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BACT ANALYSIS FOR

GREENHOUSE GAS EMISSIONS 

FROM NEW NATURAL

GAS-FIRED BOILER

New Hope Power Company

Okeelanta Cogeneration Plant

Prepared For: New Hope Power Company

8001 U.S. Highway 27 South

South Bay, FL 33493

Submitted By: Golder Associates Inc.

6026 NW 1st Place

Gainesville, FL 32607 USA

Distribution: 4 copies – EPA Region 4

1 copy – FDEP

2 copies – New Hope Power Company

2 copies – Golder Associates Inc.

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PERMIT APPLICATION
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Table of Contents

1.0 INTRODUCTION.............................................................................................................................. 1

2.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS FOR GHGS ....................................... 4

2.1 BACT Requirements .................................................................................................................... 4

2.2 Greenhouse Gases ...................................................................................................................... 5

2.2.1 Step 1 – Identification of Control Technologies ....................................................................... 5

2.2.2 Step 2 – Technical Feasibility .................................................................................................. 8

2.2.3 Step 3 – Rank Control Technologies by Control Effectiveness .............................................10

2.2.4 Step 4 – Evaluation of Economic, Environmental, and Energy Impacts of Feasible 

Technologies..........................................................................................................................10

2.2.5 Step 5 – Selection of BACT and Rationale............................................................................11

3.0 OTHER FEDERAL REQUIREMENTS...........................................................................................14

3.1 Endangered Species Act............................................................................................................14

3.2 Coastal Zone Management Act..................................................................................................15

3.3 National Historic Preservation Act..............................................................................................16

3.4 Magnuson-Stevens Fishery Conservation and Management Act..............................................17

3.5 Federal Land Manager...............................................................................................................17

3.6 Environmental Justice ................................................................................................................17

3.7 Tribal Consultation .....................................................................................................................18

List of Tables

Table 2-1 Summary of GHG (CO2, CH4, N2O) BACT Determinations for Large (> 250 MMBtu/hr) 

Natural Gas-Fired Boilers (2002 – 2012)

Table 2-2 Summary and Ranking of GHG (CO2, CH4, N2O) Control Technologies

List of Appendices

Appendix A Calculation of CO2 Emissions From New Boiler D

Appendix B Documentation of NHPC Contacts with Federal, State, and Tribal Officials
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1.0 INTRODUCTION

New Hope Power Company (NHPC) operates a 140-megawatt (MW) net electric cogeneration facility 

located adjacent to the Okeelanta Corporation sugar mill and refinery, approximately 6 miles south of 

South Bay in Palm Beach County, Florida. The facility has three essentially identical cogeneration boilers 

(Cogeneration Boilers A, B, and C) that combust primarily biomass (bagasse and wood) to generate 

steam and electricity. The cogeneration facility generates steam to produce electrical energy year-round, 

but also supplies the adjacent sugar mill with process steam during the sugar cane grinding season, 

approximately October through March. The facility also supplies the Okeelanta sugar refinery with 

process steam year-round.

NHPC is proposing to add a fourth boiler, “Boiler D”, to the facility. Boiler D will be fired primarily with 

natural gas, with No. 2 fuel oil used only as a backup fuel. The new gas-fired boiler will allow NHPC the 

flexibility to produce steam and electricity year-round from all four boilers based on the most economical 

fuel or fuel mix, using bagasse, wood, No. 2 fuel oil, and/or natural gas. The current maximum electrical 

generating capacity of the facility (140 net MW) will not be increased with the addition of the new boiler.

Boiler D will have a maximum 1-hour average heat input rate of 589 million British thermal units per hour 

(MMBtu/hr) and a maximum 24-hour average heat input rate of 536 MMBtu/hr. The corresponding steam 

production rates are 440,000 pounds per hour (lb/hr) as a 1-hour average, and 400,000 lb/hr as a 24-hour 

average. The new gas-fired boiler will be permitted for 8,760 hours per year (hr/yr) operation.

The primary fuel for Boiler D will be natural gas, with very low sulfur distillate fuel oil used as backup. The 

distillate fuel oil will contain a maximum sulfur content of 0.05 percent. To control emissions of oxides of 

nitrogen (NOx), the boiler will use ultra low-NOx burners for firing natural gas and distillate oil. The very 

low sulfur content of the fuels utilized will control emissions of particulate matter (PM), sulfur dioxide 

(SO2), mercury (Hg), and metals. A modern combustion system design and overfire air system will 

control emissions of carbon monoxide (CO) and volatile organic compounds (VOCs).

The construction of the new boiler requires an air construction permit and prevention of significant 

deterioration (PSD) approval. PSD approval requires the submission of air quality assessments for 

determining the facility’s compliance with state and federal new source review (NSR) regulations. The 

critical aspects of these assessments include the air quality impact analyses performed using appropriate 

air dispersion models and the Best Available Control Technology (BACT) analyses that must be performed

to evaluate the selected emission control technology.

The U.S. Environmental Protection Agency (EPA) has implemented regulations requiring a PSD review 

for new and modified sources with air emissions above certain threshold amounts. EPA’s PSD regulations
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are promulgated under Title 40, Parts 52 and 51.166 of the Code of Federal Regulations (40 CFR 52 and 

51.166). Florida’s PSD regulations are codified in Rule 62-212.400 of the Florida Administrative Code 

(F.A.C.). The Florida PSD regulations incorporate the requirements of EPA’s PSD regulations. The new 

natural gas-fired boiler will be a “major modification” of an existing major source under PSD rules.

Based on the potential emissions from Boiler D, PSD review is required for each of the following regulated 

pollutants:

 NOx

 CO

 PM with an aerodynamic diameter less than or equal to 10 microns (PM10)

 PM with an aerodynamic diameter less than or equal to 2.5 microns (PM2.5)

 Greenhouse gases (GHGs)

Palm Beach County has been designated as an attainment area for several criteria pollutants: PM2.5, SO2, 

CO, and nitrogen dioxide (NO2). Palm Beach County is unclassifiable for PM10 and lead (Pb), and a 

maintenance area for ozone (O3). Palm Beach County is a PSD Class II area for PM10, PM2.5, SO2, CO, 

NO2, Pb, and VOCs. Therefore, the PSD review for Boiler D will follow the regulations pertaining to these 

designations. For each pollutant subject to PSD review, the following analyses are required:

1. Ambient monitoring analysis, unless the net increase in emissions due to the modification 

causes impacts that are below specified significant impact levels (SILs)

2. Application of BACT for each new or modified emissions unit

3. Air quality impact analysis, unless the net increase in emissions due to the modification 

causes impacts that are below specified SILs

4. Additional impact analysis (impact on soils, vegetation, visibility, and growth), including 

impacts on PSD Class I areas

The new boiler will be a minor source of hazardous air pollutants (HAPs), but the NHPC facility is a major 

source of HAPs.

The Florida Department of Environmental Protection (FDEP) has been delegated PSD review authority in 

Florida for all PSD pollutants with the exception of GHGs. Because Florida has not yet adopted EPA’s 

PSD regulations related to GHG emissions, EPA retains PSD review authority for GHGs. EPA’s authority 

is contained in a Federal Implementation Plan (FIP) that became effective on December 30, 2010. The 

FIP includes the EPA PSD regulations contained in 40 CFR 52.21, including the PSD applicability 

provisions, but applies only to GHGs.
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As a result, a PSD permit application for the new Boiler D has been submitted to the FDEP that addresses

NOx, CO, PM10, and PM2.5. A copy of the FDEP PSD application is being provided separately to EPA 

Region 4.

The PSD application for GHG emissions, which requires a BACT analysis, is contained in this report. The 

GHG BACT analysis is contained in Section 2.0. Compliance with other federal requirements, including 

the Endangered Species Act, is addressed in Section 3.0 of this report.
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2.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS FOR GHGS

2.1 BACT Requirements

The 1977 Clean Air Act (CAA) Amendments established requirements for the approval of pre-construction 

permit applications under the PSD program. One of these requirements is that BACT be applied to 

pollutants that are subject to PSD review. This section presents the proposed BACT for GHGs. The 

approach to the BACT analysis is based on the regulatory definitions of BACT, as well as consideration of 

EPA’s current policy guidelines requiring a “top-down” approach. A BACT determination requires a sitespecific analysis of the technical, economic, environmental, and energy impacts of the proposed and 

alternative control technologies [40 CFR 52.21 (b)(12)].

The “top-down” approach consists of the following five steps, as described in the New Source Review 

Workshop Manual-Draft (EPA, 1990):

1) Identification of all available control technologies

2) Elimination of technically infeasible control options

3) Ranking of the technically feasible control technologies based on their effectiveness

4) Evaluation of the economic, environmental, and energy impacts of the feasible control 

options

5) Selection of BACT based on consideration of the above factors

For the proposed NHPC Boiler D project, PM/PM10/PM2.5, NOx, CO, and GHGs are subject to PSD review 

and as a result, BACT review is required for these pollutants. In each case, BACT is an emission 

limitation that meets the maximum degree of emission reduction after taking into account the proposed 

project’s specific economic, environmental, and energy impacts, while considering the application of the 

technologies proposed. If it is impractical to impose an emission limit, a work practice standard may be 

specified.

EPA has issued several guidance documents addressing BACT for GHG emissions from electric utility 

and industrial combustion sources. These documents include the following:

 PSD and Title V Permitting Guidance for Greenhouse Gases, November 2010

 Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from 

Industrial, Commercial, and Institutional Boilers, October 2010

 Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from 

Coal-Fired Electric Generating Units, October 2010

 Proposed New Source Performance Standards (NSPS) for Greenhouse Gas Emissions 

for New Stationary Sources: Electric Utility Generating Units, 40 CFR 60, Subpart TTTT 

[77 Federal Register (FR) No. 72, pg. 22392, April 13, 2012]
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The BACT analysis for Boiler D at NHPC follows these guidance documents. The following sections 

provide the required BACT analysis for GHGs.

2.2 Greenhouse Gases

As part of the BACT analysis, a review was performed of previous GHG BACT determinations for similar 

natural gas-fired industrial and electric utility boilers listed in the RACT/BACT/LAER Clearinghouse on 

EPA’s web page. EPA’s GHG permitting website was also reviewed. From this information, BACT 

determinations issued within the last 10 years (i.e., since 2002) were identified. A summary of these 

BACT determinations is presented in Table 2-1.

From the review of previous BACT determinations, there have only been three known BACT determinations

for new natural gas-fired boilers. GHG BACT determinations for new natural gas-fired industrial and 

electric utility boilers have been based on clean (low-carbon) fuels and energy efficiency improvements. 

Only one previous BACT determination has a numerical emission limit, which is 117 pounds per million 

British thermal units (lb/MMBtu). The other two BACT determinations are based on good combustion or 

good operating practices.

2.2.1 Step 1 – Identification of Control Technologies

In the BACT analysis, GHGs are considered as a single air pollutant, which is the aggregate group of the 

six principal gases, carbon dioxide (CO2), nitrous oxide (N2O), methane (CH4), hydrofluorocarbons (HFCs),

perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). The aggregate of these emissions is expressed 

as CO2 equivalents (CO2e). CO2 emissions result from the oxidation of carbon in the fuel, CH4 emissions 

result from incomplete combustion, and N2O emissions result primarily from low temperature combustion. 

CO2, N2O, and CH4 are the principal GHGs that will be emitted from the new natural gas-fired boiler. 

Emissions of CH4 and N2O from natural gas-fired boilers are extremely low, and as a result, control 

options for these pollutants are not discussed.

EPA recommends that permit applicants and permitting authorities identify all “available” GHG control 

options that have the potential for practical application to the source under consideration. In the PSD and 

Title V Permitting Guidance for GHGs (EPA, 2010), EPA emphasizes two mitigation approaches for CO2: 

energy efficiency and carbon capture and storage (CCS). The Guidance for GHGs also states that clean 

fuels, which would reduce GHG emissions, should be considered while recognizing at the same time that 

the BACT analysis does not need to include a clean fuel option that would fundamentally redefine the 

source.

In EPA’s “Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Industrial, 

Commercial, and Institutional Boilers” (October 2010), a number of GHG reduction measures are 
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identified. These include various energy efficiency improvements, post-combustion techniques (CCS), 

and other measures such as fuel switching and combined heat and power applications.

GHG emission control options are discussed below.

2.2.1.1 Clean Fuel

The definition of BACT in 40 CFR 52.21(b)(12) includes use of clean fuels as a pollution control 

technique. The combustion of natural gas emits almost 30 percent less CO2 than fuel oil, and just under 

45 percent less CO2 than coal (source: 40 CFR 98, Subpart C; www.naturalgas.org). The proposed boiler 

will be fired primarily with natural gas, with No. 2 fuel oil used only as a backup fuel when natural gas is 

not available. Indeed, natural gas offers the lowest GHG emissions of all fuels available.

2.2.1.2 Energy Efficiency

Energy efficiency falls under the general category of lower-polluting processes/practices. Applying 

technologies, measures, and options that are energy efficient translates not only to the reduction of 

emissions of the particular regulated NSR air pollutant undergoing BACT review, but it also may achieve 

collateral reductions of emissions of other pollutants. There are different categories of energy efficient 

improvements:

 Technologies or processes that maximize the efficiency of the individual emissions unit

 Replace/upgrade burners

 Tuning

 Optimization

 Instrumentation and controls

 Economizer

 Air preheater

 Insulation

 Reduce air leakages

 Capture energy from boiler blowdown

 Condensate return

 Reduce slagging and fouling of heat transfer surfaces

 Insulating jackets

 Reduce steam trap leaks

 Options that could reduce emissions from a new green field facility by improving the 

utilization of thermal energy and electricity that is generated and used on site (i.e., 

combined heat and power)
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When the efficiency of the steam generation and power generation process is increased, less fuel is burned

to produce the same amount of steam and electricity. This provides the benefits of lower fuel costs and 

reduced air pollutant emissions [including CO2 on a pound per megawatt-hour (lb/MW-hr) basis]. In 

addition, a boiler that is a cogeneration unit produces both electric energy and additional useful thermal 

energy, which adds significantly to the overall energy efficiency of the unit.

2.2.1.3 Carbon Capture and Storage

CCS falls under the category of add-on controls, which are air pollution control technologies that remove 

pollutants from a facility’s emissions stream (flue gas). As identified in EPA’s PSD and Title V Permitting 

Guidance for Greenhouse Gases, EPA classifies CCS as an add-on pollution control technology that is 

“available” for large CO2-emitting facilities including fossil fuel-fired power plants and industrial facilities 

with high-purity CO2 streams. As a result, EPA requires that CCS be considered in Step 1 of the BACT 

analysis.

CCS is composed of three main components: CO2 capture and/or compression, transport, and long-term, 

perpetual storage.

Carbon Capture – Before CO2 gas can feasibly be stored, it must be captured as a relatively pure gas. 

Most power plants and other large point sources use air-fired combustors, a process that exhausts CO2

diluted with nitrogen. According to the U.S. Department of Energy, flue gas from the combustion of fossil 

fuels contains approximately 5 to 15 percent CO2. For effective carbon sequestration, the CO2 in these 

exhaust gases must be separated and concentrated.

According to the Department of Energy’s National Energy Technology Laboratory (NETL), technologies 

for capturing CO2 from relatively dilute streams such as those produced by power generation facilities are 

less common. These technologies currently include amine and chilled ammonia solvent systems, which 

have been used with coal-based power plant applications.

The Carbon Sequestration Leadership Forum (CSLF), a ministerial-level international climate change 

initiative comprised of 24 member nations representing over 60 percent of the world’s population, states: 

“Evolutionary improvements in existing CO2 capture systems and revolutionary new capture and 

sequestration concepts will be needed to bring carbon capture costs down.” The most likely options 

currently identifiable for CO2 separation and capture include the following:

 Absorption (chemical and physical)

 Adsorption (chemical and physical)

 Low-temperature distillation
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 Gas separation membranes

 Mineralization and biomineralization (http://www.cslforum.org/education/index.html#inFocus)

Carbon Transport – After the CO2 is captured, it must be transported to a carbon sequestration site. 

Pipelines are the most common method for transporting large quantities of CO2 over long distances. 

Shipping CO2 via pipeline involves compressing gaseous CO2 to a pressure above 1,160 pounds per 

square inch (psi), to increase CO2 density and make it easier and less expensive to ship. A CO2 pipeline 

would be similar to a high pressure natural gas pipeline. CO2 also can be transported as a liquid in 

seagoing vessels or via tankers on roads or railways. In these instances, the CO2 is held in insulated 

tanks at low temperatures and relatively low pressures.

Carbon Storage – In a CCS system, CO2 is captured, transported if necessary, and then stored. 

Geologic formations such as depleted oil and gas reservoirs, unmineable coal seams, and underground 

saline formations are potential options for long-term storage. Pressurized CO2 is injected into the deep 

geologic formations through drilled wells. Under high pressure, CO2 turns to liquid and can move through 

a formation as a fluid. Once injected, the liquid CO2 tends to be buoyant and will flow upward until it 

encounters a barrier of non-porous rock, which can trap the CO2 and prevent further upward migration. 

When CO2 is injected into a coal seam, it is adsorbed onto the coal surfaces, and methane gas is 

released and produced in adjacent wells. This technology is available. There are other mechanisms for 

CO2 trapping as well: CO2 molecules can dissolve in brine; react with minerals to form solid carbonates; 

or adsorb in the pores of porous rock.

Deep saline formations, which are layers of porous rock saturated with brine, present an enormous 

potential for geologic storage of CO2. However, the industry doesn’t have as much experience with saline 

formations as they have acquired through resource recovery from oil and gas reservoirs and coal seams. 

There is ongoing research focused on storage in organic rich shale, which is a thin horizontal layer of 

sedimentary rock with low vertical permeability, and in basalt formations, which are geologic formations of 

solidified lava. Other possible options include liquid storage in the ocean.

2.2.2 Step 2 – Technical Feasibility

Under the second step of the top-down BACT analysis, all available control techniques listed in Step 1 

may be eliminated from further consideration if they are not technically feasible for the specific source and 

unit under review. EPA considers a technology to be technically feasible if it has been demonstrated and 

operated successfully on the same type of source under review.
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2.2.2.1 Clean Fuels

Use of clean fuels is considered to be a technically feasible GHG emission control option for the new 

natural gas-fired boiler. The proposed boiler will primarily fire pipeline quality natural gas, with No. 2 fuel 

oil as backup, which are considered to be “clean fuels”. Natural gas is considered to be the cleanest fuel 

available, as its CO2e emissions are the lowest of any fossil fuel or biomass fuel. The use of No. 2 fuel oil 

will also be limited to a maximum of 15 percent of the potential total heat input on an annual basis.

2.2.2.2 Energy Efficiency

Efficient steam generation and power generation is considered to be technically feasible for the new 

natural gas boiler. Several techniques to improve energy efficiency were identified in Subsection 2.2.1.2. 

However, some of these techniques are only applicable to existing steam generating units. The 

techniques applicable to new steam generating units (boilers) are as follows:

 Efficient burner design

 Optimization

 Instrumentation and controls

 Economizer

 Air preheater

 Insulation

 Capture energy from boiler blowdown

 Condensate return

 Reduce slagging and fouling of heat transfer surfaces

 Insulating jackets

 Reduce steam trap leaks

2.2.2.3 Carbon Capture and Storage

In the PSD and Title V Permitting Guidance for GHGs, EPA states that it does not believe CCS will be a 

technically feasible BACT option in certain cases at this time. To establish that an option is technically 

feasible, the permitting record should show either that an available control option has been demonstrated 

in practice or is available and applicable, with the term “applicable” generally meaning a technology can 

reasonably be installed and operated on the source type under consideration. EPA recognizes the 

significant logistical hurdles that the installation and operation of a CCS system presents and that sets it 

apart from other add-on controls that are typically used to reduce emissions of other regulated pollutants.

It should also be noted that while CCS may be available as identified in EPA’s PSD and Title V Permitting 

Guidance for Greenhouse Gases (November 2010), there are no CCS systems “commercially available”

for full-scale power plants in the United States. Logistical hurdles for CCS include appropriate geological 
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formations within a reasonable distance, obtaining contracts for offsite land acquisition (including the 

availability of land), the need for funding (including, for example, government subsidies), timing of 

available transportation infrastructure, and developing a site for secure long term storage. Not every 

source has the resources to overcome the offsite logistical barriers necessary to apply CCS technology to 

its operations, and smaller sources will likely be more constrained in this regard. Based on these 

considerations, a permitting authority may conclude that CCS is not applicable to a particular source, and 

consequently not technically feasible, even if the type of equipment needed to accomplish the 

compression, capture, and storage of GHGs are determined to be generally available from commercial 

vendors.

There are no known applications of CCS for controlling CO2 emissions from boilers in Florida, and there is 

uncertainty as to the location of available and acceptable geologic formations for long-term CO2 storage. 

NHPC, being an independent cogeneration facility, does not have the financial resources required to 

implement CCS, and CCS if required would certainly render the project economically infeasible. Due to 

lack of commercial demonstration, CCS is considered to be technically and economically infeasible for 

controlling the CO2 emissions from the new natural gas-fired boiler.

2.2.3 Step 3 – Rank Control Technologies by Control Effectiveness

Of the three potential control technologies discussed above, use of clean fuels and energy efficiency 

techniques are the technically feasible CO2 control technologies (see Table 2-2). Together, these 

technologies present the top CO2 control options.

2.2.4 Step 4 – Evaluation of Economic, Environmental, and Energy Impacts of Feasible 

Technologies

Under Step 4 of the top-down BACT analysis, economic, energy, and environmental impacts are 

evaluated for each option remaining under consideration. Energy efficiency improvements generally 

reduce emissions of all pollutants resulting from combustion processes, so any energy efficiency 

improvements are desirable. The new natural gas-fired boiler will be designed to maximize its thermal 

efficiency and will use clean fuels. Therefore, there are no additional economic impacts associated with 

these options.

The CCS option was eliminated in Step 2 as not technically feasible for the project. Although EPA 

considers CCS as technically available, it is not commercially available. Indeed, EPA recognizes that at 

present, CCS is an expensive technology, largely because of the costs associated with CO2 capture and 

compression. In the Guidance, EPA states that even if not eliminated in Step 2 of the BACT analysis, on 

the basis of the current costs, CCS is more likely to be eliminated from consideration in Step 4 of the 
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BACT analysis, even in some cases where underground storage of the captured CO2 near the facility is 

feasible.

2.2.5 Step 5 – Selection of BACT and Rationale

The efficiency of the generation technology in producing steam and electricity, and the fuel utilized, are 

the most important aspects in GHG emissions from industrial boilers and electric generation facilities. 

Together, efficiency and fuel type dictate the amount of GHG emissions per unit of steam production or 

electrical generation.

The new natural gas-fired boiler will be designed for a thermal efficiency of 85 percent. Although the 

specific boiler manufacturer has not yet been selected, the manufacturer will be required to supply a 

boiler with a minimum thermal efficiency of 85 percent. Energy efficiency measures incorporated into the 

proposed Boiler D will include the following:

 Efficient burner design, consistent with ultra-low NOx emissions.

 Optimization – boiler operation will be optimized through the control system and initial 

tuning, and operated according to the manufacturer’s recommendations through a 

boiler-specific Operation and Maintenance (O&M) Plan.

 Instrumentation and controls – a modern digital control system including an oxygen

or CO2 monitor will be installed on the boiler.

 Economizer – used to preheat boiler feedwater using boiler flue gas stream, which 

maximizes energy efficiency. Based on a design of other similar boilers, the 

temperature of the flue gas at the entrance of the economizer will be approximately 

550 to 600 degrees Fahrenheit (°F) while the exit temperature will be 300°F or less.

 Insulation and refractory – significant heat loss can occur through the boiler shell, 

especially for large boilers. The proposed new boiler will be properly insulated by the 

manufacturer to minimize the heat energy losses. The radiation losses are expected 

to be less than 1 percent at full load, and less than 2 percent at 25-percent load. This 

demonstrates that radiation losses will be minimal.

 Minimize air leakages – NHPC will employ good maintenance practices to minimize 

air leakage during operation. Operational monitoring will also be used to identify air 

leakage conditions and sources. This monitoring will be incorporated into the O&M 

Plan.

 Capture energy from boiler blowdown – boiler blowdown is required to maintain water 

quality. However, some energy is lost. This waste heat can be recovered with a heat 

exchanger, flash tank, etc. to improve the overall efficiency of the boiler. Based on 

EPA’s Available and Emerging Technologies for Reducing Greenhouse Gas 

Emissions from Industrial, Commercial, and Institutional Boilers document, any boiler 

with continuous blowdown exceeding 5 percent of the steam rate is a good candidate 

for considering blowdown waste heat recovery. The new natural gas-fired boiler is 

expected to have a design continuous blowdown of less than 5 percent.

 Condensate return system – the new boiler’s makeup water system will be incorporated

into the existing makeup water system for the existing three cogeneration boilers. 
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This will take advantage of systems already in place to recover energy from the 

condensate.

 Reduce slagging and fouling of heat transfer surfaces – primarily through use of 

natural gas fuel.

 Steam line design and maintenance – appropriate measures will be included in the 

O&M Plan.

The boiler will also be operated very efficiently using clean fuels such as natural gas and low-sulfur fuel 

oil. An O&M Plan will be developed prior to boiler startup which will include measures to minimize the 

deterioration in boiler efficiency over time. The natural gas-fired boiler at NHPC will be brand new and 

specifically designed for its intended use at NHPC. Although some deterioration in the design efficiency 

of the boiler is expected to occur over time, based on the history of maintenance and operation at 

Okeelanta Cogeneration facility, the deterioration is expected to be minimal. Equipment deterioration 

primarily occurs over time with continued use. NHPC will schedule sufficient time for maintenance of the 

new boiler each year to minimize equipment deterioration over time.

In addition to the above measures, the boiler will be operated to produce both electrical energy and useful 

thermal energy, enhancing the energy efficiency of the unit. This measure will constitute the most 

significant energy efficiency method employed by the new boiler. The steam from the boiler is first sent 

through electric turbine generators, where electricity is generated. The steam discharging from the 

turbine generators, now at a lower pressure and temperature, is then sent to the Okeelanta sugar mill and 

refinery to provide useful thermal energy to the sugar production process.

Based on the above measures which will be implemented as BACT, no additional improvements in 

energy efficiency are necessary. Air preheat is a technique typically used in much larger boilers, such as 

those used in the electric utility industry, with heat inputs in excess of 1,000 MMBtu/hr and twice as large 

at the proposed natural gas-fired boiler. The proposed boiler will have a design efficiency of more than 

80 percent. Installation of an air preheater is not practical for this boiler. An air preheater would also 

impose additional pressure loss on the system.

Natural gas will be used as the primary fuel in the proposed boiler, with No. 2 fuel oil as a backup fuel. 

This is consistent with the definition of BACT, which states that a design, equipment, work practice, 

operational standard, or combination thereof, may be prescribed instead to satisfy the requirement for the 

application of best available control technology.

NHPC has performed a calculation of Boiler D’s projected CO2 emission in terms of lb/MW-hr (Appendix A),

using standard CO2 emission factors for natural gas and No. 2 fuel oil. The calculations take into account 
February 2013 13 123-87582

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a margin to account for an actual boiler efficiency less than the selected boiler manufacturer’s guaranteed

efficiency NHPC has assumed, and also to account for efficiency degradation over the life of the boiler.

Boiler D will operate during the sugarcane processing season along with the other three existing NHPC 

biomass-fired boilers. During the off-season, Boiler D will operate along with one other existing NHPC 

biomass-fired boiler. The electrical generation and useful thermal output of Boiler D will be different under 

these two operating regimes. Under the crop season operating regime, Boiler D maximum CO2 emissions

are estimated at 825 lb/MW-hr while firing natural gas, and 1,151 lb/MW-hr while firing No. 2 fuel oil. 

Under the off-season operating regime, Boiler D maximum CO2 emissions are estimated at 848 lb/MW-hr

while firing natural gas, and 1,184 lb/MW-hr when firing No. 2 fuel oil.

As shown in Appendix A, the overall CO2 limit, assuming 150 crop season days and 215 off-crop days, as 

well as the worst case of 85 percent natural gas firing and 15 percent No. 2 fuel oil firing, is 888 lb/MW-hr.

PSD regulations also require that BACT for a source cannot be less stringent than any federal new 

source performance standard (NSPS). On April 13, 2012, EPA proposed NSPS for Greenhouse Gas 

Emissions from Electric Utility Generating Units (77 FR No. 72, pg. 22392). The regulation would be 

codified in 40 CFR 60, Subpart TTTT. The proposed rule sets a CO2 (note: not CO2e) emission limit from 

all new electric utility generating units of 1,000 lb/MW-hr, 12-month rolling average. This limit is proposed 

regardless of fuel type, and therefore would apply to the proposed Boiler D regardless of fuel type. As 

shown above and in Appendix A, Boiler D CO2 emissions are well below the proposed NSPS limit of 

1,000 lb/MW-hr.
February 2013 14 123-87582

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3.0 OTHER FEDERAL REQUIREMENTS

In addition to the CAA requirements, there are requirements in four other statutes that sometimes must be 

met before a source can begin construction and operation under a PSD permit. As discussed further 

below, the other statutory requirements that may apply to the project are the Endangered Species Act 

(ESA), the Coastal Zone Management Act (CZMA), the National Historic Preservation Act (NHPA), and 

the Magnuson-Stevens Fishery Conservation and Management Act (MSFCMA). Environmental justice 

and tribal consultation must also be addressed as required by Executive Orders (EOs).

The permit applicant, through Golder Associates Inc., initiated contact with the EPA Region 4 Office in 

December 2012, and then with other implementing federal departments or agencies, state agencies, and 

tribal officials for these statutes to determine appropriate contacts and specific requirements that may apply

to the proposed project. NHPC’s contacts with the EPA and other federal, state, or tribal officials are 

documented in Appendix B. NHPC’s assessment of the applicability of these statutory requirements is 

presented in the sections below. This includes specific information needed from NHPC that is identified 

below for the four statutes, and any additional information that was requested by the EPA.

3.1 Endangered Species Act

Under Section 7(a)(2) of the ESA, 16 U.S.C. § 1536(a)(2), the EPA must ensure that any action

authorized, funded, or carried out by the EPA is not likely to jeopardize the continued existence of any 

federally listed endangered species or threatened species or result in the destruction or adverse 

modification of such species’ designated critical habitat. If the EPA’s action (i.e., permit issuance) may 

affect a federally listed species or designated critical habitat, Section 7(a)(2) of the ESA and relevant 

implementing regulations at 50 CFR 402 require consultation between the EPA and the U.S. Fish and 

Wildlife Service (FWS) and/or the National Marine Fisheries Service (NMFS), depending on the species 

at issue. After first contacting the EPA Regional Office to discuss the process, applicants should contact 

the FWS (and/or NMFS, if applicable) to ask whether there are any species or critical habitats listed or 

designated, or proposed for listing or designation, in the action area.

The NHPC site is located in the Everglades Agricultural Area (EAA), just south of Lake Okeechobee. The 

area surrounding NHPC is all agricultural area, primarily planted in sugarcane, with some sod and 

vegetable farms. The nearest national preserves or national parks are the Big Cypress National 

Preserve, located about 25 miles southwest, and the Everglades National Park, located about 55 miles 

south-southwest of the NHPC site. The Loxahatchee National Wilderness Area is located about 20 miles 

due east of the NHPC site. There are federally-listed threatened and endangered species in the Big 

Cypress Preserve and the Everglades National Park. Some of these may also be present in the 

Loxahatchee NWA.
February 2013 15 123-87582

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NHPC submitted a Site Certification Application (SCA) to the FDEP in August 2004 for an expansion of its 

electrical generating capacity. This application was approved on May 17, 2005, and Conditions of 

Certification No. PA 04-46 were issued. The SCA stated that no critical habitat of endangered species 

existed within 5 miles [8 kilometers (km)] of the NHPC site.

Nevertheless, the predicted air quality impacts of the proposed new natural gas-fired boiler, presented in 

the FDEP air construction permit application, demonstrate that there will not be a significant air quality 

impact on these areas due to the proposed project. Air Quality Related Values (AQRVs) in the Everglades

National Park will not be adversely affected. The modeling analysis demonstrated that the maximum 

impacts due to the proposed project are less than the EPA SILs for all pollutants and averaging times, 

except for 1-hour NO2 concentrations. For 1-hour NO2, concentrations fall below the SILs within 5 km of 

the NHPC facility.

As a result, no adverse effects to any threatened or endangered species which might be present near the 

facility are expected.

NHPC has initiated contact with the FWS and NMFS offices in the area to ask whether there are any 

species or critical habitats listed or designated, or proposed for listing or designation, in the action area. 

Further, NHPC requested a determination of any significant impact to endangered species due to the 

proposed project.

3.2 Coastal Zone Management Act

The CZMA encourages states to preserve, protect, develop, and where possible, restore or enhance 

valuable natural coastal resources such as wetlands, floodplains, estuaries, beaches, dunes, barrier 

islands, and coral reefs, as well as the fish and wildlife using those habitats. It includes areas bordering 

the Atlantic, Pacific, and Arctic Oceans, the Gulf of Mexico, Long Island Sound, and the Great Lakes.

In any application for a PSD permit for a facility located in a state’s coastal zone (or outside the state’s 

coastal zone but affecting any land or water use or natural resource of the coastal zone), the applicant 

should provide the EPA Regional Office with the applicant’s own certification that the proposed activity 

complies with the enforceable policies of the state’s NOAA-approved coastal program and that such 

activities will be conducted in a manner consistent with that program. The applicant also furnishes the 

state coastal zone management agency a copy of the certification, with necessary data and information.

The state agency may concur or object to the consistency determination. The Regional Office cannot 

issue the license or permit until the state agency concurs in the certification or, through the state’s failure 

to act, its concurrence can be conclusively presumed.
February 2013 16 123-87582

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The NHPC site is located well inland of either the east coast or west coast of Florida. The east coast is 

located approximately 45 miles east of the site, while the west coast is approximately 70 miles west of the 

site. The FDEP application demonstrates that the proposed project will not affect any land or water use 

or natural resource along the coast of Florida.

NHPC has initiated contact with the NMFS office in the area to determine if the NHPC site is within the 

coastal zone, and if so, whether the project is consistent with Florida’s coastal zone management plan.

3.3 National Historic Preservation Act

Section 106 of the NHPA requires the EPA, prior to the approval of the expenditure of any funds on, or 

prior to the issuance of any license for, an undertaking, to take into account the effects of its undertakings 

on historic properties and afford the Advisory Council on Historic Preservation (the Council) a reasonable 

opportunity to comment with regard to such undertakings (16 U.S.C. §470f). Under the Council’s 

implementing regulations at 36 CFR 800, Section 106, consultation is required for all undertakings that 

have the potential to affect historic properties. Section 106 consultations assess whether historic 

properties exist within an undertaking’s area of potential effect and, if so, whether the undertaking will 

adversely affect such properties. Consultation is generally with relevant state and tribal historic 

preservation authorities in the first instance, with opportunities for direct Council involvement in certain 

circumstances.

The term “historic properties” means prehistoric or historic districts, sites, buildings, structures, or objects 

included in, or eligible for inclusion in, the National Register of Historic Places maintained by the 

Department of the Interior. Historic properties include properties of traditional religious and cultural 

importance to an Indian Tribe or Native Hawaiian organization.

NHPC submitted a SCA to the FDEP in August 2004 for an expansion of its electrical generating capacity. 

This application was approved on May 17, 2005, and Conditions of Certification No. PA 04-46 were 

issued. The SCA stated that a review of the State of Florida Master Site File (FMSF) was undertaken to 

determine if known archaeological or historic sites have been recorded for the NHPC site or adjacent 

properties. The FMSF search revealed that no archeological sites had been recorded on the NHPC site. 

Further, a letter was sent to the Florida Department of State, Division of Historical Resources (DHR) in 

1993 requesting DHR to determine whether undiscovered archaeological or historical resources were 

likely to be present in the vicinity of the NHPC plant, and whether a pedestrian survey would be required. 

DHR responded and determined that:

 No significant archaeological or historical sites are recorded for or considered likely to

be present in the project area
February 2013 17 123-87582

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 Because of the project location and/or nature, it is unlikely such sites would be 

affected

 It was the opinion of DHR that the project would have no effect on historic properties 

listed or eligible for listing in the National Register of Historic Places

As a result, no adverse effects on any historical sites are expected due to operation of the proposed 

natural gas-fired boiler.

NHPC has initiated contact with the EPA Region 4 office to ask whether there are impacts upon historical 

sites due to the proposed project.

3.4 Magnuson-Stevens Fishery Conservation and Management Act

The MSFCMA was enacted to promote the U.S. fishing industry’s optimal exploitation of coastal fisheries 

by consolidating control over territorial waters to manage fish stocks. Implementation of the MSFCMA is 

by the U.S. Department of Commerce, NMFS, and its appointed regional fishery management councils. 

As part of the permit review process, the EPA Regional Office should discuss the project with the NMFS.

As described in Section 3.2, the NHPC site is located well away from coastal areas, and therefore will not 

impact coastal fisheries. NHPC has initiated contact with the NMFS offices in the area to ask whether the 

proposed project would violate any provision of the MSFCMA.

3.5 Federal Land Manager

The EPA’s policy is that the Federal Land Manager (FLM) should be notified by the EPA Regional Office 

about any project that is located within 100 km of a PSD Class I area. The FDEP air permit application 

addresses air impacts as well as AQRVs in the Class 1 area (Everglades National Park). The assessment

demonstrates there will be no adverse effects due to the proposed project. NHPC has initiated contact 

with the FLM and FWS to request a determination of any adverse impacts on the PSD Class I area due to 

the proposed project.

3.6 Environmental Justice

EO 12898 provides for federal agencies to identify and address disproportionately high and adverse 

effects of their actions on minority, low-income, and tribal populations. The EPA defines environmental 

justice to include the fair treatment and meaningful involvement of all people regardless of race, color, 

national origin, or income in environmental decisions that affect them.

The NHPC site is an existing site that has been in operation since 1996. The only nearby towns or cities 

are South Bay and Belle Glade. Due to the very low impacts of the proposed natural gas-fired boiler, 
February 2013 18 123-87582

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there will be no new impacts associated with the proposed project. Therefore, the proposed project will 

not disproportionately affect any minority, low-income, or tribal community.

3.7 Tribal Consultation

Under EO 13175, if the proposed project may affect tribal interests, the EPA Regional Office should 

initiate consultation with the affected tribe(s) sufficiently early in the process to allow for meaningful input 

by the tribe(s). In accordance with the Regional Office’s consultation plans and practices, the Regional 

Office should engage in such consultation prior to taking actions or implementing decisions that may 

affect the tribes.

The nearest known Indian tribes to the NHPC site are the Big Cypress Indian Reservation, located about 

20 miles southwest of the NHPC site, and the Miccosukee Indian Reservation, located about 25 miles 

south of the site. Again, due to the very low impacts predicted for the proposed NHPC project, the project 

should have no effect upon tribal interests.
TABLES
February 2013 123-87582

Table 2-1. Summary of GHG (CO2, CH4, N2O) BACT Determinations for Large (> 250 MMBtu/hr) Natural Gas-Fired Boilers (2002 - 2012)

RBLCID Company Name - Facility Name State Permit Number Permit Date Process Name Pollutant Control Method

*FL-0330 Port Dolphin Energy LLC FL DPA-EPA-R4001 12/1/2011 Boilers (4) 278 MMBtu/hr Carbon Dioxide 117 lb/MMBtu Tuning, Optimization, Instrumentation and Controls, 

Insulation, and Turbulent Flow

LA-0254 Entergy Louisiana LLC - Ninemile Point 

Electric Generating Plant

LA PSD-LA-752 8/16/2011 Auxiliary Boiler 338 MMBtu/hr Carbon Dioxide 117 lb/MMBtu

(8-hr rolling avg)

Proper Operation and Good Combustion Practices

Methane 0.0022 lb/MMBtu Proper Operation and Good Combustion Practices

Nitrous Oxide 0.0002 lb/MMBtu Proper Operation and Good Combustion Practices

Consolidated Environmental Management- LA PSD-LA-751 11/8/2010 Auxiliary Boilers (2) Carbon Dioxide N/A Good combustion practices to maintain low fuel 

consumption

 Nucor Steel Louisiana (prelim det)

Throughput Emission Limit

Y:\Projects\2012\123-87582 NHPC PSD\EPA (GHG)\Final\NHPC EPA Section 2 Tables.xlsx
February 2013 123-87582

Table 2-2. Summary and Ranking of GHG (CO2, CH4, N2O) Control Technologies

PM Abatement Method Technique Now Available

Estimated 

Efficiency

Feasible and 

Demonstrated? 

(Y/N)

Rank Based on 

Control 

Efficiency

Employed by 

NHPC Boiler? 

(Y/N)

Clean Fuel Fuel Substitution NA Y 1 Y

Energy Efficiency Good Design 10 - 50% Y 2 Y

Carbon Capture & Storage Capture, Transport & Storage >99% NTF NTF N

Note: NTF = Not Technically Feasible.

a Technically feasible for fluidized bed boiler only.

Y:\Projects\2012\123-87582 NHPC PSD\EPA (GHG)\Final\NHPC EPA Section 2 Tables.xlsx
APPENDIX A

CALCULATION OF CO2 EMISSIONS FROM NEW BOILER D
February 2013 123-87582

Appendix A

Calculation of CO2 Emissions From New Boiler D - Natural Gas Firing

Scenario assumes steam sent to Mill, which is used by the Mill to generate an additional 7 MW of electrical energy, is not counted.

Natural Gas Boiler Data

Net enthalpy = 1,138 Btu/lb

Steam Rate (full load) = 400,000 lb/hr steam

Efficiency = 85 %

Heat Input = 536 MMBtu/hr

CO2 emission factor = 53.02 kg/MMBtu

CO2 @ 400,000 lb/hr steam = 62,541 lb CO2/hr

CO2 @ 300,000 lb/hr steam = 46,906 lb CO2/hr

CO2 @ 120,000 lb/hr steam = 18,762 lb CO2/hr

Crop Season Operation (Natural gas boiler provides 300,000 lb/hr steam)

Gross Electrical output = 17.5 MW (1,200,000 lb/hr steam from all boilers generates 70 MW)

 NG boiler's portion of this is 70 MW x (300,000/1,200,000) 

Useful thermal output to Mill:

 High pressure steam = 67,500 lb/hr All boilers generate 270,000 lb/hr of HP steam to Mill not 

 Enthalpy = 1,336 Btu/lb used for electrical energy production:

 Heat output = 90.2 MMBtu/hr NG boiler's portion of this is 270,000 x (300,000/1,200,000) 

 Low pressure steam = 97,500 lb/hr All boilers generate 390,000 lb/hr of LP steam to Mill and Refinery;

 Enthalpy = 1,177 Btu/lb NG boiler's portion of this is 390,000 x (300,000/1,200,000) 

 Heat output = 114.8 MMBtu/hr

 Total useful thermal output = 204.9 MMBtu/hr

= 60.1 MW

Total Gross Output = 62.6 MW

 (gross elect. + 75% of thermal)

CO2 emissions = 750 lb CO2/MWh

Off-Season Operation (Natural Gas Boiler provides 120,000 lb/hr steam)

Gross Electrical output = 8.8 MW (300,000 lb/hr steam from all boilers generates 22 MW)

 NG boiler's portion of this is 22 MW x (120,000/300,000) 

Useful thermal output to Mill:

 High pressure steam = 0 lb/hr No HP steam is sent to mill during off-season

 Enthalpy = 1,336 Btu/lb

 Heat output = 0.0 MMBtu/hr

 Low pressure steam = 60,000 lb/hr All boilers generate 150,000 lb/hr of LP steam to Refinery;

 Enthalpy = 1,177 Btu/lb NG boiler's portion of this is 150,000 x (120,000/300,000) 

 Heat output = 70.6 MMBtu/hr

 Total useful thermal output = 70.6 MMBtu/hr

= 20.7 MW

Total Gross Output = 24.3 MW

 (gross elect. + 75% of thermal)

CO2 emissions = 771 lb CO2/MWh

Y:\Projects\2012\123-87582 NHPC PSD\EPA (GHG)\Final\NHPC Blr D Appx A - CO2 Limits.xlsx
February 2013 123-87582

Appendix A

Calculation of CO2 Emissions From New Boiler D- No. 2 Fuel Oil Firing

Scenario assumes steam sent to Mill, which is used by the Mill to generate an additional 7 MW of electrical energy, is not counted.

Natural Gas Boiler Data

Net enthalpy = 1,138 Btu/lb

Steam Rate (full load) = 400,000 lb/hr steam

Efficiency = 85 %

Heat Input = 536 MMBtu/hr

CO2 emission factor = 73.96 kg/MMBtu

CO2 @ 400,000 lb/hr steam = 87,242 lb CO2/hr

CO2 @ 300,000 lb/hr steam = 65,431 lb CO2/hr

CO2 @ 120,000 lb/hr steam = 26,173 lb CO2/hr

Crop Season Operation (Natural gas boiler provides 300,000 lb/hr steam)

Gross Electrical output = 17.5 MW (1,200,000 lb/hr steam from all boilers generates 70 MW)

 NG boiler's portion of this is 70 MW x (300,000/1,200,000) 

Useful thermal output to Mill:

 High pressure steam = 67,500 lb/hr All boilers generate 270,000 lb/hr of HP steam to Mill not 

 Enthalpy = 1,336 Btu/lb used for electrical energy production:

 Heat output = 90.2 MMBtu/hr NG boiler's portion of this is 270,000 x (300,000/1,200,000) 

 Low pressure steam = 97,500 lb/hr All boilers generate 390,000 lb/hr of LP steam to Mill and Refinery;

 Enthalpy = 1,177 Btu/lb NG boiler's portion of this is 390,000 x (300,000/1,200,000) 

 Heat output = 114.8 MMBtu/hr

 Total useful thermal output = 204.9 MMBtu/hr

= 60.1 MW

Total Gross Output = 62.6 MW

 (gross elect. + 75% of thermal)

CO2 emissions = 1,046 lb CO2/MWh

Off-Season Operation (Natural Gas Boiler provides 120,000 lb/hr steam)

Gross Electrical output = 8.8 MW (300,000 lb/hr steam from all boilers generates 22 MW)

 NG boiler's portion of this is 22 MW x (120,000/300,000) 

Useful thermal output to Mill:

 High pressure steam = 0 lb/hr No HP steam is sent to mill during off-season

 Enthalpy = 1,336 Btu/lb

 Heat output = 0.0 MMBtu/hr

 Low pressure steam = 60,000 lb/hr All boilers generate 150,000 lb/hr of LP steam to Refinery;

 Enthalpy = 1,177 Btu/lb NG boiler's portion of this is 150,000 x (120,000/300,000) 

 Heat output = 70.6 MMBtu/hr

 Total useful thermal output = 70.6 MMBtu/hr

= 20.7 MW

Total Gross Output = 24.3 MW

 (gross elect. + 75% of thermal)

CO2 emissions = 1,076 lb CO2/MWh

Y:\Projects\2012\123-87582 NHPC PSD\EPA (GHG)\Final\NHPC Blr D Appx A - CO2 Limits.xlsx
February 2013 123-87582

Appendix A

Performance and Proposed GHG BACT Limit (Gross Basis)

Category Units

Season

Fuel Gas Oil Gas Oil

Heat Input MMBtu/hr (HHV) 536 536 536 536

CO2 lb/hr 46,906 65,431 18,762 26,173

Gross Output MW 62.55 62.55 24.32 24.32

Gross Heat Rate Btu/kWh (HHV) 8,562 8,562 22,016 22,016

CO2lb CO2/MWh 750 1,046 771 1,076

Average On/Off Season lb CO2

/MWh 750 1,046 771 1,076

Margin for Guarantee % 5% 5% 5% 5%

Margin for Degradation % 5% 5% 5% 5%

Proposed CO2lb CO2/MWha

825 1,151 848 1,184

Season Days Days 150 150 215 215

Fuel Percentage % 85% 15% 85% 15%

12-Month Average lb CO2

/MWhb

a

 Crop Season of Off Season averages.

b

 12-month rolling average.

Estimated Performance

Crop Season Off Season

888

Y:\Projects\2012\123-87582 NHPC PSD\EPA (GHG)\Final\NHPC Blr D Appx A - CO2 Limits.xlsx
APPENDIX B

DOCUMENTATION OF NHPC CONTACTS WITH

FEDERAL, STATE, AND TRIBAL OFFICIALS
U.S. FISH & WILDLIFE SERVICE
1

From: Sealey, Kristen

Sent: Wednesday, January 30, 2013 4:13 PM

To: victoria_foster@fws.gov

Cc: Buff, Dave; Cobb, Phil

Subject: PSD Greenhouse Gas Emissions Notification - New Hope Power Company, Florida

Attachments: 123-87582_NHPC Project Desc for Agencies.pdf

Hello Ms. Foster,

New Hope Power Company (NHPC) operates an electric cogeneration facility located adjacent to the Okeelanta

Corporation sugar mill and refinery in Palm Beach County, Florida.  NHPC is requesting authorization to add a natural

gas‐fired boiler to the facility. The new boiler will have a nominal steam generating capacity of 400,000‐pound per hour

(lb/hr), fired primarily by natural gas (No. 2 fuel oil as backup only), and will be permitted for 8,760 hr/yr operation.  The

construction of the new boiler requires prevention of significant deterioration (PSD) approval by U.S. EPA for emissions

of greenhouse gases (GHG).  Federal statutory requirements that may apply to the project are:

 Endangered Species Act  

 Coastal Zone Management Act  

 National Historic Preservation Act  

 Magnuson‐Stevens Fishery Conservation and Management Act

 Federal Land Manager

In addition, the project may affect PSD Class I areas (Everglades National Park)and other areas administered by the U.S.

Fish and Wildlife Service.  Indian tribal lands may also be affected.  

The attached fact sheet provides additional information on the project including a project description, a site map,

emission tables, and air quality impact assessments as it relates to the aforementioned statutory requirements.  We ask

that you review this information to determine if the proposed project will comply with the rules and policies

administered by your agency.   

Thank you in advance for your assistance with this PSD GHG review and approval.  If you need additional information,

please feel free to contact me by email or telephone at 352‐336‐5600.  

Kristen Sealey | Project Engineer | Golder Associates Inc.             

6026 NW 1st Place, Gainesville, Florida, USA 32607           

T: +1 (352) 336-5600 | D: +1 (352) 224-1147 | F: +1 (352) 336-6603 | E: Kristen_Sealey@golder.com | 

www.golder.com        

Work Safe, Home Safe   

This email transmission is confidential and may contain proprietary information for the exclusive use of the intended recipient. Any use, distribution or copying of 

this transmission, other than by the intended recipient, is strictly prohibited. If you are not the intended recipient, please notify the sender and delete all copies. 

Electronic media is susceptible to unauthorized modification, deterioration, and incompatibility. Accordingly, the electronic media version of any work product may 

not be relied upon.     

Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation.     

Please consider the environment before printing this email.     
1

From: Sealey, Kristen

Sent: Wednesday, January 30, 2013 4:07 PM

To: jill_webster@fws.gov

Cc: Buff, Dave; Cobb, Phil

Subject: PSD Greenhouse Gas Emissions Notification - New Hope Power Company, Florida

Attachments: 123-87582_NHPC Project Desc for Agencies.pdf

Hello Ms. Webster,

New Hope Power Company (NHPC) operates an electric cogeneration facility located adjacent to the Okeelanta

Corporation sugar mill and refinery in Palm Beach County, Florida.  NHPC is requesting authorization to add a natural

gas‐fired boiler to the facility. The new boiler will have a nominal steam generating capacity of 400,000‐pound per hour

(lb/hr), fired primarily by natural gas (No. 2 fuel oil as backup only), and will be permitted for 8,760 hr/yr operation.  The

construction of the new boiler requires prevention of significant deterioration (PSD) approval by U.S. EPA for emissions

of greenhouse gases (GHG).  Federal statutory requirements that may apply to the project are:

 Endangered Species Act  

 Coastal Zone Management Act  

 National Historic Preservation Act  

 Magnuson‐Stevens Fishery Conservation and Management Act

 Federal Land Manager

In addition, the project may affect PSD Class I areas (Everglades National Park)and other areas administered by the U.S.

Fish and Wildlife Service.  Indian tribal lands may also be affected.  

The attached fact sheet provides additional information on the project including a project description, a site map,

emission tables, and air quality impact assessments as it relates to the aforementioned statutory requirements.  We ask

that you review this information to determine if the proposed project will comply with the rules and policies

administered by your agency.   

Thank you in advance for your assistance with this PSD GHG review and approval.  If you need additional information,

please feel free to contact me by email or telephone at 352‐336‐5600.  

Kristen Sealey | Project Engineer | Golder Associates Inc.             

6026 NW 1st Place, Gainesville, Florida, USA 32607           

T: +1 (352) 336-5600 | D: +1 (352) 224-1147 | F: +1 (352) 336-6603 | E: Kristen_Sealey@golder.com | 

www.golder.com        

Work Safe, Home Safe   

This email transmission is confidential and may contain proprietary information for the exclusive use of the intended recipient. Any use, distribution or copying of 

this transmission, other than by the intended recipient, is strictly prohibited. If you are not the intended recipient, please notify the sender and delete all copies. 

Electronic media is susceptible to unauthorized modification, deterioration, and incompatibility. Accordingly, the electronic media version of any work product may 

not be relied upon.     

Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation.     

Please consider the environment before printing this email.     
NATIONAL PARK SERVICE
1

From: Sealey, Kristen

Sent: Wednesday, January 30, 2013 4:10 PM

To: andrea_stacy@nps.gov

Cc: Buff, Dave; Cobb, Phil

Subject: PSD Greenhouse Gas Emissions Notification - New Hope Power Company, Florida

Attachments: 123-87582_NHPC Project Desc for Agencies.pdf

Hello Ms. Stacy,

New Hope Power Company (NHPC) operates an electric cogeneration facility located adjacent to the Okeelanta

Corporation sugar mill and refinery in Palm Beach County, Florida.  NHPC is requesting authorization to add a natural

gas‐fired boiler to the facility. The new boiler will have a nominal steam generating capacity of 400,000‐pound per hour

(lb/hr), fired primarily by natural gas (No. 2 fuel oil as backup only), and will be permitted for 8,760 hr/yr operation.  The

construction of the new boiler requires prevention of significant deterioration (PSD) approval by U.S. EPA for emissions

of greenhouse gases (GHG).  Federal statutory requirements that may apply to the project are:

 Endangered Species Act  

 Coastal Zone Management Act  

 National Historic Preservation Act  

 Magnuson‐Stevens Fishery Conservation and Management Act

 Federal Land Manager

In addition, the project may affect PSD Class I areas (Everglades National Park)and other areas administered by the U.S.

Fish and Wildlife Service.  Indian tribal lands may also be affected.  

The attached fact sheet provides additional information on the project including a project description, a site map,

emission tables, and air quality impact assessments as it relates to the aforementioned statutory requirements.  We ask

that you review this information to determine if the proposed project will comply with the rules and policies

administered by your agency.   

Thank you in advance for your assistance with this PSD GHG review and approval.  If you need additional information,

please feel free to contact me by email or telephone at 352‐336‐5600.  

Kristen Sealey | Project Engineer | Golder Associates Inc.             

6026 NW 1st Place, Gainesville, Florida, USA 32607           

T: +1 (352) 336-5600 | D: +1 (352) 224-1147 | F: +1 (352) 336-6603 | E: Kristen_Sealey@golder.com | 

www.golder.com        

Work Safe, Home Safe   

This email transmission is confidential and may contain proprietary information for the exclusive use of the intended recipient. Any use, distribution or copying of 

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NOAA / NATIONAL MARINE FISHERIES SERVICE
1

From: Sealey, Kristen

Sent: Wednesday, January 30, 2013 4:10 PM

To: david.bernhart@noaa.gov

Cc: Buff, Dave; Cobb, Phil

Subject: PSD Greenhouse Gas Emissions Notification - New Hope Power Company, Florida

Attachments: 123-87582_NHPC Project Desc for Agencies.pdf

Hello Mr. Bernhart,

New Hope Power Company (NHPC) operates an electric cogeneration facility located adjacent to the Okeelanta

Corporation sugar mill and refinery in Palm Beach County, Florida.  NHPC is requesting authorization to add a natural

gas‐fired boiler to the facility. The new boiler will have a nominal steam generating capacity of 400,000‐pound per hour

(lb/hr), fired primarily by natural gas (No. 2 fuel oil as backup only), and will be permitted for 8,760 hr/yr operation.  The

construction of the new boiler requires prevention of significant deterioration (PSD) approval by U.S. EPA for emissions

of greenhouse gases (GHG).  Federal statutory requirements that may apply to the project are:

 Endangered Species Act  

 Coastal Zone Management Act  

 National Historic Preservation Act  

 Magnuson‐Stevens Fishery Conservation and Management Act

 Federal Land Manager

In addition, the project may affect PSD Class I areas (Everglades National Park)and other areas administered by the U.S.

Fish and Wildlife Service.  Indian tribal lands may also be affected.  

The attached fact sheet provides additional information on the project including a project description, a site map,

emission tables, and air quality impact assessments as it relates to the aforementioned statutory requirements.  We ask

that you review this information to determine if the proposed project will comply with the rules and policies

administered by your agency.   

Thank you in advance for your assistance with this PSD GHG review and approval.  If you need additional information,

please feel free to contact me by email or telephone at 352‐336‐5600.  

Kristen Sealey | Project Engineer | Golder Associates Inc.             

6026 NW 1st Place, Gainesville, Florida, USA 32607           

T: +1 (352) 336-5600 | D: +1 (352) 224-1147 | F: +1 (352) 336-6603 | E: Kristen_Sealey@golder.com | 

www.golder.com        

Work Safe, Home Safe   

This email transmission is confidential and may contain proprietary information for the exclusive use of the intended recipient. Any use, distribution or copying of 

this transmission, other than by the intended recipient, is strictly prohibited. If you are not the intended recipient, please notify the sender and delete all copies. 

Electronic media is susceptible to unauthorized modification, deterioration, and incompatibility. Accordingly, the electronic media version of any work product may 

not be relied upon.     

Golder, Golder Associates and the GA globe design are trademarks of Golder Associates Corporation.     

Please consider the environment before printing this email.