due to use over time.

Some permits based their limits on the design ef ficiency 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 ov er time. The total variance from the design conditions for these units ranged from 14 to 17 pe rcent. See the Plant GHG Basis section of this document for more detailed permit and SOB discussi on of the factors evalua ted 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 MW h 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 tota l of 54 hours with an
actual emission rate of 983 lbs of CO2/MWh. It is important to note that th e capacity factor[2] of this unit during this operating period would have classified this unit as a non-base lo ad 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 thes e operating data as requi red by section 111(a)(1).Page | 8 August 3, 2015 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 CO 2 emission limit for each of the 25 facilitie s with output-based emission limits is excerpted below.

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

The PHPP is designed to use solar technology to generate a porti on of the Project’s output. The facility will be operated in combin ed-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 st eam 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 cont rol technologies for GHG emissions from natural gas-fired combustion turbines, BACT for this so urce is the use of new thermally efficient CTs
and emission limits of 774 lb CO2/MWh for so urce-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 fact or 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 st artup duration limits also constitute BACT for GHG emissions, because the shorter startup time in creases the overall therma l efficiency of the facility. Therefore, BACT for the PHPP’s GHG emissions during startup is 110 minutes for a cold startup and 80 minute s 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 tu rbine 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 th e Clean Air Act for PSD permitt ing purposes is a group of six gases: carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perflu orocarbons, 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 regulat ory 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 becau se nitrous oxide and methane are emitted from CTs in minor amounts and the majority of the GHG emissions actually are CO2. For example, EPA’sPage | 9 August 3, 2015 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 acco unting for the global warming potential of methane and nitrous oxide , the CO2 emission fact or accounts for 99.7% of the emission on a CO2e basis. Further, an emi ssion 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 sour ce, 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)-Emissi on limit for CO2e at 833 lb/MWh-gross

The Project is designed for baseload electric ity generation and will utilize state-of-the-art combustion turbine technology in combined cycl e mode. The Project is proposing to use combustion turbines which utilize highly effi cient combustion technol ogy. In addition, the combustion turbines will combust natural gas as th eir only fuel source, since this effectively minimizes the production of CO2 from combustion re lative to other fuels. The proposed project has a “Design Base Heat Rate” of approximate ly 6,687 British thermal units per kilowatt-hour (Btu/kW-hr), HHV at ISO conditions (59°F, 71 pe rcent relative humidity) with no duct firing. Other permits incorporating GHG requirements we re reviewed with GHG emissions limits based upon engine efficiency expre ssed as heat rate and range d 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 CO 2/MW-hr. These limits ranged from 887 lb CO2/MW-hr gross to 918 lb CO2/MW-hr net, wh ile combusting natural gas. Based on their analysis, Bay Area Air Manage ment District (BAAMD) conc luded 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 m ode proposed for the Project have a design base heat rate of approximately 6,687 Btu/kW-h r 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 ach ieved through utilization of high efficiency, stateof-the-art, combustion turbine t echnology and combusting only commercially available, pipeline quality natural gas in the turbines.

One commenter stated that the EPA had inappr opriately 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 dir ects the commenters attention to page 84 of 86 under permit condition (gg)(2)(d) which states,Page | 10 August 3, 2015 “[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. Alt hough this generally cons ists of operating the emissions unit at its maximum material input/produc tion 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 scenari o. Failure to test unde r these conditions is justification for not accepti ng 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 em ission 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 comb ined 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 pe r year with a duration of 83 minutes each, and hourly CO emissions at ISO conditions duri ng steady state operation of 11.90lbs/hr based on
manufacturer’s data and stea dy state operating hours was dete rmined by the following equation. (Included here (p. 68 of the PDF) was an equa tion). 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 megawa tt hour (gross output) as BACT for the proposed project. These limits repr esent the lowest heat input rate that can reasonably be assured under all operating scenario s for these turbines. This level of emissions would be achieved through util ization of high efficiency, stat e-of-the-art, combustion turbine technology and combusting only comme rcially 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 fo r 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 factor s that may foreseeably reduce efficiency under real-world conditions. The design base load gros s heat rates for the combustion turbines being considered for this project are as follows:

 AlstomPage | 11 August 3, 2015 o 7,625 Btu/kWhr (HHV) wit hout duct burner firing

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

These rates reflect the facil ity’s “gross” power production, meaning the amount of power provided to the grid. It does not reflect the total amount of en ergy produced by the plant, which also includes auxiliary load cons umed 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 c onstructed facility will not
be able to achieve the design heat rate.

 A 6% performance margin re flecting 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 th e site. Typically, the market for contracting the engineering a nd construction of combined cycle power plants has a design margin of 5% for the guaranteed net MW output and net heat rate. Th is is the condition for
which the contractor has a "make right" obligation to continue t uning the facility's performance to achieve this minimum value. Therefore, the contra ctor must deliver a facili ty 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 confiden ce surrounding the expert ise and experience of combined cycle power plant construction, FGE has elected to reduce the 5% design margin to
3.3%.

Performance Margin on Combustion Turbin e 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 Us ers 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 recove red, resulting in a 20-year degradation of 4.5%. According to the combustion turbine vendor (Als tom Power), typically, performance degradation during the first 36,000 hours (the normally r ecommended interval for inspection and maintenance) is 2.01% (heat rate degradation) to 2.64% (power out put degradation). Alstom also indicated that, depending on the equivalent ope rating 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 degradati on of approximately 2.32 %. Considering the atmospheric conditions at the project location (e.g., high ambi ent temperature, humidity, and ~2,200 foot elevation, etc.); FGE ha s 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% stat ed in the CEC publication) and, assuming a 44% performance recovery, FGE calculate d a 20-year degradation of 6%.Page | 12 August 3, 2015 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 ti me as well as minor potential fou ling of the hea ting surface of the tubes. Similar to the HRSGs, scaling and co rrosion 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 op erating data has been gathered and published that illustrate a clear performance degradation characterist ic 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 operati on a year). The BACT limit will apply to the turbines during all operational c onditions, with and w ithout duct burner firi ng. 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% lo ad, corrected to ISO conditions.

FGE requested the BACT limit to be expre ssed 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 BA CT limits established for other combined cycle/heat recovery steam genera ting 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 En ergy Center, Pioneer Valley Energy Center, and PacifiCorp Energy Lake Side Powe r Plant. The differences in BA CT 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 Calp ine facilities ( 920 lb CO2e/MWh).

St. Joseph Energy Center-Emission Limit fo r 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 he at rate is consistent with the GHG BACT analyses performed for the Russe ll 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 D over, New York. For a backup fuel, Diesel fuelPage | 13 August 3, 2015 was used because it is an indepe ndent 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 applica tion is fundamental to meeting power and water requirements in an emer gency 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 CO 2e/MWh-grid. To determine the emission limit which must be demonstrated during PVEC’s init ial stack test, accuracy in measuring CO2 and
the correction curves used to convert stack test s 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 fo r installation cannot feasibly be used for continuous operations due to a number of factors su ch as partial load, startups, shutdowns, and
weather conditions which all affect the turbine’s e fficiency. To ensure PVEC operates its facility to minimize greenhouse gases, EPA is propos ing to establish an ongoing CO2e emission limit/MWh to the electric grid. Due to the factor s previously listed affecting efficiency, the emission limit shall be determined by averagin g 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 w ith 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 appl ication supplement, PVEC clai med a performance margin of 6%. EPA understands the performance margin addr esses factors affecting the efficiency which cannot be controlled by PVEC such as ambient te mperature. 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 PV EC provided and on EPA’s own research regarding unavoidable de creases in efficiency and variabil ity of performance under a reasonable range of conditions, EPA has determined that BA CT 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 Li mit for CO2e of 903 lb/MWh-gross

The permit for Green Energy Partners had no sp ecial 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 Bt u (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 degradationPage | 14 August 3, 2015  A 1.2% degradation margin reflecting ope rational variation a nd auxiliary power degradation. The operational variation assumes differen ces in operating techniques including but not limited to CT operation, degr adation 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 kW h 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 demons trated 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/MMBt u. The GHG emission limit includes startups, shutdowns, and low load operations. To establis h 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 a nd 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 natu ral gas and procurement, installation and operation of a high efficiency, low heat rate co mbined 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 ma rgin, 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 pr ior 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 fo r CO2 of 934.5, 913, and 909.2 lb/MWh-gross

LPEC requested the BACT limit to be expr essed 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 gene rating units, the proposed limits fo r LPEC are comparable to the limits established for LCRA, Calpine Deer Park, Calpine Channel Energy Center, Pioneer Valley Energy Center, and PacifiCorp Energy Lake Si de Power Plant. The differences in BACT
between La Paloma and LCRA a nd 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 loadPage | 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 tu rbines rated between 183 and 232 MW each and the steam from the HRSGs driving a third electric generator with an electri city output capacity of 271 MW. As energy efficiency measures, LA Pa loma is using Fuel Gas Preheating, drain operation, multiple combustion turbine/HRSG trai ns, and Boiler feed pump variable speed drives. To determine the appropriate heat-input ef ficiency limit, LPEC st arted with the turbine’s design base load net heat rate for combined cycle operation and then calculated a compliance margin based upon reasonable degradation factor s 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) wit hout duct burner firing

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

 Siemens SGT6-5000F(4)

o 6782 Btu/kWhr (HHV) wit hout duct burner firing

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

 Siemens SGT6-5000F(5)

o 6891 Btu/kWhr (HHV) wit hout duct burner firing

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

These rates reflect the facility’s “net” pow er production, meaning the amount of power provided to the grid; it does not reflect the to tal amount of energy produced by the plant, which also includes auxiliary load cons umed by operation of the plant. To be consistent with other recent GHG BACT determinations, the net heat rate without duct burne r 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 cons tructed facility will not be able to achieve the design heat rate.

 A 6% performance margin re flecting 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-cyc le 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 H eat Rate,” which represents a de sign 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 ex pected after the first major overhaul and/or as the equipment approach es the end of its usef ul life. Further, the projected 5% degradation rate re presents the average, and not the maximum or guaranteed, rate of degradation for the gas turbin es. Therefore, LPEC proposes that, for purposes of deriving an enforceable BACT limitation on the proposed facil ity’s heat rate, gas turbine degradation may reasonably be estimated at 6% of the facility’s he at rate. This degradation rate is comparable to the rates estimated by other natural gas fired pow er plants that have received a GHG PSD permit.

Finally, in addition to the heat rate degr adation 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 cy cle plant that would cause the overall plant heat rate to rise (i.e., cause efficien cy to fall). Degradation in the pe rformance 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) Fe rguson-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 identif ied a GHG BACT analysis that was completed for the Russell City Energy Center and the Palmda le Hybrid Power Project. The Russell City Energy Center project included two SiemensW estinghouse 501 FD3 combustion turbines and a GHG BACT permit condition was established whic h set the heat rate limit to 7,730 Btu/kWh. The Palmdale project consists of two General El ectric 7FA natural gas-fired CTGs rated at 154 MW each, one steam turbine generator rated at 2 67 MW and 251 acres of parabolic solar-thermal collectors with associated heat-transfer equi pment. 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 equi pment 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 re sulting from the anticipated reduction in startup time. CCS was ruled out due to cost and inadequate dem onstration. It was determined that the most efficient method to ge nerate electricity from a natural gas fuel source is the use of a combined-cycle design. The major components inco rporated into a combined-cycle unit are a combustion turbine, a heat rec overy generator (HRSG) and a st eam turbine. Specific energy efficiency processes, practices and designs ar e included in the permit application for each component of the co mbined cycle unit.

The GHG BACT limit is calculated from emi ssion factors and the annual average heat rate (HHV), 7,720 Btu/kWh, and includes a 5 percen t degradation factor and seasonal variation. From the calculations, with the emission units runn ing 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 pe rcent and 100 percent gross load scenarios. At 50 percent gross loa d, the facility efficiency is ca lculated to be approximately 44 percent. The permit application i ndicates 50 percent efficiency and for this efficiency the grossPage | 17 August 3, 2015 load is 100 percent. The calculation method pr oposed 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 season al variation averages). With LCRA's proposed BACT calculation method, relying only on the quanti ty 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 m easure the actual heat input in MMBtu per hour and measure the pounds of C02 on an hourly basis w ith a C02 emissions monitor. This analysis can be completed utilizing the updated Fe fact or, 40 CFR Part 75, Appendices F and G, and a conversion methodology similar to the equati ons 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 in stall an FD2-series combustion turbine with plans to modify it within an eighteen (18) mont h period to the FD3-series combustion turbine.
Since CCS was eliminated as BACT for CTG 5, then BACT for the new combined-cycle combustion turbine is the high efficiency proc esses, practices and de signs 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 configuratio n as the FD3 configuration when in continuous operation, since the FD2-series and FD3-series co mbustion turbines have the same efficiency. However, the FD3 configuration provides grea ter output at high ambien t temperatures during base load periods. Therefore, for the FD3, th e potential annual electric generation (MWh) and fuel usage, as well as corresponding GHG emi ssions, 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-opera ting-hour degradation curve provided by the manufacturer, Siemens, reflects anticipated recove rable and non-recoverabl e degradation in heat rate between major maintenance ove rhauls of approximately five pe rcent (5%). The results of the degradation curves differentia te 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 repla cement. The turbine components most affected by the combustion process include combustion liners, fuel nozzle assemblies, transition pieces, turbine nozzles, stationary shr ouds, and turbine buckets. These components are often referred to as “hot gas path” components. “Recoverable” degrad ation is mostly attribut able to turbine blade fouling due to impurities in intake air and fuel. Th is type of degradation can be mitigated through inspection programs, on-line turbine water wa shes, instrument calibration, and other maintenance activities. “Non-recoverable” degrada tion is mainly attributed to blade surface roughness, erosion and blade tip rubs and cannot be restored upon a maintenance overhaul. The manufacturer’s degradation result s 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 th e first major overhaul and/or as the equipment approaches the end of its useful life. Further, the projected 5% degradat ion rate represents thePage | 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 reasonab ly be estimated at six percent (6%) of the facility’s heat rate.

A compliance margin based on potential degrada tion in other elements of the combinedcycle plant that would cause the overa ll plant heat rate to rise (i.e., cause efficiency to fall) of 3% degradation rate to account for these factors. Th e other elements of the combined-cycle plant degradation in turbine exhaust flow, degradation in performan ce of steam turbine and other equipment

To determine an appropriate h eat rate limit for continuous op erations, the baseline annual average heat rate (HHV) of 6,852 Btu/kWh is us ed with the 3.3% design margin taken into account followed by a six percent (6%) performance margin reflecti ng efficiency losses due to equipment degradation prior to maintenance overhauls, and then a three percent (3%) degradation margin reflecting the variability in op eration in auxiliary plant equipment due to use over time, resulting in the annual average he at rate (HHV) of 7,728 Btu/kWh (See Appendix, Table 4). Additionally, to determine the heat i nput limit for this facility, the heat rate is calculated assuming that all steam generated in th e heat recovery steam generator is used to generate electricity in the ex isting on-site steam tu rbine even though there are periods when some or all of the generated steam is sold to a ne ighboring 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 engine s on a 30-day rolling average and an annual GHG BACT limit of 1,045,635 tons CO2e per year fo r 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 seri es will be upgraded to the FD 3 series within a statutory
timeframe of 18 months under the conditions of this permit. In establishing an enforceable
BACT limit over the lifetim e of the turbine, Calpine accounted for the anticipated degradation of the equipment over time between regular maintena nce 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 di fferences in size, manufacturer, configuration, cooling practice, elevation, and the method used to determine the heat rate among the permitted power plants across the country, so me variability in BACT determ inations 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 degrad ation 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 em ission rate at simila r 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 issu ed 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% degrad ation 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 WE C 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 th e constructed facility will not be able to achieve the design he at rate, a 6% performance margin reflecting efficiency losses due to equipment degradation prior to maintenan ce overhauls, and a 3% degradation margin reflecting the variability in opera tion of auxiliary plant equipment due to use over time. This heat rate is equivalent to a net pl ant efficiency of 56.2% Lower Hea ting 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 Cent er proposes as BACT net heat rate for the Project of 7,605 Btu/kWh (HHV), corrected to ISO conditions wi th ambient dry bulb temperature of 59oF, ambient relative humidity of 60%, barometric pre ssure 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 turb ines 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 fi ring rate (2,234 MMBtu/hr at -5 degrees F) and the quantity per year throughput represents the tu rbine 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 mini mize GHG operates the combustion turbines in combined cycle mode with natural gas as the prim ary fuel and proposes a he at 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 co mbined cycle units will be limited to 2,183,223 tons/year (or 1,091,611.5 tons/year/unit). Th is 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 limi t 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 operati ng at relatively steady lo ads, 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 requi red to run at steady-stat e at the higher power output, which also increases GHG em issions over the steady-state em ission rate. In addition, the GHG emission limit proposed by the applicant acc ounts for the use of ULSD, which has higher GHG emissions, up to 720 hours per year in each tu rbine. This limit is for all times including startup, shutdown and malfunction. Th e BACT determination is based on thermal efficiency and clean fuels, although carbon capture and stor age 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 th e Pacific Northwest, due to th e variability of renewable and hydro-generation output, the combined-cycle powe r plant at the Troutdale Energy Center could also be load following. The combined-cycle plan t 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 en ergy. The combined-cycle plant will follow net load after hydropow er 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 ta bles indicate that GHG em ission in tons per hour
are at their maximum at full load and are lowe r 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 effici ency 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 turb ines 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 e xhibits 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 reliabi lity of wind may vary unexpectedly resulting in variable output from wind genera tion resources. One of the stat ed purposes of the Troutdale Energy Center is to integrate with wind power, whic h 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 inhere ntly less efficient than operating continuously at full load. This is an unavoidabl e consequence that will often result in a higher GHG emission rate, on a lb/MWh basis, when the f acility is operating. The fact that wind power is available at times means that, generally, le ss 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 whol e 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 f acilities identified by the commenters, Port Everglades Energy Center5, Pio Pico Ener gy Center6 and Puget Sound Energy Fredonia Generating Station Expansion Pr oject7. The GHG BACT limits for these facilities are showPage | 21 August 3, 2015 below, along with the full load GHG emission ra tes for the turbines at the proposed Troutdale Energy Center (TEC):

Simple Cycle Combustion Turbine

Proposed BACT: Annual Average 1,707 CO 2 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

CO 2 Emissions (lb/MWh equivalent gross w/10% degradation) 1,136 1,203 1,367 1,786 1,591 1,701 1,927

CO 2 (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

CO 2 (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 CO 2 lb/MWh

HRSG Firing Unfired Fired Unfi red 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) 359,622 411,660 278,514 210,618 285,777 185,508Page | 22 August 3, 2015 Fuel Flow (MMBtu/hr, HHV) 2,595 3,092 2,106 1,662 2,298 1,599

CO 2 Emissions (lb/MWh equivalent gross w/10% degradation) 844 878 884 923 1,311 1,406

CO 2 (tons/hr) 152 181 123 97 187 130 97 130

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

CO 2 (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 re ferenced 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 lo w load. It appears to DEQ that
the BACT limits were set at the full load emissi on rates, and that the BACT limits above would limit the operation of these facilities to full or clos e 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 rede fine a facility. The stated purpose of the proposed Troutdale Energy Center is to provide base load, lo ad following and peaking power, and this requires the facility to operate all co mbustion 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 inte nded manner and would constitute redefining the facility to a base-load only ge nerating 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 em ission rates (on a lb/MWh basis) at lower
loads.

In consideration of all of the above, DEQ doe s 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 part icular 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 lim its 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 refl ect 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 th ere is a legal requirement to establish separate GHG BACT limits in te rms of lb/MWh for natural gas and ULSD.

CPV Energy St. Charles – GHG limit of 3,217,553 TPY CO 2 e 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 iden tification of available co ntrol technologies or techniques, including inherently lower-emitting pr ocesses/practices/designs, addon controls, and a combination of inherently lower-emitting processes/practices and addon controls, that have a practical application to the c ontrol of GHG emissions. These cont rol technologies must include control technologies for the pol lutant under evaluation, GHG, rega rdless 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 s ource categories with similar e xhaust stream characteristics.

Technologies that formed the basis of an app licable 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 go al, objectives, purpose, or basic design. A BACT analysis may consider control t echnologies that change aspects of the proposed facility but do not redefine the nature of the proposed facility.

The available control technologies for GHG em issions for the 7FA.05 CT/HRSG at CPV St. Charles are high thermal efficiency system desi gn and carbon capture and sequestration (CCS).

High Thermal Efficiency System Design

Increased energy efficiency is a potential means of reduci ng GHG emissions and should be considered as a potential cont rol technology for GHG emissions. Th ere are generally two types of categories of energy efficiency improvement categories. The first category consists of technologies, process improvements, or other m eans 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 ofPage | 24 August 3, 2015 output would be pound per hour of steam generate d. It is EPA’s opinion that the available technologies for this first category will not be si gnificantly different th an those technologies considered for other NSR pollutant BACT analyses.

The second category of energy efficiency impr ovements 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 th e direct GHG emissions from the new source (which was evaluated in the first category of energy efficiency opti ons) but looks at other facility processes or ancillary equipmen t that could reduce the amount of energy consumed. Potential technologies included in this category may in clude 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 em ergency 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 evalua te their overall energy efficient technologies against a high-level performance facility in th e 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 fl uid via pipeline, and in jection and longterm geologic storage.

The capture technologies applicable for fo ssil 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 ai r in the combustion process to produce a highly concentrated CO2 stream.

Precombustion systems are not technically feasib le 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 feasib le, and both are currently in development as demonstration projects at coal-f ired power plants using amine and ammonia capture systems to remove the CO2 from the flue gas. These cap ture 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 applicati ons,\ 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 wa ste 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 (I nteragency Task Force, 2010).

Carbon sequestration usually involve s the injection of CO2 into d eep 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 co al seams are candidates for CO2 storage. Also, CO2 injected for enhanced oil recovery project s 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 ca rbonates, and terres trial 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 emi ssions. 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 Technica lly Infeasible Options

Step 2 of the top-down BACT analysis is the el imination 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 contro l technology should also be cons idered 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 generati on facility and is not currently commercially available. In addition, there ha s been no demonstration of carbon capture technology on a similar exhaust gas stream. Ther e 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 ra nking of technically feas ible options. The energy efficiency must look at the high thermal efficien cy design of the CT as well as various energy efficiency improvements throughout the facil ity. 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 h eat rate, expressed in units of Btu/kWh, and thus combusts less fuel per kilowatt-hour (kWh ) of electrical power outpu t. 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 anothe r 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 f acility will use the higher efficiency GE 7FA.05 CT and is committed to the exclusive combustion of pipeline-quality natural gas in thePage | 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 anal ysis is the selection of BACT.

5.2.5.6 Proposed GHG BACT Emissions Limits

CT/HRSG

CPV St. Charles proposes a GHG BACT emissi ons limit of 3,217,553 short tons of CO2e per year for two CT/HRSGs based on a rolling 12-m onth average. This GHG BACT emissions limit is based on the GE 7FA.05 high efficiency CT an d 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 poten tials 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 ava ilable 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 c onditions (refer to Table 5

‐ 3). For comparison, the existing SH5 unit combustion turbine, as GE 7FA.03 mode l, 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 em issions. 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, w ith the benefit of the HRSG and additional output from the STG, the gross heat rate of the propos ed GE 7FA.04 unit is e xpected range to from 7,044 to 7,328 Btu/kWh, HHV without evaporative cooling.

Because the new combustion turbine will be adde d to an existing combined cycle unit and its HRSG will provide steam to a steam turbine generato r 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 exis ting 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 c onditions. Therefore, the City of Austin is proposing GHG BACT limits based on the new combustion turbine alone (s imple 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/M Wh (or 916 lb/MWh) gross output basis for the combined cycle unit that shares the ST G with the existing SH5 combustion turbine,
with unfired HRSG

 Simple cycle combustion turbine gross out put 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 combus tion turbine, at 68°F with unfired HRSG

The proposed output

‐ based GHG emission limits are equivale nt 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 ba sis) 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 w ith these performance standards is determined for operation at 100% load at ISO conditions, without evaporative cooling or duct burner firing. This provides a st andard basis for comparison of the GHG limits that are permitted for different projects. In orde r to demonstrate that the proposed simple cycle GHG limit corresponds to the combined cycle perfor mance 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 regul ate GHG emissions from all operating conditions, including those using evaporative cooling and with duct burner firi ng, 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 propose d 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 cove r other operating conditions and emissions has been used in other recent GHG BACT pe rmit limits for combined cycle units.

Each of the proposed limits is calculated to in clude a 10% margin to account for measurement error, equipment and site varia tions, 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 calib rated fuel flow mete rs, with heat input calculated based on weighted average monthly h eating values provided by the pipeline natural gas supplier, and emissions of CO2e calculated based on emi ssion factors and GWPs from 40 CFR 98 (greenhouse gas monitoring rule). Gross out put (kW) will be continuously measured and recorded at the combustion turbine generator.Page | 28 August 3, 2015 Victoria Power – GHG Basis of 940 lb CO 2 /MWh (gross) on a 12 m.r.a.

Pur s uant to th e p rovisions of this permit

, Victoria WLE, L.P

. (Vict o ria) will carry out a maj or modification at th e existing Victoria Pow e r Station (VPS) located in Victoria, Victoria County,

Texas. The exis t ing VPS i s a n atu ral gas-fired combined cycle base load power gene ratin g station that curr e ntly operates in a 1 b y I by 1 ( 1 x 1 x 1 ) co nfi guratio n (one combusti on turbine

,

one H RSG and one s t eam tur lb in e) with a gas tu rbi ne (M50 lf ), heat re covery steam generator ( H R SG) equ i pped with duc1t burners and a s t ea m generat or (General E l e ctric 05)

. The project
would add a new gas turb ine (GE.7FA.04 or equivale nt) and HRS G equipped with duct burners.
After t h es e additio n s, the facility will be able to opera t e i n a natural gas-fired combined cycl e

ge nerat in g unit in a 2 by 2 by l (2 x 2 x 1 ) configuration (two comb u stion turbines, two HRSG
and one ste am turbin e) that utiliz es the existing non-modified M501 F combustion turbine and

HR SG a nd the exist ing non-modified steam turbine. Th e VPS plant is authorized t o operate in a

1 x 1 x 1 comb in ed cy cle configuration with the n ew gas turbine and new HR SG, and it r etains
ab 11 ity to operate in Tts orTglnal 1 x 1 x 1 combined cycle configura t ion-without an as s i g n e d GHG BACT limit. VPS operations cove red by the permit will consist of the following sources of
GHG emissions:

 Natural Gas-Fired Combined Cycle Combusti on Turbine (GE.7F A.04 or equivalent). The combustion turbine is equi pped 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 wi th sulfur hexafluoride (SFG).

Pinecrest Energy Center – GHG basis of 909.2-942.0 lb CO 2 /MWh

PCEC proposes as BACT for this project, the fo llowing energy efficiency processes, practices, and designs for the proposed comb ined 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 Proce sses, 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 CyclesPage | 29 August 3, 2015 o Use of Exhaust Steam Condenser

o Efficient Blading Design

o Efficient Generator Design

 Plant-wide Energy Efficiency Pr ocesses, 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 efficien cy limit, PCEC started with the turbine’s design base load net heat rate for combined cycle operation and then calcula ted a compliance margin based upon reasonable degradation factors that may foreseeably reduce efficiency under realworld conditions. The design base load net he at rate for the combustion turbines being considered for this project are as follows: the Ge neral Electric 7FA design ba se load net heat rate is 6674 Btu/kWhr (HHV) without duct burner fi ring 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 firi ng 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 bur ner firing. Note that th ese 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 plan t. 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 cons tructed facility will not be able to achieve the design heat rate.

 A 6% performance margin re flecting 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 ma ny elements of the plant, wh ich are often imprecise or not
reflective of conditions once installe d 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 ove r 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 turb ine’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. Furt her, the projected 5% degradation rate represents the average, and not the maximum or guaranteed, rate of degradationPage | 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 heatrate degradation from normal wear and tear on the combustion turbines, PCEC is also providi ng a reasonable compliance margin based on potential degradation in other elements of the combined cycle plant that would cause the overall pl ant heat rate to rise ( i.e. , cause efficiency to fall). De gradation in the performance of the heat recovery steam generator, steam turbine, heat transfer, cooli ng 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 mont h rolling average, excluding startup hours:

Turbine Model Gross Heat Rate With Duct Firing (Btu/kWh) (HHV) Output Based Emission Limit With Duct Firing (lb

CO 2 /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 cap acity of the turbine, cost, reliability, and bpredicted longevity
of the turbines.

While starting up the combustion turbines followi ng ignition, a large porti on of the energy input to the combustion turbine is used for heating th e turbine casings and rotors, boiler tubes, main steam piping, and other portions of the thermal syst em rather than the production of electricity. During this startup period, the st eam 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 generato r. Therefore, PCEC pr oposes 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 de fined 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 CO 2 e emissions from Lake Side block 2 sh all 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 multip lied by an emission factor of 121.723 lb CO 2 e/MMBtu toPage | 31 August 3, 2015 obtain the total CO 2 e emissions during the 12-month peri od. 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 tw elve-month period to obtain the total gross generation. The CO 2 e per MWH(g) value is calculated by dividing the 12-month total CO 2 e emissions by the 12-month total gross generation.

Berks Hollow – GHG Basis of 1,000 lb CO 2 /MWh on a 365 d.r.a.

CCS has not been demonstrated on a facility of th is size, therefore it has been determined that it is infeasible. Energy efficiency utilization wi ll include: combine cycle technology (significantly higher levels of electric generation efficiency th an traditional fossil fuel generating facilities); equipment maintenance; instrumentation & contro l systems; HRSG design consideration; and high efficiency auxiliary equipm ent. Energy efficiency is the only technical feasible option remaining. The BACT determination is use of en ergy efficiency with an emission limitation of 1,000 lb C02/MW-hr (gross) on a 365-day rolli ng 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 CO 2 /MWh on a 365 d.r.a.

CCS has not been demonstrated on a facility of th is size, therefore it has been determined that it is infeasible. Energy efficiency utilization wi ll include: combine cycle technology (significantly higher levels of electric generation efficiency th an traditional fossil fuel generating facilities); equipment maintenance; instrumentation & contro l systems; HRSG design consideration; and high efficiency auxiliary equipm ent. Energy efficiency is the only technical feasible option remaining. The energy efficiency for the vari ous 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 bt u/kWh, HHV @ ISO conditions at 59F ambient temperature with no duct firing

 Mitsubishi G: net plant heat rate of 6,702 btu/kWh, HHV @ IS O conditions at 59F ambient temperature with no duct firing

 Siemens H: net plant heat rate of 6,577 bt u/kWh, HHV @ ISO conditions at 59F ambient temperature with no duct firing

The BACT determination is use of energy effi ciency with an emission limitation of 1,000 #

CO 2 /MW-hr (gross) on a 365-day rolling average which is based on proposed NSPS.Page | 32 August 3, 2015 Black Hills Power, Cheye nne Prairie – 1,100/1,600 lb CO 2 /MWh annual average basis

The only feasible option is the “Electrical Generation Effi ciency” 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 installatio n of combustion turbines from any manufacturer with a rating of nominal 40 MW. However, the annual CO 2 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 ra nge shown. The proposed permit limit of annual total
tons of CO 2 e and lb/MWh would remain fixed regard less of the combustion turbine selected.

The estimated total annual CO 2 e emissions from the combustion turbines are 936,588 tpy, and this value is proposed to be the annual CO 2 e 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, partia l load operation, and ambient temperature during operations, and considering the ra nge 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 com bustion turbine on an annual average basis. If the averaging time is less than 1 year, these perm it limits should be increased accordingly.

FROM PREAMBLE-WILL REMOVE

In total 31 major permits were identified w ith 39 discrete limits on GHG emissions. Eight of the limits were expressed as lbs/h or tons pe r year and were not incl uded in the analysis. In addition, one CHP unit that genera tes electricity and supplies steam to a chemical plant was in the set with a limit of 1,362 lb CO 2 /MWh based only on the gross el ectrical 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 spec ify if the output based standard was on a gross
or net basis and were th erefore also excluded.

The remaining 28 permit standards were expressed on a lb CO 2 /MWh or a heat rate basis
that could be converted to a lb CO 2 /MWh basis. Eight permit limits were based on net output ranging from 774-936 lb CO 2 /MWh-n. The lowest emission limit was for a hybrid power plant with a solar component of heat input that co uld contribute up to 50 MW. Twenty permit limits were based on gross output ranging from 833-1,100 lb CO 2 /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 CO 2 /MWh.

Each of the permit limits discussed above that is 1,000 lb CO 2 /MWh or include all periods of operation (i.e., in cluding startup, shutdown and ma lfunction). 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, th e Pioneer Valley Energy Ce nter has unrestricted use of natural gas while restricting operation wi th ultra-low sulfur diesel (ULSD) to 1,440 hours per 12-month period. This permit allows up to 16 per cent use of a fuel other than natural gas andPage | 33 August 3, 2015 the facility accepted a permit limit of 895 lb CO 2 /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 lo ads, 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 tu rbines 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 evaluate d emission limits for th e plant at 50, 75 and 100 percent gross load, since the expected opera tion is 50 percent gross load, the plant accepted
an emission limit of 918 lb CO 2 /MWh-n for the corresponding ev aluation. For the combined cycle combustion turbine units with duct burne rs on their HRSG, the hours of operation with
duct burners was included in the determination of the permit li mits. Typically, the hours of operation and heat input were limited to ensure th at the units are operated in the most efficient way and reduce their CO 2 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 th e design efficiency.