UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

Region 4 

Atlanta, Georgia 

Preliminary Determination & Statement of Basis

for

Okeelanta Cogeneration Station 

New Hope Power Company

January 21, 2014
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 2

Table of Contents

1.0 Introduction................................................................................................................................3

2.0 Applicant Information................................................................................................................4

2.1 Applicant Name and Mailing Address.................................................................................. 4

2.2 Facility Location ................................................................................................................... 4

3.0 Proposed Project ........................................................................................................................5

4.0 Legal Authority and Regulatory Applicability ..........................................................................5

4.1 EPA Jurisdiction ................................................................................................................... 5

4.3 Title V................................................................................................................................... 7

4.4 Federal Requirements for GHGs ......................................................................................... 7

5.2 Compliance Methodology (Monitoring, Recordkeeping, and Reporting)........................ 998

6.0 Best Available Control Technology (BACT) and Recordkeeping Requirements.....................9

7.0 Additional Requirements.................................................................................................131312

7.1 Endangered Species.................................................................................................... 131312

7.2 Essential Fish Habitat of Magnuson-Stevens Act............................................................... 13

7.3 National Historic Preservation Act ............................................................................. 141413

7.6 Executive Order 13175 – Tribal Consultation.................................................................... 15

8.2 Public Hearing .................................................................................................................... 16

8.3 Administrative Record........................................................................................................ 17

8.4 Final Determination ............................................................................................................ 17
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 3

1.0 Introduction

New Hope Power Company (the Applicant or NHPC) has applied for a Prevention of Significant 

Deterioration (PSD) air permit for the emission of Greenhouse Gases (GHGs) pursuant to the 

Clean Air Act (CAA) from the United States Environmental Protection Agency (EPA) Region 4 

for a proposed project (Project) at the Okeelanta Cogeneration Station (Okeelanta). NHPC is 

proposing to build one natural gas fired boiler (Boiler D) for steam generation at their existing

140-megawatt (MW) net electric cogeneration facility. The facility is located adjacent to the 

Okeelanta Corporation sugar mill and refinery, approximately 6 miles south of South Bay in 

Palm Beach County, Florida. The facility currently has two cogeneration boilers that combust 

primarily biomass (bagasse and wood), and one natural gas boiler to generate steam and 

electricity (Boilers A, B and C). The primary fuel for Boiler D will be natural gas, with very low 

sulfur distillate fuel oil (fuel oil) used as backup. The current maximum electrical generating 

capacity of the Okeelanta Cogeneration Plant of 140 megawatts, net (MW-net) will not be 

increased with the addition of the new boiler.

The Florida Department of Environmental Protection (FDEP) is responsible for issuing a 

separate construction and title V operating permit for the Project for regulated pollutants other 

than GHGs. A PSD permit application for GHG emissions from Boiler D was submitted to EPA 

Region 4. Also, a PSD application was submitted to the FDEP separately addressing nitrogen 

oxide (NOx), carbon monoxide (CO), particulate matter with an aerodynamic diameter less than 

or equal to 10 microns (PM10), and particulate matter with an aerodynamic diameter less than or 

equal to 2.5 microns (PM2.5) emissions for the proposed Project. EPA Region 4 is the agency 

responsible for implementing and enforcing CAA requirements for GHG sources in Florida. 

EPA has completed review of the application and supplemental materials and is proposing to 

issue Permit No. PSD-EPA-R4016 to NHPC, subject to the terms and conditions described in the 

permit. The draft permit incorporates the applicable requirements for GHGs from the federal 

PSD program.

This document serves as a fact sheet, preliminary determination, and Statement of Basis (SOB)

for the draft permit. It provides an overview of the Project, a summary of the applicable 

requirements, the legal and factual basis for the draft permit conditions, and EPA’s analysis of 

key aspects of the application and permit such as the Best Available Control Technology 

(BACT) analysis for GHG emissions. Additional information can be found in the draft permit 

accompanying this document as well as in the application materials and administrative record for 

this Project, as discussed in Section 8.0.1

Section 2.0 provides applicant and facility information followed by a description of the proposed 

Project in Section 3.0. Section 4.0 lists the legal authority and regulatory applicability. Pollutants 

emitted and emissions units are discussed in Section 5.0. BACT for all applicable units is listed 

in Section 6.0. Section 7.0 includes a description of additional requirements and how this Project

complied with them. Finally, Section 8.0 gives information about public participation.

 

1 The procedures governing the issuance of PSD permits are set forth at 40 CFR part 124, subparts A and C. See 40 CFR §§ 

52.21(q) and 124.1. Accordingly, EPA has followed the procedures of 40 CFR part 124 in issuing this draft permit. This 

Preliminary Determination describes the derivation of the permit conditions and the reasons for them as provided in 40 CFR § 

124.7, and also serves as a Fact Sheet as provided in 40 CFR § 124.8.
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 4

2.0 Applicant Information

2.1 Applicant Name and Mailing Address

New Hope Power Company

8001 U.S. Highway 27 South

South Bay, FL 33493

2.2 Facility Location

NHPC is proposing to modify the existing facility located approximately six miles south of 

South Bay in Palm Beach County, Florida. The UTM coordinates of the facility are Zone 17, 

524.9 kilometers (km) East and 2940.1 km North. 

The site location and facility is illustrated in the following figures:

Figure 2-1 County and Site Location

Figure 2-2 Facility Areal View and Boiler D Location
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 5

3.0 Proposed Project

NHPC has applied for a PSD air permit for GHGs pursuant to the CAA from the United States 

EPA Region 4 for the proposed Project. NHPC is proposing to build one additional boiler at their 

existing 140 MW net electric cogeneration facility which will be fired by natural gas with fuel oil

used as backup. The fuel oil will contain a maximum sulfur content of 0.05 percent. 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 current maximum electrical generating capacity of 

the Okeelanta Cogeneration Plant of 140 MW-net will not be increased with the addition of the 

new boiler.

The Project will result in a net emission increase greater than PSD threshold limits for NOx, CO, 

PM10, PM2.5, and GHGs. On August 27, 2013, the FDEP issued their portion of the construction 

permit to the applicant (PSD-FL-196R/0990332-021-AC), which addressed all pollutants 

mentioned except for GHGs. The expiration date of the construction permit is December 31, 

2016. EPA will be responsible for issuing the GHG portion of the PSD permit. The Project 

cannot be constructed until both the FDEP and EPA PSD permits are effective.

The Project will result in a significant net increase of 17.48 TPY of PM10, 17.48 TPY of PM2.5, 

147.74 TPY of NOx, 187.65 TPY of CO, and 274,446 TPY of GHG emissions (on a CO2e basis). 

Based on emissions estimates using 100% natural gas as fuel, and the applicable permitting 

thresholds, the Project will have significant emissions of GHGs on a mass basis and is subject to 

regulation for GHGs. GHG emissions will increase by 274,446 TPY of CO2e.

Although the NHPC application sought a permit that authorized use of fuel oil for 15% hours of 

operation, the permit will not allow that. Instead, to qualify under the “Gas 1 subcategory” of 40 

CFR part 63, subpart DDDDD (78 FR 7138), Boiler D will be allowed to burn fuel oil only 48 

hours for periodic testing of liquid fuel, maintenance, or operator training during any consecutive 

12 month period and also during periods of natural gas curtailment or supply interruption as 

defined at 40 C.F.R. § 63.7575.

Both the existing facility operating three existing boilers and the Project are located at 8001 U.S. 

Highway 27 South, approximately six miles south of Palm Beach, in Palm Beach County, 

Florida. The facility currently operates 3 boilers in order to generate steam and electricity. Boiler 

A was converted to natural gas fired under Permit Number 0990332-019-AC on June 6, 2012. 

Cogeneration Boilers B and C are authorized to combust primarily biomass (bagasse and wood).

4.0 Legal Authority and Regulatory Applicability

4.1 EPA Jurisdiction

In 2010, the EPA established a Federal Implementation Plan (FIP) to apply in each state that had 

not submitted by their established deadline a corrective State Implementation Plan (SIP) revision 

to apply their CAA PSD program to sources of GHGs. See 75 FR 82246 (Dec. 30, 2010). The 

State of Florida is subject to the FIP; therefore, the EPA is issuing this GHG PSD permit. FDEP 
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 6

is responsible for issuing a separate preconstruction and title V operating permit for the Project 

for regulated pollutants other than GHGs.

4.2 Prevention of Significant Deterioration (PSD)

The PSD program, as set forth at 40 CFR § 52.21, is applicable to major sources such as this 

proposed Project. The objective of the PSD program is to prevent significant adverse 

environmental impact from air emissions by a proposed new or modified source. The PSD 

program limits degradation of air quality to that which is not considered “significant.” The PSD 

requires the utilization of BACT as determined on a case-by-case basis taking into account 

energy, environmental and economic impacts, and other costs.

Under the PSD regulations, a stationary source is “major” if, among other things, it emits or has 

the Potential To Emit (PTE) 100 or 250 TPY or more (depending on source category) of a 

“regulated New Source Review (NSR) pollutant” as defined in 40 CFR § 52.21(b)(50). See 40 

CFR § 52.21(b)(1). “PTE” is defined as the maximum capacity of a source to emit a pollutant 

under its physical and operational design. “Any physical or operational limitation on the capacity 

of the source to emit a pollutant, including air pollution control equipment and restrictions on 

hours of operation or on the type or amount of material combusted, stored or processed, shall be 

treated as part of its design if the limitation or the effect it would have on emissions is 

enforceable.” See 40 CFR § 52.21(b)(4).

Beginning on January 2, 2011, GHGs became subject to regulation under the PSD major source 

permitting program as a regulated NSR pollutant when emitted in amounts greater than certain 

applicable thresholds. GHGs are a single air pollutant defined in 40 CFR 52.21(b)(49)(i) as the 

aggregate group of the following six gases:

 Carbon dioxide (CO2);

 Nitrous oxide (N2O);

 Methane (CH4);

 Hydrofluorocarbons (HFCs);

 Perfluorocarbons (PFCs); and

 Sulfur hexafluoride (SF6).

Due to the nature of GHGs and their incorporation into the definition of “subject to regulation”, 

the determination of whether a source is emitting GHGs in an amount that triggers PSD 

applicability involves a calculation of the source’s CO2e emissions as well as its GHG mass 

emissions. Consequently, when determining the applicability of PSD to GHGs, there is a twopart applicability process that evaluates both:

 The sum of the CO2e emissions in TPY of the six GHGs, in order to determine whether 

the source’s emissions are a regulated NSR pollutant; and, if so;

 The sum of the mass emissions in TPY of the six GHGs, in order to determine if there is 

a major source or major modification of such emissions.

For PSD permits issued on or after July 1, 2011, PSD applies to new sources as well as existing 

sources not already subject to title V that emit, or have the potential to emit, at least 100,000 
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 7

TPY CO2e and greater than zero TPY on a mass basis. In addition, sources that emit or have the 

potential to emit at least 100,000 TPY CO2e and that undertake a modification that increases net 

emissions of GHGs by at least 75,000 TPY CO2e and equal to or greater than 100/250 TPY on a 

mass basis will also be subject to PSD requirements.2

Table 5-1 lists the annual emissions for each regulated NSR pollutant from the Project, based on 

the use of 100% natural gas, as well as the significant emission rate for each regulated NSR 

pollutant. The permit application and Section 5.0 of this document contain information on the 

emissions factors used to determine the annual emissions for the Project. 

Okeelanta is an existing PSD source and the net increase in GHG emissions associated with the 

Project exceeds the threshold of 75,000 TPY. Section 6.0 of this document contains a discussion 

of the BACT analysis. 

4.3 Title V

Upon issuance of this PSD permit, the State of Florida will incorporate these permit conditions 

into the existing title V permit for the facility.

4.4 Federal Requirements for GHGs

New Source Performance Standards (NSPS) Subpart TTTT 

On January 8, 2014, EPA proposed an NSPS (75 FR 1430) that could influence the ultimate 

emission requirements for this source. The definition of BACT in PSD rules at 40 CFR 

52.21(b)(12) states that “in no event shall application of best available control technology result 

in emissions of any pollutant which would exceed the emissions allowed by any applicable 

standard under 40 CFR parts 60 and 61.” Although this facility may be within the source 

category covered by the proposed NSPS, the proposed NSPS emission limits are not a 

controlling floor for BACT purposes since the proposed NSPS is not a final action and the 

proposed standard may change. However, the NSPS is an independent requirement that will 

apply to any source subject to the NSPS that commences construction after the date the NSPS is 

proposed (unless that source is covered by a transitional source exemption adopted in the NSPS). 

Thus, this facility may ultimately be subject to, and need to comply with, the NSPS after it is 

finalized, even if the emissions limits in the final permit are higher than the NSPS. See EPA, 

“PSD and Title V Permitting Guidance for Greenhouse Gases” (March 2011) at 25.

5.0 Project Emissions

The maximum annual potential emissions for the Project, firing 100% natural gas, include GHG 

emissions from Boiler D. Table 5-1 summarizes the maximum annual emissions changes, 

submitted by the applicant. This table addresses the relevant regulated NSR pollutants, as 

required under PSD. 

 

2 Federal Register 3151475 FR 31514 (June 3, 2010)
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 8

Table 5-1 Summary of Annual Project Emissions Changes

Pollutant PTE*

(TPY)

Significant Emission Rate 

(TPY) PSD Review Required

SO2 19.54 40 No

PM 17.48 25 No

PM10 17.48 15 Yes

PM2.5 17.48 10 Yes

NOx 147.74 40 Yes

CO 187.65 100 Yes

VOC 12.65 40 No

Sulfuric Acid Mist 0.06 7 No

Lead 0.18 0.6 No

GHGs (CO2e) 274,446 75,000 (subject to regulation 

threshold) Yes

HAP 4.35 N/A N/A

Mercury 6.5 (lb/yr) 200 lb/yr No

* based on 100% natural gas firing, 8760 hours/year

As seen in the emissions summary table, the project emissions are based upon changes to facility

emissions associated with future equipment.

As described below, Boiler D will be subject to restrictions from 40 CFR Subpart DDDDD, 

which limits the use of fuel oil to 48 hours per calendar year; however, the limitations in the 

regulation allow for an unknown amount of fuel oil use during times of “natural gas curtailment 

and supply interruption”. Consequently, the worst case emissions scenario for Boiler D is 

difficult to calculate. As seen in Table 5-1 above, the Project triggers PSD for GHG emissions 

even with the use of 100% natural gas. Therefore, any amount of fuel oil use will not affect the 

PSD applicability determination for GHG emissions. Based on the application, EPA estimates an 

additional 2,093 TPY of CO2 emissions for 48 hours of fuel oil use, which is less than 0.76% 

increase in CO2 above the 100% natural gas scenario in Table 5-1. EPA has included in the draft 

permit fuel oil restrictions which are similar to those included in 40 CFR DDDDD as well as 

output-based CO2e emission limits (lb CO2e/1,000 lbs steam produced) for both natural gas and 

fuel oil usage. These emission limits will apply at all times to the respective fuel, regardless of 

how long the boiler may operate on fuel oil due to a “natural gas curtailment of supply 

interruption”. 

5.1 Unit Analysis 

Emissions calculations for equipment used during operation of Boiler D were made based on the 

assumptions described below:

Boiler D will be a natural gas boiler with a 1-hour maximum heat input rate of 589 MMBtu/hr 

and a 24-hr maximum heat input rate of 535.5 MMBtu/hr and a minimum thermal efficiency of 

85%. The 1-hour maximum steam production rate will be 440,000 lb/hr steam and 24-hour 

maximum steam production will be 400,000 lb/hr steam. Boiler D will be equipped with Ultralow NOx burners and will fire natural gas and operate with good combustion practices. Boiler D 

will be designed to operate burning 100% natural gas, with fuel oil as backup during periods of 

natural gas curtailment or supply interruption. To enable Boiler D to qualify for the Gas 1 

subcategory under 40 CFR part 63, subpart DDDDD (Industrial, Commercial, and Institutional 

Boilers and Process Heaters), the permit restricts Boiler D’s fuel oil usage to no more than 48 
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 9

hours per consecutive 12 month period for testing purposes (aside from use during periods of 

natural gas curtailment or supply interruption). As a result, only work practice standards from 

subpart DDDDD will apply.

5.2 Compliance Methodology (Monitoring, Recordkeeping, and Reporting) 

The applicant proposed to monitor compliance with the CO2e BACT limits for the Boiler

through the installation and use of a continuous monitoring system. The applicant proposes to 

use the monitored data (including gross steam output rate, fuel type and amount, hours of 

operation, and heat input rate) to determine CO2e emissions based on 40 CFR Part 98, Subpart C.

The applicant will calculate, record, and maintain record files according to requirements in the 

permit.

6.0 Best Available Control Technology (BACT) and Recordkeeping 

Requirements

A major modification of a major stationary source subject to PSD requirements is required to 

apply BACT for each pollutant subject to regulation under the CAA that it would have the 

potential to emit in significant amounts. See 40 CFR § 52.21(j). Based on the emissions analysis 

summarized in Table 5-1, the Project has the potential to emit NOx, CO, PM10/PM2.5, and GHGs

in quantities that equal or exceed the significant emission rate. Based on their authority, FDEP 

has permitted the NOx, CO, PM10, and PM2.5 emissions for the Project. However, EPA is 

responsible for permitting the GHG emissions. Therefore, BACT must be determined for the

emission unit that emits GHGs as part of the EPA-issued permit.

Emissions from the Project are included in the source’s potential to emit, as required by 40 CFR 

52.21(b)(4), and the facility is subject to operating limits and requirements for monitoring, 

recordkeeping and reporting to ensure they will not exceed the potential emissions assumed in 

the application and impact review. 

BACT is defined in the applicable permitting regulations at 40 CFR § 52.21(b)(12), in part, as:

an emissions limitation (including a visible emission standard) based on the maximum degree of 

reduction for each pollutant subject to regulation under the Act which would be emitted from any 

proposed major stationary source or major modification which the Administrator, on a case-bycase basis, taking into account energy, environmental, and economic impacts and other costs, 

determines is achievable for such source or modification through application of production 

processes or available methods, systems, and techniques, including fuel cleaning or treatment or 

innovative fuel combustion techniques for control of such pollutant. In no event, shall application 

of best available control technology result in emissions of any pollutant which would exceed the 

emissions allowed by any applicable standard under 40 CFR parts 60 and 61. If the Administrator 

determines that technological or economic limitations on the application of measurement 

technology to a particular emissions unit would make the imposition of an emissions standard 

infeasible, 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. 

The CAA contains a similar BACT definition, although the 1990 CAA amendments added 

“clean fuels” after “fuel cleaning or treatment” in the above definition. See CAA § 169(3).
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 10

On December 1, 1987, the EPA issued a memorandum describing the top-down approach for 

determining BACT. See, e.g., In re Prairie State Generating Co., 13 E.A.D. 1 (EAB 2006). In 

brief, the top-down approach provides that all available control technologies be ranked in 

descending order of control effectiveness. Each alternative is then evaluated, starting with the 

most stringent, until BACT is determined. The top-down approach consists of the following 

steps:

Step 1: Identify all available control technologies.

Step 2: Evaluate technical feasibility of options from Step 1 and eliminate options 

that are technically infeasible based on physical, chemical and engineering 

principles. 

Step 3: Rank the remaining control technologies from Step 2 by control 

effectiveness, in terms of emission reduction potential.

Step 4: Evaluate the most effective controls from Step 3, considering economic, 

environmental and energy impacts of each control option. If the top option is not 

selected, evaluate the next most effective control option.

Step 5: Select BACT (the most effective option from Step 4 not rejected).

6.1 GHG BACT Analyses for Natural Gas Boiler

Step 1: Identify all available control technologies

The applicant identified the following available control technologies for the proposed boiler in 

their permit application dated February 4, 2013, supplemental information dated May 17, 2013,

and in an email dated November 11, 2013, responding to a request from the EPA for additional 

information:

1. Maximized Energy Efficiency

2. Carbon Capture and Storage (CCS)

3. Cleaner Fuels

Maximized 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 in 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, and

 Options that could reduce emissions by improving the utilization of thermal energy 

and electricity that is generated and used onsite. 

When the efficiency of the steam generation process is increased, less fuel is burned to produce 

the same amount of electricity. This provides the benefits of lower fuel costs and reduced air 
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 11

pollutant emissions (including CO2). In addition, a boiler that is a cogeneration unit produces 

both useful thermal energy and additional electric energy, which adds significantly to the overall

energy efficiency of the unit. The applicant has proposed implementation of the following 

measures to maximize the overall energy efficiency of the Project:

 Effective Burner Design

 Optimization

 Instrumentation and controls

 Economizer

 Air pre-heater

 Insulation and insulating jackets

 Capture energy from boiler blow down

 Condensate return

 Reduce slagging and fouling of heat transfer surfaces

 Reduce steam trap leaks

 Use of natural gas as primary fuel source.

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

technologies that remove pollutants from a facility’s emissions stream. CCS is 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. CCS is composed 

of three main components: CO2 capture and/or compression, transport, and storage. 

Cleaner Fuels: The use of natural gas as a fuel source is an inherently lower emitting practice 

than the use of fuel oil. The combustion of natural gas has the lowest emissions of GHGs of any 

fossil fuel and emits almost 30% less CO2 than oil, and about 45% less CO2 than coal on a 

lb/MMBtu basis.

Step 2: Eliminate technically infeasible control options

CCS: The applicant contends that CCS is technically infeasible for their project because (1) 

there has not been a full scale commercial demonstration of CO2 capture for boilers and (2) there 

is no known suitable geological formation within a reasonable distance from the site. While EPA 

recognizes there are certain challenges with capturing CO2 from lower concentration exhaust 

streams (such as a 10% CO2 by volume stream that is typical for a natural gas-fired boiler), we 

believe that CO2 capture systems exist that have been demonstrated in practice and can be 

transferred to boilers of the size proposed for use in this Project. Further, the applicant did not 

provide sufficient specificity with regard to dismissing geologic storage based on availability and 

distance. Accordingly, for the purposes of this draft permit, EPA considers CCS to be a 

technically feasible option for the proposed new natural gas-fired boiler at NHPC.

Step 3: Ranking remaining control technologies

Of the three potential emission control methods discussed, EPA has determined CCS, energy 

efficiency and use of clean fuels are all technically feasible options for reducing GHG emissions 

from the natural gas-fired boiler and were further evaluated in Step 4 of the BACT analysis.
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 12

Step 4: Evaluation of Impacts

CCS: The EPA recognizes that the logistical hurdles of installing and operating a CCS system 

set this pollution control technology apart from other types of add-on controls that are typically 

used to reduce emissions of other pollutants. Logistical hurdles identified by the applicant for 

CCS include: 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, developing a site for secure long term storage, and environmental 

permitting for underground GHG sequestration. In addition to these logistical factors, the EPA 

considered economic feasibility, in conjunction with energy and environmental impacts, in 

evaluating CCS for this project. 

The applicant stated that, as an independent cogeneration facility, it did not have the financial 

resources to implement a CCS system and if such a system was required, it would render the 

Project economically infeasible. See Application at 10. In addition, NHPC provided EPA with an 

estimate of the total capital cost of the natural gas boiler Project as $14,000,000.

3 Based on a 

post-combustion capture capital cost factor of $86/ton CO2e, taken from the CCS Task Force 

Report (page 34)4, the estimated upfront capital cost to capture 90% of the CO2 emissions 

(247,001 TPY) for the Project would be $21,242,086. Therefore, the estimated post-combustion 

capture capital costs for the Project ($21,242,086) are more than one and a half the total capital 

costs of the proposed natural gas boiler ($14,000,000). In addition, we estimate that there would 

be other capital costs for the CCS system, specifically with respect to the transportation 

component of a CCS system. Given that a CO2 pipeline does not currently exist in the vicinity of 

the NHPC facility, one would have to be built on yet to be acquired land. Given these factors, we 

believe the costs would increase substantially over what is already projected for the CO2 capture 

system. Furthermore, there are additional energy requirements to operate a CO2 capture and

compression system that would increase the overall cost of the CCS system, and potentially

increase emissions of other pollutants. As such, CCS is rejected under Step 4 of the BACT

analysis for this natural gas boiler Project.

Step 5: Select BACT

Based on the above evaluation, the most effective control options for GHG emissions are 

maximized energy efficiency and the use of natural gas as the primary fuel source with limited 

use of fuel oil. The boiler chosen for this project has a thermal efficiency of 85% efficient. 

Neither the applicant nor EPA was able to identify a similarly sized natural gas-fired boiler with 

a permitted efficiency of greater than 85%.. In addition, the applicant will implement the 

additional measures identified to ensure that the highest level of thermal efficiency is maintained. 

Maximized energy efficiency will be achieved by implementing the measures identified in the 

application, which includes but is not limited to: efficient burner design and optimization, 

insulation of the unit, use of instrumentation/controls to achieve high-efficiency/low-emissions 

performance, and capture of energy from boiler blowdown. The EPA concurs with the applicant 

that these control measures and operational practices together satisfy requirements for the BACT 

determination at this time, and EPA is proposing the following GHG BACT emission limits for 

this draft permit:

 

3 Emails dated 01/15/14 and 01/20/14 from Phil Cobb of Golder Associates to EPA

4

 Report of the Interagency Task Force on Carbon Capture and Storage (August 2010)
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 13

 157 pounds (lbs) of CO2e per 1,000 lbs of steam produced (lbs CO2e/1,000 lbs Steam) 

while firing natural gas; based on a 30-day rolling average

 218 lb CO2e/1,000 lbs Steam while firing fuel oil; based on a 3-hour rolling average

 Fuel oil operation will be limited to 48 hours annually (12-month rolling total) and during 

periods of natural gas curtailment or gas supply interruption 

Additionally, a minimum thermal efficiency of 85% will also be maintained in any month, 

averaged on a 30 day rolling average basis and determined by the following formula:

Thermal Efficiency = (lbs steam produced) / (boiler heat input)

Compliance with the minimum thermal efficiency requirement will be demonstrated by fuel use 

records and steam production records.

7.0 Additional Requirements

7.1 Endangered Species

Section 7(a)(2) of the Endangered Species Act (ESA) requires federal agencies, in consultation 

with the National Oceanic and Atmospheric Administration (NOAA) National Marine Fisheries 

Service (NMFS) and/or the U.S. Fish and Wildlife Service (FWS) (collectively, “the Services”), 

to ensure that any action authorized, funded, or carried out by the agency is not likely to 

jeopardize the continued existence of a species listed as threatened or endangered, or result in the 

destruction or adverse modification of designated critical habitat of such species. See 16 U.S.C. 

§1536(a)(2); see also 50 CFR §§ 402.13 and 402.14. The federal agency is also required to 

confer with the Services on any action which is likely to jeopardize the continued existence of a 

species proposed for listing as threatened or endangered or which will result in the destruction or 

adverse modification of critical habitat proposed to be designated for such species. See 16 U.S.C. 

§1536(a)(4); see also 50 CFR 402.10. Further, the ESA regulations provide that where more than 

one federal agency is involved in an action, the consultation requirements may be fulfilled by a 

designated lead agency on behalf of itself and the other involved agencies. See 50 CFR § 402.07. 

Based upon the best available data and informal consultation with the Services, the EPA 

determined that the issuance of this permit to NHPC is not likely to cause any adverse effects on 

listed species and essential fish habitats. The applicant will enforce standard protection measures 

during construction to ensure none of the potentially identified endangered species is harmed. 

The proposed permit includes a condition requiring NHPC to comply with all other applicable 

federal regulations. EPA received concurrence by email on March 27, 2013, from the FWS that 

the proposed Project is not likely to adversely affect resources protected by the ESA of 1973, as 

amended (16 U.S.C. 1531). The FWS also confirmed the ESA consultation requirements were 

met.

7.2 Essential Fish Habitat of Magnuson-Stevens Act

Section 305(b)(2) of the Magnuson-Stevens Fishery Conservation and Management Act (MSA) 

requires federal agencies to consult with NOAA with respect to any action authorized, funded, or 

undertaken by the agency that may adversely affect any essential fish habitat identified under the 
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 14

MSA. On July 01, 2013, NOAA’s NMFS Southeast Region, HCD determined in an email copied 

to EPA, there were no resources affected by the Project for which the NMFS would consult.

7.3 National Historic Preservation Act

Section 106 of the NHPA requires federal agencies to take into account the effects of their 

undertakings on historic properties. Section 106 requires the lead agency official to ensure that 

any federally funded, permitted, or licensed undertaking will have no effect on historic properties 

that are on or may be eligible for the NRHP

The Florida Division of Historical Resources (DHS) indicated in a letter dated December 4, 

2013, that review of information from the Florida Master Site File (FMSF) determined that there 

are no previously recorded archaeological sites or historic standing structures within the NHPC 

property and due to the location and nature of the project effect would be unlikely. Due to 

environmental conditions consistent with those found at other archaeological sites in Palm Beach 

County and lack of professional archeological or historical investigation, there is some potential 

for undiscovered sites to occur. EPA will include a permit condition requiring EPA and FDEP be 

notified and proper procedures be followed in the event historical or archaeological artifacts are

discovered during construction.

7.4 Coastal Zone Management Act

Executive According to the Coastal Zone Management Act of 1972 (CZMA), the State may 

develop and adopt a management program for its coastal zone in accordance with Federal rules 

and regulations promulgated by the Secretary, after notice, and with the opportunity of full 

participation by relevant Federal agencies, State agencies, local governments, regional 

organizations, port authorities, and other interested parties and individuals, public and private, 

which is adequate to carry out the purposes of the CZMA and is consistent with the policy 

declared in the CZMA.

The Florida Coastal Management Act (§380.205-380.27, Florida Statutes) requires that the CZM

Section of FDEP be responsible for certification of consistency with the FCMP for all Federal 

licenses, permits, activities, and projects listed in §380.23(3)(c), Florida Statutes, when such 

activities are subject to Federal consistency review and affect land or water use, are seaward of 

the jurisdiction of the state, or there is no State agency with sole jurisdiction for such consistency 

review. The issuance of Federal permits listed in §380.23(3)(c), Florida Statutes is not required 

for NHPC. 

7.5 Executive Order 12898 - Environmental Justice

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive branch 

policy on environmental justice. Based on this Executive Order, the EPA’s Environmental 

Appeals Board (EAB) has held that environmental justice issues must be considered in 

connection with the issuance of federal PSD permits issued by EPA Regional Offices [See, e.g., 

In re Prairie State Generating Company, 13 E.A.D. 1, 123 (EAB 2006); In re Knauf Fiber 

Glass, Gmbh, 8 E.A.D. 121, 174-75 (EAB 1999)]. This permitting action, if finalized, authorizes 

emissions of GHGs, controlled by what we have determined is the BACT for those emissions. It 

does not select environmental controls for any other pollutants. Unlike the criteria pollutants for 

which EPA has historically issued PSD permits, there is no NAAQS for GHGs. The global 

climate-change inducing effects of GHG emissions, according to the “Endangerment and Cause 
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 15

or Contribute Finding”, are far-reaching and multi-dimensional (75 FR 66497). Climate change 

modeling and evaluations of risks and impacts are typically conducted for changes in emissions 

that are orders of magnitude larger than the emissions from individual projects that might be 

analyzed in PSD permit reviews. Quantifying the exact impacts attributable to a specific GHG 

source obtaining a permit in specific places and points would not be possible [PSD and Title V 

Permitting Guidance for GHGs at 48]. Thus, we conclude it would not be meaningful to evaluate 

impacts of GHG emissions on a local community in the context of a single permit. Accordingly, 

we have determined an environmental justice analysis is not necessary for the permitting record.

7.6 Executive Order 13175 – Tribal Consultation

In accordance with Executive Order 13175 and the EPA Policy on Consultation and 

Coordination with Indian Tribes, the Miccosukee Tribe of Indians of Florida (Miccosukee Tribe) 

and the Seminole Tribe of Florida (Seminole Tribe) were offered the opportunity to consult 

regarding EPA’s consideration of the PSD permit application submitted by NPHC. Neither 

Tribe responded to the EPA invitation for consultation sent on March 6, 2013 about the NHPC

permit action. EPA sent a letter confirming their lack of response on August 1, 2013. Both tribes 

were informed that regardless of whether they elected to consult on the permit application, they 

would also have the opportunity to submit comments during any forthcoming public comment 

period. 

The objective of such consultation, in EPA’s view, is to improve EPA’s understanding of the 

perspectives of the Seminole Tribe and Miccosukee Tribe and to identify any issues or concerns 

they may have regarding EPA’s consideration of the NHPC application. During the course of 

any consultation on this matter, the EPA can offer such things as education and outreach, holding 

conference call(s) to discuss issues and concerns, and providing feedback through written 

communication explaining how the EPA considered any issues and concerns raised.

8.0 Public Participation

8.1 Opportunity for Public Comment

These proceedings are subject to EPA Procedures for Decision-making, set forth at 40 CFR Part 

124. As provided in part 124, EPA is seeking public comment on NHPC air permit PSD-EPAR4016 during the public comment period as specified in the public notice. 

Any interested person may submit written comments on the draft permit during the public 

comment period. If you believe any condition of the permit is inappropriate, you must raise all 

reasonably ascertainable issues and submit all reasonably available arguments supporting your 

position by the end of the comment period. Any documents supporting your comments must be 

included in full and may not be incorporated by reference unless they are already part of the 

record for this permit or consist of state or federal statutes or regulations, EPA documents of 

general applicability, or other generally available referenced materials. 

Comments should focus on the proposed air quality permit, the permit terms, and the air quality 

aspects of the Project. The objective of the air quality program is to prevent significant adverse 

environmental impact from air emissions by a new or modified source. All timely comments will 
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 16

be considered in making the final decision, included in the record, and responded to by EPA. 

EPA may group similar comments together in our response, and will not respond to each 

individual commenter directly. 

All comments on the draft permit must be received by email or postmarked by February 24, 

2014. Requests for a Public Hearing (see below) must be received by email or mail by February 

7, 2014. An extension of the 30-day comment period may be granted if the request for an 

extension adequately demonstrates why additional time is required to prepare comments. 

Comments must be sent or delivered in writing to the address below. All comments will be 

included in the public docket without change and may be made available to the public, including 

any personal information provided, unless the comment includes Confidential Business 

Information or other information in which disclosure is restricted by statute. Information that you 

consider Confidential Business Information or otherwise protected should be clearly identified as 

such and should not be submitted through e-mail. If you send e-mail directly to the EPA, your 

email address will be captured automatically and included as part of the public comment. Please 

note that an e-mail or postal address must be provided with your comments if you wish to 

receive direct notification of the EPA’s final decision regarding the permit and the EPA’s 

response to comments submitted during the public comment period. For questions on the draft 

permit, please contact: Mr. James Purvis at 404-562-9139 or R4GHGpermits@epa.gov. 

Submit comments on the draft permit and requests for a public hearing to:

EPA Region 4, APTMD

61 Forsyth Street, SW

Atlanta, GA 30303

ATTN: James Purvis

Fax: (404) 562-9019

Email: R4GHGpermits@epa.gov

8.2 Public Hearing 

EPA has discretion to hold a public hearing if we determine there is a significant amount of 

public interest in the draft permit. Requests for a public hearing must be received by EPA by 

email or mail by February 7, 2014, at the address given above, and state the nature of the issues 

proposed to be raised in the hearing. You may submit oral or written comments on the draft 

permit at the public hearing. You do not need to attend the public hearing to submit written 

comments. If there is significant public interest, EPA will hold a public hearing on the draft 

GHG permit on February 26, 2014, at the location given in the public notice. If no timely request 

for a public hearing is received, or EPA determines that there is not significant interest, the 

hearing will be cancelled. An announcement of cancellation will be posted on the EPA’s website 

at: http://www.epa.gov/region4/air/permits/ghgpermits/ghgpermits.html or you may call EPA at 

the contact number above to determine if the public hearing will be held.
PSD-EPA-R4016; NHPC – Okeelanta Cogeneration Station_ PD_1-21-2014 17

8.3 Administrative Record

The administrative record contains the application, supplemental information submitted by 

NHPC, and correspondence, including e-mails, between NHPC and its consultants and EPA 

clarifying various aspects of the NHPC application. The draft permit and the administrative 

record are available for public review at the EPA Region 4 office and the Belle Glade Library at 

the addresses listed below. Please call in advance for available viewing times.

 

 Belle Glade Library/Civic Center

 725 North West 5th Street

 Belle Glade, Florida 33430

 (561) 993-0728 

EPA Region 4 Office

61 Forsyth Street, SW

Atlanta, GA 30303

Phone: (404) 562-9643

The administrative record and draft permit are also available on EPA’s website at: 

http://www.epa.gov/region4/air/permits/ghgpermits/ghgpermits.html.

To request a copy of the draft permit, preliminary determination or notice of the final permit 

action, please contact: Ms. Rosa Yarbrough, Permit Support Specialist at: 404-562-9643, or 

R4GHGpermits@epa.gov. 

8.4 Final Determination 

A decision to issue a final permit, or to deny the application for the permit, shall be made after 

all timely comments have been considered. Notice of the final decision shall be sent to each 

person who has submitted written comments or requested notice of the final permit decision, 

provided the EPA has adequate contact information.