## UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Region 4 Atlanta, Georgia

Preliminary Determination & Statement of Basis

for Okeelanta Cogeneration Station New Hope Power Company

January 2 1

, 201 4PSD

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## 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 Titl e V

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

................................ ................................ ......................... 7 5.2 Compliance Methodology (Monitoring, Recordkeeping, and Reporting)

........................ 9 9 8 6.0 Best Available Control Technology (BACT) and Recordkeeping Requirements

..................... 9 7.0 Additional Requirements

................................ ................................ ................................ . 13 13 12 7.1 Endangered Species

................................ ................................ ................................ .... 13 13 12 7.2 Essential Fish Habitat of Magnuson

- Stevens Act

................................ ............................... 13

7.3 National Historic Preservation Act

................................ ................................ ............. 14 14 13

7.6 Executive Order 13175

– Tribal Consultation

................................ ................................ .... 15 8.2 Public Hearing

................................ ................................ ................................ .................... 16

8.3 Administrative Record

................................ ................................ ................................ ........ 17

8. 4 Final Determination

................................ ................................ ................................ ............ 17PSD

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## 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 Protecti on Agency (EPA) Region 4

for a proposed project ( P roject) at the Okeelanta Cogeneration Station (Okeelanta)

. NHPC is

pro posing 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 mile s south of South Bay in Palm Beach County, Florida. Th e 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

increas ed 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 (NO
x ), carbon monoxide (CO), particulate matter with an aerodynamic diameter less than

or equa l to 10 microns (PM 10 ), and particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (PM 2.5 ) 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

- R401 6 to NHPC , subject to the terms and conditions describ ed in the permit. The draft permit incorporates the applicable requir ements for GHGs from the federal PSD program.

This document serves as a fact sheet, preliminary determination, and S tatement of B asis (SOB) for the draft permit. It provides an overview of the Project , a summary of the applicable requirements, the legal a nd factual basis for the draft permit conditions, and EPA’s analysis of key aspects of the application and permit such as the B est A vailable C ontrol T echnology (BACT) analysis for GHG emissions. Additional information can be found in the draft permit

accom panying 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 additio nal 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 serv es as a Fact Sheet as provided in 40 CFR § 124.8.PSD

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## 2.0 Applicant Information

2.1 Applicant Name and Mailing Address New Hope Power Company 8001 U.S. Highway 27 South South Bay, FL 33 493



### 2.2 Facility Location NHPC is proposing to modify the existing facility located approximate ly 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 f igure s :

Figure 2

- 1 County and Site Location

Figure 2

- 2 Facility Ar e al View and Boiler D LocationPSD

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## 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 MM Btu/hr. The

co rresponding 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 Cogenerati on Plant of 140 MW

- net will not be increased w ith the addition of the

new boiler.

The P roject will result in a net emission increase greater than PSD threshold lim its for NO
x , CO

, PM 10 , PM 2.5 , and GHGs. On August 27, 2013

, the FDEP issued their portion of the construction permit to the applicant (PSD

- FL

- 196R /0990332

- 0 2 1

- AC) , w hich addressed all pollutants mentioned except for GHGs. The expiration date of the c onstruction permit is December 31,

201 6

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

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

The Project will result in a significant net increase of 17.48 TPY of PM 10 , 1 7.48 TPY of PM 2.5 , 147 .74 TPY of NO
x , 187.65 TPY of CO, and 274,446 TPY of GHG emissions ( on a CO 2 e 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 o f CO 2 e

.

A lthough 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 wil l 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 t he existing facil ity 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 t o 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 prim arily biomass (bagasse and wood).



## 4.0 Legal Authority and Regulatory Applicability

4.1 EPA Jurisdiction

In 2010

, the EPA established a F ederal I mplementation P lan (FIP) to apply in each state that had

not submitte d by their established deadline a corrective S tate I mplementation P lan (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. FDEPPSD

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is responsible for issuing a separate pre construction and title V operating permit f or 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 t o 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 deter mined 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 P otential T o E mit (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 operatio nal 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, sha ll 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 re gulated 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 (CO 2 );

 Nitrous oxide (N 2 O);

 Methane (CH 4 );

 Hydrofluorocarbons (HFCs);

 Perfluorocarbons (PFCs); and

 Sulfur hexafluoride (SF 6 ).

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 a n amount that triggers PSD applicability involves a calculation of the source’s CO 2 e emissions as well as its GHG mass emissions. Consequently, when determining the applicability of PSD to GHGs, there is a two

part applicability process that evaluates both :

 The sum of the CO 2 e 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 n ew sources as well as existing sources not already subject to title V that emit, or have the potential to emit, at least 100,000PSD

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TPY CO 2 e and greate r than zero TPY on a mass basis . In addition, sources that emit or have the potential to emit at least 100,000 TPY CO 2 e and that undertake a modification that increases net emissions of GHGs by at least 75,000 TPY CO 2 e 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

po llutant. 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 wit h 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 titl e 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. T he 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 par ts 60 and 61.” A lthough 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 ma y 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 NSP S). 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 ” (M arch 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 tabl e addresses the relevant regulated NSR pollutants, as required under PSD

.

2 Federal Register 31514 75 FR 31514 (June 3, 2010)PSD

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- 1 Summary of Annual Project Emissions Changes

Pollutant PTE *

(TPY) Significant Emission Rate

(TPY) PSD Review Required

SO 2 19.54 40 No

PM 17.48 25 No

PM 10 17.48 15 Yes

PM 2.5 17.48 10 Yes

NO
x 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 (CO 2 e) 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 summa ry table , the project emis sions 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”. Consequentl y, 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 applica bility determination for GHG emissions. Based on the application, EPA estimates an additional 2,093 TPY of CO 2 emissions for 48 hours of fuel oil use, which is less than 0.76%

increase in CO 2 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 CO 2 e emission limits (lb CO 2 e/1,000 lbs steam produced) for both natur al 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 calculation s for equipme nt 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 inp ut rate of 589 MMBtu/hr

and a 24

- hr maximum heat input rate of 535.5 MMBtu/hr and a m inimum 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 wil l be equipped with Ultra

low N O
x burners and will fire natural gas and ope rate w ith 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, s ubpart DDDDD (Industrial, Commercial, and Institutional Boilers and Process Heaters) , the permit restricts Boiler D’s fuel oil usage to no more than 48PSD

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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

s ubpart DDDDD will apply.



### 5.2 Compliance Methodology (Monitoring, Recordkeeping, and Reporting) The applicant proposed to monitor compl iance with the CO 2 e 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 determin e CO 2 e e missions 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 NO
x , CO, PM 10 /PM 2.5 , and GHGs in quantities that equal or exceed the signific ant emission rate. Based on their authority, FDEP has permitted the NO
x , CO , PM 10 , and PM 2.5 emissions fo r 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.

E missions from the Project are included in the source’s potential to e mit, as required by 40 CFR 52.21(b)(4), and the facility is subject to operating limits and requirements for monitoring,

recordke eping 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

- by

case 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, an d 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

emiss ions 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 emi ssions 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 d efinition, although the 1990 CAA amendments added “clean fuels” after “fuel cleaning or treatment” in the above definition. See CAA § 169(3).PSD

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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 wit h 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 techn ically 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 S tep 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 BAC T 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 informatio n dated May 17, 2013

, and in a n 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 r eview, 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 th at could reduce emissions by improving the utilization of thermal energy and electricity that is generated and used onsite.

When the efficiency o f the steam generation process is increased, less fuel is burned to produce the same amount of electricity. T his provides the benefits of lower fuel costs and reduced airPSD

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pollutant emissions (including CO 2 ). In addition, a boi ler 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

 Insul ation and insulating jackets

 Capture en ergy 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 contro ls, which are air pollution control technologies that remove pollutants from a facility’s emissions stream. CCS is an add

- on pollution control technol ogy that is available for large CO 2 emitting facilities

, including fossil

fuel

- fired power plants and indu strial facilities with high purity CO 2 streams . CCS is composed of three main components: CO 2 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 CO 2 than oil, and about 45% less CO 2 than coal on a

lb/MMBtu basis.

Step 2: Eliminate technically infeasible control options

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

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

is no known suitable geological formation within a re asonable distanc e from the site . While EPA recognizes there are certain challenges with capturing CO 2 from lower concentration exhaust streams (such as a 10% CO 2 by volume stream that is typical for a natural gas

- fired boiler), we

believe that CO 2 capture systems exist th at have been demonstrated in practice and can be

transferred to boiler s 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

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Step 4: Evaluation of Impacts

CCS: The EPA recognizes that the logistical hurdles of install ing and operatin g a CCS system set this p ollution 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 (includi ng 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 sequestra tion. 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 n ot 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 natura l gas boiler P roject as $1 4 ,000,000

. 3 Based on a
post

- combustion capture capital cost factor of $86/ton CO 2 e, taken from the CCS Task Force Report (page 34) 4 , the estimated upfront capital cost to capture 90% of the CO 2 emissions (2 47 ,00 1 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 ($1 4 ,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 CO 2 pipeline does not currently exist in the vicinity of the NHPC facility, one would have to be bu ilt on yet to be acquired land. Given these factors, we believe the costs would increase substantially over what is already projected for the CO 2 capture
system. Furthermore, there are additional energy requirements to operate a C O 2 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 P roject.

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.

M aximized energy efficiency will be achieved by implementing the measures identified in the application, which includes but is not limited to : e fficient burner design and optimization,

insulation of the un it, 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 Email s 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 (Augu st 2010)PSD

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 157 pounds (lbs) of CO 2 e per 1,000 lbs of steam produced (lbs CO 2 e/1,000 lbs Steam) while firing natural gas; based on a 30

- day rollin g average

 218 lb CO 2 e/1,000 lbs Steam while firing fuel oil ; based on a 3

- hour rolling averag e

 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

Additi onally, 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 agenc ies, in consultation with the National Oceanic and Atmospheric Administration (NOAA) National Marine Fisheries Service (NMFS) and/or th e U.S. Fish and Wildlife Service (FWS) (collectively, “ the Services”), to ensure that any action authorized, funded, or c arried 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); se e 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 th e 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 t he 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 n one of the potentially identified endangered spec ies 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 t o 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 thePSD

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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 in to 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 elig ible 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. D ue to
environmental conditions consistent with thos e found at other archaeological sites in Palm Beach County and lack of professional archeological or historical investigation, there is some potential

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

not ified a nd 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 adop t 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, regiona l 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 c onsistent with the policy

declar ed 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 F CMP 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 Fed eral 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 justic e. 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 Stat e 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 GHG s , controlled by what we have determined is the BACT for those emissions. I t 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 GHG s . The global

climate

- change inducing effects of GHG emissions, according to the “ Endangerment and CausePSD

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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 permittin g 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 consul tation sent on March 6 , 2013 about the NHPC permit action. EPA sent a letter confirming thei r 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 an y 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 regard ing 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

communic ation 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 Decisi on

- making, set forth at 40 CFR P art 124. As provided in part 124, EPA is seeking public comment on NHPC air permit PSD

- EPA

R401 6 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 i n 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 willPSD

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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 comment s on the draft permit must be received by email or postmarked b y 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.

C omments 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 th e 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 other wise 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 dra ft

per mit, please contact: Mr. James Purvis at 404

- 562

- 9 1 39 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, 201 4 , 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

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

GHG permit on February 26, 201 4

, at the location given in the public notice. If no timely request for a publ ic 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

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### 8.3 Admini strative Record The administrative record contains the application, supplementa l information submitted by

NHPC , and correspondence, i ncluding e

- mails, between NHPC and its consultants and EPA

clarif ying various aspects of the NHPC application. The draft pe rmit 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 5 th 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 Determina tion 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 no tice of the final permit decision, provided the EPA has adequate contact information.