11/14/14 Anadarko BlackHornet PD OCS

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

Preliminary Determination & Statement of Basis Outer Continenta l Shelf Air Permit OCS

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Anadarko Petroleum, Inc. Diamond BlackHornet Drilling Project

November 14 , 2014i

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### Table of Contents
1.0 Introduction

................................ ................................ ................................ ................................ ........... 3 2.0 Applicant Information

................................ ................................ ................................ ........................... 3 2.1 Applicant Name and Address

................................ ................................ ................................ ........... 3 2.2 Facility Location

................................ ................................ ................................ ............................... 4 3.0 Proposed Project

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

................................ ................................ ..................... 7 4.1 EPA Jurisdiction

................................ ................................ ................................ ............................... 7 4.2 OCS Air Regulations

................................ ................................ ................................ ........................ 7 4.3 Prevention of Significant Deterioration (PSD)

................................ ................................ ................. 8 4.4 Title V

................................ ................................ ................................ ................................ ............. 10 4.5 New Source Performance Standards (NSPS)

................................ ................................ ................. 10 4.6 National Emission Standards for Hazardous Air Pollutants (NESHAP)

................................ ........ 15 5.0 Project Emissions

................................ ................................ ................................ ................................ 17 5.1 BlackHornet (DR

- ME

- 01 through DR

- ME

- 08) and (DR

- GE

- 07) Analysis

................................ ... 18 5.2 BlackHornet Small Engines, Third Party Engines, and Miscellaneous Emission Sources

............ 19 5.8 Compliance Methodology

................................ ................................ ................................ ............... 23 6.0 Best Available Control Technology (BAC T) and Recordkeeping Requirements

.............................. 24 7.0 Summary of Air Quality Impact Analyses

................................ ................................ .......................... 53 7.1 Required Analyses

................................ ................................ ................................ .......................... 53 7.2 PS D Class II Air Quality Impact Assessment

................................ ................................ ................. 54 7.2.1 Air Quality Model Selection

................................ ................................ ................................ .... 55 7.2.2 Characteristics of Modeled Operational Scenarios

................................ ................................ .. 55 7.2.3 Meteorological Data

................................ ................................ ................................ ................. 57 7. 2.4 Building Downwash

................................ ................................ ................................ ................. 57 7.2.5 Receptor Locations

................................ ................................ ................................ .................. 57 7.2.6 Project Impact Assessment

................................ ................................ ................................ ...... 58 7.2.7 Ozone

................................ ................................ ................................ ................................ ....... 60 7.2.8 Additional Impact Assessments

................................ ................................ ............................... 61 7.3 PSD Class I Areas Analyses

................................ ................................ ................................ ........... 62 7.3.1 Air Quality Model Selection

................................ ................................ ................................ .... 63 7.3.2 Modeling Procedures

................................ ................................ ................................ ............... 63 7. 3.4 Meteorological Data

................................ ................................ ................................ ................. 63 7.3.5 Modeling Results

................................ ................................ ................................ ..................... 63 8.0 Additional Requirements

................................ ................................ ................................ .................... 66 8.1 Endangered Species Act and Essential Fish Habitat of Magnuson

- Stevens Act

............................ 66 8.2 National Historic Preservation Act

................................ ................................ ................................ . 67 8.3 Executive Order 12898

– Environmen tal Justice

................................ ................................ ............ 67 9.0 Public Participation

................................ ................................ ................................ ............................. 68 9.1 Opportunity for Public Comment

................................ ................................ ................................ ... 68 9.2 Public Hearing

................................ ................................ ................................ ................................ 69 9.3 Administrative Record

................................ ................................ ................................ .................... 70 9.4 Final Determination

................................ ................................ ................................ ........................ 70ii

11/14/14 Anadarko BlackHornet PD OCS

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- R4020 ABBREVIATIONS AND ACRONYMS

AP

- 42 AP

- 42 Compilation of Air Pollutant Emissions Factors AQRV Air Quality Related Values
BACT Best Available Control Technology
Bbl Barrels
BOEM Bureau of Ocean Energy Management
Breton NWR Breton National Wildlife Refuge
Btu British T hermal U nit
CAA Clean Air Act
CFR Code of Federal Regulations
CO Carbon M onoxide
CO 2 Carbon Dioxide
CO 2 e Carbon D ioxide (CO 2 ) E quivalent
EPA United States Environmental Protection Agency ESA Endangered Species Act
FLM Federal Land Manager
GHG Green h ouse Gas
GOM Gulf of Mexico
HAP Hazardous Air Pollutants hp Horsepower IC Internal Combustion

m 3 Cubic Meters MMScf/day Million Standard Cubic Feet per Day
MSA Magnuson

- Stevens Fishery Conservation and Management Act NAAQS National Ambient Air Quality Standards NESHAP National Emission Standards for Hazardous Air Pollutants
NO 2 Nitrogen Dioxide
NOAA National Oceanic and Atmospheric Administration
NO X Oxides of nitrogen NSPS New Source Performance Standards
NSR New Source Review
OCS Outer Continental Shelf OCSLA Outer Continental Shelf Lands Act
Part 55 40 CFR part 55
PEMS Parametric Emission Monitoring System
PM Particulate Matter

PM 2.5 Particulate Matter with an Aerodynamic Diameter Less Than or Equal to 2.5

Microns
PM 10 Particulate Matter with an Aerodynamic Diameter Less Than or Equal to 10 Microns

ppm Parts Per Million
PSD Prevention of Significant Deterioration
PTE Potential to Emit
SO 2 Sulfur Dioxide Support Vessels Support Boat, Anchor Handling Boat, Stimulation Vessel, Tug, Well Evaluation Vessel, and Barge
TPY Tons Per Year
TVP True Vapor Pressure VOC Volatile Organic Compounds3

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## 1.0 Introduction

Anadarko Petroleum Corporation, (the Applicant or Anadarko) has applied for an Outer Continental Shelf (OCS) air permit pursuant to section 328 of the Clean Air Act (CAA) from the United States Environmental Protection Agency (EPA) Region 4 for the proposed mobilization and operation of the deepwater drilling vessel BlackHornet , owned by Diamond Offshore Drilling Inc. and associated su pport fleet located on the OCS in the Gulf of Mexico east of longitude 87°30’ (87.5 ° ), west of the Military Mission Line (86°41’ west longitude), and not within 125 nautical miles of the state seaward boundary of Florida. Anadarko proposes three phases of project activity: drilling, well completion, and production well maintenance. The project is expected to operate for five year s and approximately 200 days per year.

The EPA Region 4 is the agency responsible for implementing and enforcing CAA requirements for OCS sources in the Gulf of Mexico east of 87°30’ (87.5°). 1 The EPA has completed a review of Anadarko’s application , including all supplemental materials provided

, and is proposing to is sue Permit Number OCS

- EPA

- R4020 to Anadarko for an exploratory drilling program subject to th e terms and conditions contained in the draft permit. The draft permit incorporates applicable require ments from the federal PSD and title V oper ating permit programs, New Source Performance Standards (NSPS), and National Emission Standards for Hazardous Air Pollutants (NESHAP) as required by the OCS air quality regulations in 40 CFR part 55.

This document serves as a fact sheet, preliminary deter mination, and statement of basis for the draft permit. It provides an overview of the project, a summary of applicable requirements, the legal and factual basis for draft permit conditions, and the EPA’s analysis of key aspects of the application and draft permit such as the best available control technology (BACT) analysis and Class II/Class I area air quality impact analysis. Additional information can be found in the draft permit accompanying this preliminary determination, as well as in the application materials and administrative record for this project, as discussed in Section 9 of this document. 2


## 2.0 Applicant Information

2.1 Applicant Name and Address

Anadarko Petroleum Corporation 1201 Lake Robbins Drive The Woodlands, Texas 77380

1 S ee CAA section 328

. The Department of the Interior has jurisdiction for CAA implementation west of 87°30’

. 2 The EPA must follow the administrative and public participation procedures in 40 CFR part 124 used to issue PSD permits when processing OCS permit applications under Part 55. 40 CFR § 55.6(a)(3). The EPA must also follow the administrative a nd public particpation procedures of 40 CFR part 71 when issuing permits to OCS sources subject to Title V requirements

. 40 CFR § 71.4(d). Accordingly, the EPA has followed the procedures of 40 CFR parts 71 and 124 in issuing the draft permit

. This Preli minary Determination & Statement of Basis serves as a statement of basis under 40 CFR § 124.7

, a f act s heet under 40 CFR § 124.8 , and a statement of basis under 40 CFR § 71.7(a)(5)

.4

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- R4020 2.2 Facility Loca tion

Anadarko is proposing to drill in the Eastern Gulf of Mexico located on the OCS waters east of longitude 87°30’, west of the Military Mission Line (86°41’ west longitude), at least 100 nautical miles from the Florida shoreline in the Bureau of Ocean E nergy Management BOEM Central Planning Area , and at least 125 nautical miles from the Florida state seaward boundary in the BOEM Eastern Planning Area

. The area contains both active lease blocks and lease blocks that the BOEM may lease in the future. The a vailable lease blocks are identified in Figure 2

- 1 below.

Figure 2

- 1

- Anadarko Oil Site and Lease Blocks in Eastern Gulf of Mexico

Image Source: Anadarko Petroleum Corporation Application, September 20135

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## 3.0 Proposed Project

The proposed project will mobilize the BlackHornet drillship and associated support vessels

. These vessels will include a combination of supply boats, an anchor handling boat, tug boats, barges, stimulation vessels, and well evaluation vessels . The proposed proje ct will consis t of three phases: the drilling phase, the well completion phase, and production well maintenance phase. At this time, there are no plans to establish permanent production platforms at the well site. Such permanent facilities would be permitted separately. Emissions from production well maintenance activities related to facilities on the sea floor are subject to regulation by this permit. The proposed project ’s annual operat ion will be limited by fuel use

. 3

Air pollutant emissions generated from the project include the criteria pollutants nitrogen dioxide (NO 2 ), carbon monoxide (CO), particulate matter (PM), particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (PM 2.5 ), particulate matter with an aerodynamic diameter less than or equal to 10 microns (PM 10 ), and sulfur dioxide (SO 2 ), as well as other regulated air pollutants including volatile organic compounds (VOC), oxides of nitrogen (NO X ), and greenhouse gases (GHGs). VOC and NO X are the measured precursors for the criteria pollutant ozone, and NO X and SO 2 are measured precursors for PM 2.5

.

E missions are primarily released from the combustion of diesel fuel in the drilling vessel’s main engines and in smaller engines that supply power for operating drilling equipment and support vessels . Emissions may also be released from other equipment such as fuel and mud storage tanks and from activities such as well completion

, pumping heavy lubricating mud, painting, and welding and from flare emissions associated with well maintenance activities

.

3 This fuel limit is approximately equal to operations of 200 calendar da ys per year, assuming that the project operated 24

- hours a day.6

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- R4020 Figure 3

- 1 Drilling Vessel

Image Source: Online http://www.marinetraffic.com/en/ais/details/s hips/9618903/vessel:OCEAN_BLACKHORNET Accessed on Nov. 13 , 2014

Based on emissions estimates and the applicable permitting thresholds, the project will have emissions of NO x CO, VOC, PM, PM 10 , PM 2.5 , and GHGs that meet or exceed the respective PSD and Title V significant emission rates and , hence, is subject to the PSD and Ti tle V
programs

. Any facility that emits a regulated New Source Review (NSR) pollutant at levels meeting or exceeding its PSD significant emission rate must perform a BACT an alysis for that pollutant and comply with all subsequent regulatory obligations for that pollutant as described in Section 6.0 below.

The emissions units to be used on the BlackHornet drilling vessel and the emissions units to be used on support vessels that will become a part of the OCS source are detailed in Sections 4.0 and 5.0 and Table s 4

- 2 and 4

- 3 . The d iesel powered units include eight main propulsion diesel electric g enerators (DR

- ME

- 01 through DR

- ME

- 08 ), one emergency generator (DR

- GE

- 01), one

em ergency air compressor diesel engine (DR

- AC

- 01), one fast rescue craft engine (DR

- FR

- 01), six life boat engines (DR

- LB

- 01 through DR

- LB

- 06), 16 third

- party engines (DR

- TP

- 01 through DR

- TP

- 11 and DR

- TP

- 17 through DR

- TP

- 21), five third

- party well evaluation engines (DR

- TP

12 through DR

- TP

- 16), and eight pump engines on the stimulation vessel (SV

- PE

- 01 through SV

- PE

- 08). The third

- party equipment is leased on short notice and the exact specifications are unknown. Anadarko selected worst

- case equipment to devel op emission calculations, but will identify the exact engines for the purpose of permit compliance and emissions inventory

.

The BlackHornet will be supported by up to two support vessels for the entire project and four well completion vessels. The support vessels will be used , sometimes simultaneously, to7

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- R4020 transport personnel, supplies, and fuel to the drilling vessel, as required for the duration of the exploratory drilling. Various support and well completion vessels will be used interchangeably depending on availability. Anadarko selected the largest support vessels (the supply boat HOS Coral and the anchor handling boat Kirt Chouest ) and the largest well completion vessels (a tug, a barge, a stimulation vessel, and a well evaluation vessel) to calculate emissions based on the
worst

- case scenario. Anadarko will maintain records of the engine specifications and number of hours each engine will operate within 25 miles of the BlackHornet for any support vessel used in place of the HOS Coral (supply boat), the Kirt Chouest (anchor handling boat), or any vessel used during well completion . Emissions for the support vessel and the well completion vessel engines assume a worst

- case value while at the drill site and within 25 nautical miles of the BlackHornet . Dies el units used to calculate emissions from the support vessel s are detailed in Anadarko’s OCS permit application materials and are included in the administrative record for this project as discussed in Section 9.0 of this document. 

## 4.0 Legal Authority and Regulatory Applicability

4.1 EPA Jurisdiction

The 1990 CAA Amendments transferred authority for implementation of the CAA for sources subject to the Outer Continental Shelf Lands Act (OCSLA) from the Department of the Interior (DOI) to the EPA for all area s of the OCS with the exception of the Gulf of Mexico west of 87.5° longitude. Subsequently, the Consolidated Appropriations Act, 2012 (P.L. 112

- 74), transferred authority from the EPA to DOI for areas offshore the North Slope of Alaska.

4.2 OCS Air Regul ations

Section 328(a)(1) of the CAA requires the EPA to establish requirements to control air pollution from OCS s ources under the EPA ’s jurisdiction in order to attain and maintain federal and state ambient air quality standards and to comply with the pr ovisions of part C (PSD) of title I of the CAA. The OCS Air Regulations at 40 CFR part 55 implement section 328 of the CAA and establish the air pollution control requirements for OCS sources and the procedures for implementation and enforcement of these r equirements. The regulations define “OCS source” by incorporating and interpreting the statutory definition of OCS source:

OCS source means any equipment, activity, or facility which:

(1) Emits or has the potential to emit any air pollutant; (2) Is regulated or authorized under the OCSLA ( see 43 U.S.C. §1331 et seq.); and (3) Is located on the OCS or in or on waters above the OCS.

This definition shall include vessels only when they are:

(1) Permanently or temporarily attached to the seabed and erected thereon and used for the purpose of exploring, developing or producing resources there from, within the meaning of section 4(a)(I) of the OCSLA ( see 43 U.S.C. §1331 et seq.); or8

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- R4020 (2) Physically attached to an OCS facility, in which case only the stationary source
aspec ts of the vessels will be regulated [ see 40 CFR § 55.2; see also CAA § 328(a)(4)(C) and 42 U.S.C. § 7627].

Section 328 and part 55 distinguish between OCS sources located within 25 nautical miles of a
state ’ s seaward boundary and those located beyond 25 n autical miles of a state’s seaward boundary [ see CAA § 328(a)(1); 40 CFR §§ 55.3(b) and (c)]. In this case, Anadarko is seeking a permit for exploratory drilling operations that will be conducted exclusively beyond 25 nautical miles of any state’s seaward boundary.

Sources located beyond 25 nautical miles of a state ’ s seaward boundaries are subject to the NSPS in 40 CFR part 60; the PSD pre

- construction program in 40 CFR § 52.21, if the OCS source is also a major stationary source or a major modification t o a major stationary source; standards promulgated under section 112 of the CAA, if rationally related to the attainment and maintenance of federal and state ambient air quality standards or the requirements of part C of title I of the CAA; and the title V operating permit program in 40 CFR part 71. See 40 CFR §§ 55.13(a), (c), (d)(2), (e), and (f)(2), respectively. The applicability of these requirements to Anadarko’s exploratory drilling program is discussed below.

The OCS regulations also contain provis ions related to monitoring, reporting, inspections, compliance, and enforcement. See 40 CFR §§ 55.8 and 55.9. Sections 55.8(a) and (b) provide that all monitoring, reporting, inspection, and compliance requirements of the CAA apply to OCS sources. These pr ovisions, along with the provisions of the applicable substantive programs listed above, provide authority for the monitoring, recordkeeping, reporting

, and other compliance assurance measures included in the draft permit.

4.3 Prevention of Significant Deterioration (PSD)

The PSD program, as set forth in 40 CFR § 52.21, is incorporated by reference into the OCS Air Regulations at 40 CFR § 55.13(d)(2), and is applicable to major OCS sources such as this proposed project. The PSD program requires an assess ment of air quality impacts from the proposed project and the utilization of BACT as determined on a case

- by

- case basis taking into account energy, environmental, and economic impacts, as well as 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 ton per year (TPY ) or more of a “regulated NSR pollutant” as defined in 40 CFR § 52.21(b)(50); is “subject to regulation” as defined in 40 CFR § 52.21(b)(49); and is one of a named list of source categories. Any stationary source is also considered a major stationary source if it emits or has a PTE of 250 TPY or more of a regulated NSR pollutant. See 40 CFR § 52.21(b)(l).

“Potential to emit” is defined as the maximum capac ity of a source to emit a pollutant under its physical and operational design. See 40 CFR § 52.21(b)(4). In the case of “potential emissions” from OCS sources, 40 CFR part 55 defines the term similarly and provides that:

Pursuant to section 328 of the Act , emissions from vessels servicing or associated with an OCS source shall be considered direct emissions from such a source while at the source,9

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- R4020 and while en route to or from the source when within 25 miles of the source, and shall be included in the “pote ntial to emit” for an OCS source. This definition does not alter or affect the use of this term for any other purposes under 40 CFR §§ 55.13 or 55.14 of this part, except that vessel emissions must be included in the “potential to emit” as used in 40 CFR § § 55.13 or 55.14 of this part. (40 CFR § 55.2)

Thus, emissions from vessels servicing or associated with an OCS source that are within 25 miles of the OCS source are considered in determining the PTE or “potential emissions” of the OCS source for purpose s of applying the PSD regulations. Emissions from such associated vessels are therefore counted in determining whether the OCS source is required to obtain a PSD permit, as well as in determining the pollutants for which BACT is required.

The drilling ves sels and support fleet vessels may contain emission sources that otherwise meet the definition of “nonroad engine” as defined in section 216(10) of the CAA. However, based on the specific requirements of CAA section 328, emissions from these otherwise nonr oad engines on subject vessels are considered as “potential emissions” from the OCS source. Similarly, all engines that are part of the OCS source are subject to the requirements of 40 CFR part 55, applicable to the OCS source, including control technology requirements.

Table 4

- 1 lists the PTE for each regulated NSR pollutant from the proposed project, as well as the significant emission rate for each regulated NSR pollutant. The permit application materials and Section 5.0 of this document contain information regarding t he emissions factors used to determine PTE for the project. Emissions from the support vessels servicing the BlackHornet were considered direct emissions while within 25 nautical miles of the drilling vessel and are included in the PTE.

The requirements o f the PSD program apply to this OCS source if the project PTE is at least 250 TPY for any regulated pollutant. Anadarko’s exploration drilling program is a major PSD source because emissions of NO X and CO exceed the major source applicability threshold of 250 TPY and, thus, is subject to PSD review for CO and NO X (both as a measured pollutant for NO 2 and ozone and as a precursor to ozone and PM 2.5 ). PSD review also applies to PM, PM 10 , PM 2.5 , and VOC (as a measured pollutant and precursor for ozone) , and GHGs because the source is a major source under the PSD regulations and because emissions of these pollutants exceed the respective significant emission rate thresholds. Section 6.0 of this document contains a discussion of the BACT analysis.10

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Table 4

- 1 Po tential to Emit for Regulated NSR Pollutants

Pollutant PTE (TPY) Significant Emission Rate (TPY) PSD Review Required CO 5 40 100 Yes NO x 1 1, 447 40 Yes VOC 2 171 40 Yes PM 58 25 Yes PM 10 56 15 Yes PM 2.5 56 10 Yes SO 2 3 1 40 No H 2 SO 4 0.03 7 No Pb 0.02 0.6 No GHGs 125,000 75,000 Yes

1 NO x is a measured pollutant for the criteria pollutants ozone and NO 2 and a precursor for ozone and PM 2.5

. 2 VOC is a measured pollutant and precursor for the criteria pollutant ozone.

3 SO 2 is a precursor for the criteria pollutant PM 2.5

.

4.4 Title V

The requirements of the title V operating permit program, as set forth in 40 CFR part 71, apply to major OCS sources located beyond 25 nautical miles of any state's seaward boundaries. See 40 CFR § 55.13(f)(2). Because the PTE for this project is greater than 100 TPY for NO X , CO

, and VOCs

, the project is considered a major source under title V and part 71.

The OCS permit application submitted by Anadarko seeks to obtain a title V operating permit in accordance with 40 CFR § 55.13(f)(2) and 40 CFR part 71 concurrently with the OCS preconstruction permit. Part 71 forms are included in Section 6 of Anadarko’s application received on September 5, 2013 . The dr aft permit includes conditions necessary to meet the requirements of the title V operating permit program. For example, the draft permit will include requirements for submittal of annual compliance certifications and annual fee payments ( based on actual em issions ), as well as monitoring, recordkeeping

, and reporting requirements.

4.5 New Source Performance Standards (NSPS)

An OCS source must comply with any NSPS applicable to their source category. See 40 CFR § 55.l3(c). In addition, per 40 CFR § 52.21(j)(1), the PSD regulations require that each major stationary source or major modification meet applicable NSPS. A specific NSPS subpart applies to a source based on source category, equipment capacity, and the date when the equipment commenced const ruction or modification. Potentially applicable NSPS are discussed below.

4.5.1 Subpart IIII

NSPS, 40 CFR part 60, subpart IIII applies to stationary compression

- ignition internal combustion engines that commence construction after July 11, 2005

, and were manufactured after April 1, 2006. Relevant equipment specifications for the BlackHornet and the stimulation vessel a re summarized below i n Table 4

- 2 and Table 4

- 3 , respectively . Engines installed on the drillship are subject to the emissions limitations and diesel fuel requirements of subpart IIII.

The life boats (LB

- 01 through LB

- 06) and the fast rescue boats (DR

- FR

- 01) are classified as11

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- R4020 vessels. Therefore, only stationary source aspects are regulated. As they are used for man overboard and emergency es cape scenarios, these units do not have any stationary source aspects and are not subject to subpart IIII.

The BlackHornet will have third party engines onboard

, and the third party stimulation vessel will be equipped with eight pump engines all of which could be subject to subpart IIII. Anadarko used representative worst

- case engines for all unknown engines, and therefore could substitute engines with equal or lesser emissions. Anadarko will use new engines where available, and has identified which third party engines could be subject to this subpart. Since Anadarko used representative eng ines for all unknown engines, t hey must notify the EPA prior to use of any new, modified, or reconstructed engine intended to be used or in replacement of any engines ide ntified in Table s 4

- 2 and 4

- 3 , and shall submit to the EPA a reevaluation of the applicability of pertinent NESHAP and NSPS regulations, as well as copies of the manufacturer engine certification to the EPA standards. The engines that Anadarko identified in their September 2013 application as third part y engines (DR

- TP

- 01 through DR

- TP

- 11 and DR

- TP17 through DR

- TP

21) are EPA Tier 2 certified and are subject to subpart IIII. If the substitute engines are subject to thi s subpart, Anadarko will comply with all applicable requirements. Anadarko will need to provide the EPA certification indicating that any engines selected meet subpart IIII emissions standards.

The main diesel engines were constructed after the applicabil ity date of July 11, 2005. Therefore

, these engines are subject to the emissions limitations and diesel fuel requirements of subpart IIII. This requires compliance with 40 CFR § 94.8 standards for the eight main e ngines ( DR

- ME

- 01 through DR

- ME

- 08 )

, which h ave a displacement greater than 10 liters per cycle. A NO X emission limit of 9.69 g/kW

- hr and a PM emission limit of 0.15 g/kW

- hr are the limits for each 720 rpm engine required under this subpart . These engines are International Maritime Organization (IMO ) Tier II certified engines. To demonstrate compliance with th e requirement s in subpart IIII , Anadarko provide d the IMO certification indicating that these engines meet 40 CFR 94.8 emissions standards . The emission standards and requirements in 40 CFR 94.8 correspond to the IMO standards for engines of this size

. These standards are applicable when the engines are operating at maximum load. Anadarko will run the engines at the highest achievable load and conduct a stack test to demonstrate compliance.

The emergency air compressor engine (DR

- AC

- 01) is a post

- 2007 engine and is classified as a nonroad engine subject to emission standards locate d in 40 CFR part 1039 Table 2 , the exhaust opacity limits in 40 CFR 1039.105(b) , and the sulfur fuel standard in 40 C FR 80.510(b). To demonstrate compliance

, Anadarko provide d the EPA Tier 3 certification indicating that this engine meets subpart 1039 emission standards in the supplemental material submitted on November 23, 2013

, and found in the Administrative Record

, and Anadarko will certify the sulfur fuel content used.

B ased on specific engine size, model date, and displacement , 40 CFR part 60 subpart IIII requires the emergency generator (DR

- GE

- 01) to comply with Tier 2 emissions standards for new marine engines a s set forth in 40 CFR § 94.8. Compliance with the NSPS specifically requires that this engine be certified to the EPA Tier 2 standards. Since the BlackHornet is not a U.S. flagged vessel, it was constructed to different standards. The emergency generator i s IMO12

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- R4020 Tier II certified. The requirements for an engine the size of the emergency generator in 40 CFR § 94.8 do not incorporate the IMO standard. Since certification is an engine manufacturer process, it is not possible for this engine to obtain an EPA Tier certificate, even with emissions levels that meet the EPA certification requirements. See 40 CFR § 60.4211(c). Hence, compliance with the NSPS would require Anadarko to replace this engine with an engine that has been certified to EPA rather than IMO emission standards

. Anadarko is requesting exemptions from subpart IIII for the emergency generator engine . Pursuant to 40 CFR § 55.7 , the EPA may grant an exemption from a part 55 requirement, if the Administrator or the delegated agency finds that compliance is technically infeasible or will cause an unreasonable threat to health and safety.

The existing emergency generator was sized to meet the drillship’s stringent space and weight distribution requirements in the vessel’s design phase. Based on consultations with the engine manufacturer and the drillship owner, Anadarko has determined that any replacement engine would have to meet exacting output, weight, physical size, and shape restrictions dictated by the vessel’s design constraints. Anadarko was not able to locate replacement engines for this vessel that would meet all the necessary criteria and fit the design footprint of the original engines as summarized in email communicat ions to the EPA dated November 26 , 2013

, and included in t he administrative record. Furthermore, if a suitable replacement engine could be found, repla cing this engine would likely require a redesign of the engine bed frame and vessel structural modifications that would subsequently require recertification of the vessel. Based on these

source

- specific technical barriers, the EPA concludes that replacement of the DR

- GE

- 0 1 unit for this operating scenario and this project is not technically feasible at this time. Thus, the EPA proposes to grant Anadarko’s request fo r an exemption from subpart IIII

. Any exemption under §55.7 would necessitate compliance with substitute emissions and/or work practice requirements based on the next most stringent standard available. The EPA determined that the next most stringent sta nd ards for the DR

- GE

- 01 unit is IMO certification standards for a comparable engine . Detailed information regarding IMO certification standards from the Regulations for the Prevention of Air Pollution from Ships (Annex VI) document can be found at the IMO’s website, www.imo.org

. An exemption under §55.7 also requires an estimate of residual emissions derived from the difference between the estimated reductions that would be achieved by co mpliance with the original requirement and the estimated emission reductions that would be achieved by compliance with the proposed substitute requirements. In accordance with 40 CFR § 55.7(e)(3), Anadarko must then obtain emission reductions of a sufficie nt quantity to offset the estimated resid ual emissions. Anadarko calculated the differences in emissions that would be achieved by compliance with the original emission standards for each engine versus the estimated emissions from the substitute requiremen ts as provided in the supplemental information submitted on November 11 , 2013

. As discussed above, the emergency generator engine (DR

- GE

- 01) is a Category 2, commercial marine engine subject to emission standards located in 40 CFR part 94.8 Table A

- 1. T he total residual emissions for the emergency generator are approximately 1.87 tons of NO X and non

- methane hydrocarbons (NMHC) c ombined (the calculated difference submitted by Anadarko only included NO X emissions) , and approximately 0.047 tons of particulate matter. Potential emissions of CO for the emergency generator are below the Tier 2 standards.13

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- R4020 Since this OCS source will be located beyond 25 miles from any States ’ seaward boundary, the EPA is authorized to determine an adequate emission offset ratio to b e protective of State and Federal ambient air quality standards and to comply with part C of title I of the CAA. See 40 CFR 55.7(e)(3). With respect to this specific project, the residual emissions are so low as to be essentially equivalent to the original emissions standards. As such, the EPA has determined that, based on currently available data, no emissions offsets will be required at this time. Taking into account the quality of the emissions factors currently available to estimate the substitute emiss ions and the uncertainty inherent in these estimates, this determination will be revisited by the EPA upon review of project specific operating data from the BlackHornet that is required by the draft permit. At that time, if the EPA determines that emissions reductions are appropriate, Anadarko will work with the EPA to identify suitable offsets to satisfy this requirement.

Anadarko must comply with all other applicable requirements of subpart IIII for engines DR

ME

- 01 through DR

- ME

- 08

, DR

- AC

- 01, and DR

- GE

- 01, and third party engines (DR

- TP

- 01 through DR

- TP

- 11 and DR

- TP

- 17 through DR

- TP

- 21) including recordkeeping, reporting, and the diesel fuel requirements of 40 CFR § 60.4207. Compliance with these permit requirements and the substitute control requ irements will also meet the applicant’s obligations for these engines under 40 CFR § 63 subpart ZZZZ, as discussed below in Section 4.6.

Table 4

- 2 BlackHornet Engine Specifications

Emissions Unit ID Description Make & Model Rating 1 (hp) Manufacture Year DR

- M E

- 01 Main propulsion generator #1 Hyundai

- HiMsen 6,035 hp 2012
DR

- M E

- 02 Main propulsion generator #2 Hyundai

- HiMsen 6,035 hp 2012
DR

- M E

- 03 Main propulsion generator #3 Hyundai

- HiMsen 6,035 hp 2012
DR

- M E

- 04 Main propulsion generator #4 Hyundai

- HiMsen 6,035 hp 2012
DR

- M E

- 05 Main propulsion generator #5 Hyundai

- HiMsen 6,035 hp 2012
DR

- M E

- 06 Main propulsion generator #6 Hyundai

- HiMsen 6,035 hp 2012
DR

- M E

- 07 Main propulsion generator #7 Hyundai

- HiMsen 12,069 hp 2012
DR

- M E

- 08 Main propulsion generator #8 Hyundai

- HiMsen 12,069 hp 2012
DR

- GE

- 01 Emergency Generator Cummins QSK60DMGE 2,547 hp 4/2011
DR

- LB

- 01 Life boat e ngine #1 Siyang N 485

- J 41 hp
DR

- LB

- 02 Life boat e ngine #2 Siyang N 485

- J 41 hp
DR

- LB

- 03 Life boat e ngine #3 Siyang N 485

- J 41 hp
DR

- LB

- 04 Life boat e ngine #4 Siyang N 485

- J 41 hp
DR

- LB

- 05 Life boat e ngine #5 Siyang N 485

- J 41 hp
DR

- LB

- 06 Life boat engine #6 Siyang N 485

- J 41 hp
DR

- AC

- 01 Emergency air compressor Hatz 2M41 39 hp 9/2011
DR

- FR

- 01 Fast rescue craft engine Sab b

- L4 Turbo 55 hp Third Party Engines DR

- TP

- 01 Third party engine #1 Various

- Tier II Certified ≤860 hp Varies
DR

- TP

- 02 Third party engine #2 Various

- Tier II Certified ≤860 hp Varies
DR

- TP

- 03 Third party engine #3 Various

- Tier II Certified ≤ 300 hp Varies
DR

- TP

- 04 Third party engine #4 Various

- Tier II Certified ≤ 300 hp Varies
DR

- TP

- 05 Third party engine #5 Various

- Tier II Certified ≤ 300 hp Varies
DR

- TP

- 06 Third party engine #6 Various

- Tier II Certified ≤ 300 hp Varies14

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- R4020 DR

- TP

- 07 Third party engine #7 Various

- Tier II Certified ≤ 300 hp Varies
DR

- TP

- 08 Third party engine #8 Various

- Tier II Certified ≤ 300 hp Varies
DR

- TP

- 09 Third party engine #9 Various

- Tier II Certified ≤ 300 hp Varies
DR

- TP

- 10 Third party engine #10 Various

- Tier II Certified ≤ 300 hp Varies
DR

- TP

- 11 Third party engine #11 Various

- Tier II Certified ≤ 300 hp Varies
DR

- TP

- 12 Third party well evaluation

engine #1 Detroit Diesel ≤ 140 hp Varies

DR

- TP

- 13 Third party well evaluation

engine #2 Detroit Diesel ≤ 140 hp Varies

DR

- TP

- 14 Third party well evaluation

engine #3 Detroit Diesel ≤ 140 hp Varies

DR

- TP

- 15 Third party well evaluation

engine #4 Detroit Diesel ≤ 140 hp Varies

DR

- TP

- 16 Third party well evaluation

engine #5 Detroit Diesel ≤ 140 hp Varies

DR

- TP

- 17 Third party engine #12 Various

- Tier II Certified ≤ 126 hp Varies
DR

- TP

- 18 Third party engine #13 Various

- Tier II Certified ≤ 126 hp Varies
DR

- TP

- 19 Third party engine #14 Various

- Tier II Certified ≤ 126 hp Varies
DR

- TP

- 20 Third party engine #15 Various

- Tier II Certified ≤ 126 hp Varies
DR

- TP

- 21 Third party engine #16 Various

- Tier II Certified ≤ 126 hp Varies

1 Permit conditions may limit operation to less than rated capacity.

Table 4

- 3 Stimulation Vessel Engine Specifications

Emissions Unit ID Description Make & Model Rating 1 (hp) Manufacture Year SV

- PE

- 01 Stimulation Vessel Pump #1 Various 2,250 hp Varies
SV

- PE

- 02 Stimulation Vessel Pump #2 Various 2,250 hp Varies
SV

- PE

- 03 Stimulation Vessel Pump #3 Various 2,250 hp Varies
SV

- PE

- 04 Stimulation Vessel Pump #4 Various 2,250 hp Varies
SV

- PE

- 05 Stimulation Vessel Pump #5 Various 2,250 hp Varies
SV

- PE

- 06 Stimulation Vessel Pump #6 Various 2,250 hp Varies
SV

- PE

- 07 Stimulation Vessel Pump #7 Various 2,250 hp Varies
SV

- PE

- 08 Stimulation Vessel Pump #8 Various 2,250 hp Varies

1 Permit conditions may limit operation to less than rated capacity.

4.5.2 Subpart K

NSPS, 40 CFR part 60, subpart K, applies to petroleum liquids tanks with a capacity of greater than 40,000 gallons that commence construction or modification after March 8, 19 74, and prior to May 19, 1978, or have a capacity greater than 65,000 gallons and commence construction or modification after June 11, 1973, and prior to May 19, 1978. All storage tanks on the drilling vessel were constructed after 1978; therefore, they are not subject to subpart K

.15

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- R4020 4.5.3 Subpart Ka

NSPS, 40 CFR part 60, subpart Ka, applies to petroleum liquids tanks with a capacity of greater than 40,000 gallons that are used to store petroleum liquids and for which construc tion is commenced after May 18, 1978, and prior to July 23, 1984. All storage tanks on the drilling vessel were constructed after 1984; therefore, they are not subject to subpart Ka.

4.5.4 Subpart Kb

NSPS 40 CFR part 60 subpart Kb applies to each storage v essel with a capacity greater than or equal to 75 cubic meters (m 3 ) that is used to store volatile organic liquids for which construction, reconstruction, or modification is commenced after July 23, 1984. This subpart does not apply to storage vessels with a capacity greater than or equal to 151 m 3 storing a liquid with a maximum true vapor pressure (TVP) less than 3.5 kilopascals (kPa) or with a capacity greater than or equal to 75 m 3 but less than 151 m 3 storing a liquid with a maximum true vapor pressure less than 15.0 kPa. As indicated in the application materials

, all storage tanks were constructed after 1984. However, none of the fuel tanks included in the permit application are subject to subpart Kb because each tank has a capacity less than 75 m 3 or t he liquid contained in them has a vapor pressure less than 3.5 kPa. This subpart also does not apply to condensate storage tanks that have a volume less than 1,589.874 m 3 , if condensate is stored prior to custody transfer. None of the condensate storage t anks included in the permit application are subject to subpart Kb because each tank has a capacity less than 1,589.874 m 3 and the condensate will be stored prior to custody transfer . These parameters exempt the storage tanks from this subpart

.
4.5.5 Subpart Dc

NSPS, 40 CFR part 60, subpart Dc, applies to owners and operators of steam generating units for which construction, modification, or reconstruction commenced after June 9, 1989, and that have a maximum heat input design capacity of 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/hr)) or less but greater than or equal to 2.9 MW (10 MMBtu/hr). The proposed flowback b oiler will be a n 8 M MBtu/hr “SIGMA FIRED” SF

- 200SE flowback b oiler, or equivalent, and is therefore not subject t o subpart Dc.

4.6 National Emission Standards for Hazardous Air Pollutants (NESHAP)

Applicable NESHAP promulgated under section 112 of the CAA apply to OCS sources if rationally related to the attainment and maintenance of federal and state ambient air qua lity standards or the requirements of part C of title I of the CAA. See 40 CFR § 55.13(e).

NESHAP regulations set forth in 40 CFR part 63 apply to a source based on its source category listing. Many part 63 NESHAPs apply only if the affected source is a “major source” as defined in Section 112 and 40 CFR § 63.2. A “ major source ” is generally defined as a source that has a PTE of 10 tons per year or more of any single hazardous air pollutant (HAP) or 25 tons per year or more of all HAP combined. See sectio n 112(a)(1) and 40 CFR § 63.2. An area source is any source that is not a major source as defined in section 112(a)(2) and 40 CFR § 63.2. Anadarko has estimated emissions of less than 25 TPY for all HAP combined and less than 10 TPY for each individual HAP . This makes the project an area source of HAPs.16

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- R4020 4.6.1 Subpart ZZZZ

NESHAP, 40 CFR part 63, subpart ZZZZ, applies to stationary reciprocating internal combustion engines (RICE) located at major and area sources of HAP emissions. The regulations establish different standards for new and existing sources pursuant to CAA section 112. Area source engines rated above 500 hp that are constructed after December 19, 2002

, and engines with a rating of 500 hp or less that are constructed after June 12, 2006

, are con sidered “new” reciprocating internal combustion engines (RICE).

The drillship emergency air compressor (DR

- AC

- 01) has a horsepower rating of 39 hp and was constructed after the June 12, 2006 applicability date. The drillship main engines (DR

- ME

- 01 through DR

- ME

- 08) and the drillship emergency generator (DR

- GE

- 01) installed on the BlackHornet drillship were also constructed after June 12, 2006. In addition, the third party engines (DR

- TP

- 01 through DR

- TP

- 11 and DR

- TP

- 17 through DR

- TP

- 21) will be EPA Tier 2 certified and compliant with 40 CFR subpart IIII. Therefore, 40 CFR 63 subpart ZZZZ requires that these engines comply with the requirements of 40 CFR 60 subpart IIII as discussed above in Section 4.5.1 . No further requirements under subpart ZZZZ ap ply to these engines.

The third part y well evaluation engi nes a nd the stimulation v essel p ump engines are existing

non

- emergency engines that were not constructed after the applicability dates, and must comply with the management practices as defined in 40 CFR § 63.6603

. These management practices for the stimulation vessel pump engines are found in 40 CFR § 63.6603(c) and include:

 Change oil every 1,000 hours of operation or annually, whichever comes first. Or, utilize an oil analysis program as prescribed in 40 CFR § 63.6625(i) in order to extend the specified oil change requirement;

 Inspect and clean air filters every 750 hours of operation or annually, whichever comes first, and replace as needed;

 Inspect fuel filters and belts, if installed, e very 750 hours of operation or annually, whichever comes first, and replace as needed; and

 Inspect all flexible hoses every 1,000 hours of operation or annually, whichever comes first, and replace as needed.

The management practices for the third party we ll evaluation engines are in Table 2d to this subpart and include :

 Change oil and filter every 1,000 hours of operation or annually, whichever comes first. Or, utilize an oil analysis program as prescribed in 40 CFR § 63.6625(i) in order to extend the specified oil change requirement;

 Inspect air cleaner every 1,000 hours of operation or annually, whichever comes first, and replace as necessary; and

 Inspect all hoses and belts every 500 hours of operation or annually, whichever comes first, and replace as necessary

.

 During periods of startup

, minimize the engine ’ s time spent at idle and minimize the engine ’ s startup time at startup to a period needed for app ropriate and safe loading of the engine, not to exceed 30 minutes, after which time the non

- startup emission limitations apply.17

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- R4020 Additionally, pursuant to 40 CFR § 63.6655 and 40 CFR § 63.6660 , records of the above management practices must be maintained i n readily

- accessible, hard, or electronic form for at least five years following the date of each maintenance activity.

Emissions from the escape capsule engines and the fast rescue craft on the BlackHornet were included in th e OCS source’s PTE and emissions modeling, as required by 40 CFR part 55. These vessels are also subject to operating limits, and to monitoring, recordkeeping

, and reporting requirements to ensure they will not exceed the potential emissions assumed in the application and i mpact review. However, these units do not have any stationary source aspects, as they are used for man

- overboard and emergency escape scenarios

, and are therefore not subject to subpart ZZZZ standards.

4.6.2 Subpart HHHHHH

NESHAP, 40 CFR part 63, subpart HHHHHH, applies to paint stripping and miscellaneous surface coating operations performed at area sources of HAP emissions. This project is considered an area source, as explained above. The spray painting operation performed on the drillship is part of t he routine maintenance to protect the vessel from the marine environment. This activity meets the definition of “facility maintenance” provided in 40 CFR 63.11180 and, therefore, the spray painting operations on the drillship are not subject to subpart HHH HHH pursuant to 40 CFR 63.11170.

4.6.3 Subpart XXXXXX

NESHAP, 40 CFR part 63, subpart XXXXXX, applies to HAPs emitted from miscellaneous metal fabrication and finishing operations performed at area sources of HAP emissions. This project is considered an area source, as explained above. The welding operation performed on the drillship is part of the routine maintenance. This activity meets the definition of “facility maintenance” provided in 40 CFR 63.11522 and, therefore, the proposed welding operations o n the drillship are not subject to subpart XXXXXX pursuant to 40 CFR 63.11514

. 

## 5.0 Project Emissions

This section describes the emission calculation basis for each emission source. The total projected emissions are based on estimations of the worst

- case to tal fuel consumption for the drillship, support vessels, and well evaluation vessels . The emission factors are based on stack
test s , AP

- 42, EPA publications, IMO and EPA nonroad engine emission tier limits, analysis of fuel sulfur content, vendor

- supplied emissions factors, fuel mass balance, NSPS, BOEM guidance document, EPA’s TANKS 4.09d program, and material safety and data sheets.

At the time of the application

, Anadarko did not know the exact specifications for equipment leased from third party vendors. Therefore, Anadarko used the worst

- case emission units for each category of air pollutant sources when calculating the PTE. These worst

- case, or

“ equivalent, ” units will have equal or lower mass emissions to what was estimated for each criteria, toxic, and other regulated air pollutants on a short

- term and long

- term basis. The units that Anadarko identified with this description inc lude: third party engines (DR

- TP

- 01 through18

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- R4020 DR

- TP

- 21), supply boats, stimulation vessel, w ell evaluation vessel, tug boat, barge , and other miscellaneous sources (painting, welding, etc.).

During the drilling, well completion, and maintenance phases

, var ious operating scenarios can

occur , including but not limited to

, the following :

 Worst

- case gas well flowback ;

 Worst

- case oil well flowback ;

 Worst

- case stimulation vessel operations ;

 Well completion third party equipment ;

 Well evaluation vessel operations ; and

 Worst

- case drilling

. The emissions of any one scenario or combination of scenarios at a given time will not exceed the worst

- case emissions calculated. Anadarko calculated the PTE for each of the scenarios listed above. The emission calculations det ermined that the highest PTE will result during the worst

case oil well flowback scenario for all pollutants except for NO x , which will have the highest PTE during the well evaluation vessel operations

. The discussion that follows is based on the
worst

- cas e scenario, and d etailed calculations for the alternative scenarios are provided in Appendix B of the September 2013 application and in the supplemental information submitted in August 2014

. These documents are located in the administrative record as referenced in Section 9 of this documen t.

Anadarko has proposed to only use ultra

- low sulfur diesel fuel for all diesel emission units and ancillary vessels . The sulfur content of ultra

- low sulfur diesel fuel is defined as a maximum sulfur content of 15 p arts per million (ppm). Sulfur dioxide (SO 2 ) and sulfuric acid ( H 2 SO 4 ) emissions were calculated by a mass balance method. Based on a draft EPA document, EPA 420

- R

- 03

- 008 titled “Draft Regulatory Impact Analysis: Control of Emissions from Nonroad Diesel Engines” dated April 2003 , Anadarko used a 98% conversion factor for SO 2 formation during diesel fuel combustion, with the other 2% of the sulfur assumed to be converted to sulfuric acid ( H 2 SO 4 ). The H 2 SO 4 emissions were assumed to condense to form total r educed sulfur (TRS) particulate matter, primarily as sulfates in the atmosphere. Since the total amount of H 2 SO 4 was calculated at 1.02 TPY, the potential TRS PM contribution is minimal

.
5.1 BlackHornet Main Propulsion Electric Generator Engines (DR

- ME

- 01 through DR

ME

- 08 ) and Emergency Generator (DR

- GE

- 07) Analysis

Eight main engines provide po wer to the drilling vessel: six Hyundai

- HiSen 9H32/4 0 diesel generators with a rated powe r output of approximately 6,035 hp each and two Hyundai

- HiSen 18H32/40V diesel generators with a rated pow er output of approximately 12,069 hp each.

The Cummins QSK60

- DM HPI emergency generator diesel engine, rated 2,547 hp, provides emergency power to the drilling vessel and is run periodically to ensure the engine will ope rate properly in the event of an emergency.

Anadarko proposed a drillship

- wide fuel limit derived from the main engine fuel based emission19

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- R4020 factors. Emissions estimates for the BlackHornet ’s main engines and emergency generator were based on an average fuel consumption of 112 cubic meters/day

. This fuel limit is the highest fuel limit of all six scenarios. This results in an annual fuel limit of 18,438 cubic meters/year

, which is equal to approximately 200 days per year of 24 hour per day operation and a power requirement of 86,400,00 kW

. This will limit the maximum total emissions from the drillship.

5.2 BlackHornet Small Engine s, Third Party Engines, and Miscellaneous Emission Sources Analysis

The following is a description of the addit ional emission units and the basis of the worst

- case usage estimates for each engine :

Unit ID: Emergency Air Compressor Diese l Engine (DR

- AC

- 01 )

For t he HATZ 2M41 air compress or rated at 39 hp

, calculations are based the hourly and annual emissions operating a t 100% load for a maximum of 100 hours per year per engine.

Unit ID: Life Boat Diesel Engines (DR

- LB

- 01 through DR

- LB

- 06)

The six SIYANG 485

- J life boat engines rated at 41 hp are operated during maintenance and safety checks and i n the event of an emergency. Non

- emergenc y, planned operation time of a maximum of 1 hour per day for each engine was used for the emission calculations. The maximum annual emissions were calculated based on operating for a maximum of 100 hours per year per engi ne.

Unit ID: Fast Rescue Craft (DR

- FR

- 01)

The SABB

- L4 engine rated at 55 hp in the fast rescue boat is operated during maintenance checks, safety checks

, and in the event of an emergency. N on

- emergency, planned operation time of 1 hour per day was used for the emission calculations. The hourly and annual emissions were calculated based on operating 100 hours year per.

Unit ID: Third Party Engines (DR

- TP

- 01 through DR

- TP

- 1 1 and DR

- TP

- 17 through DR

TP

- 21 )

These units are portable and brought on the drillship as needed by a third party supplier. The exact engines available for use during the project had not been identified at the time of the application submittal. The worst

- case engine s listed below were chosen to calculate emissions and the potential to emit

, since they represent engines that have both the most recent available technology, but are also the largest engines that will perform the required function

. Any replacement engines for the project will meet the equivalent or a higher EPA Tier stan dard. These engin es will be EPA Tier 2 certified, and t he engines were grouped in the following categories:

 Third Party Engines ≤ 860 hp (DR

- TP

- 01 and DR

- TP

- 02)

 Third Party Engines ≤ 300 hp (DR

- TP

- 03 through DR

- TP

- 11)

 Third Party Engines ≤ 126 hp (DR

- TP

- 17 and DR

- TP

- 21)20

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- R4020 The estimated annual emissions used 4,800 hours per year of operation per engine.

Unit ID: Third Party Well Evaluation Engines (DR

- TP

- 12 through DR

- TP

- 16)

These units are portable and brought on the drillship as needed by a third party supplier. The exact engines available for use during the project had not been identified at the time of the application submittal. These units may be used on the drillship or the supply boat. These engines will be rated less than or equal to 140 hp and each engine will operate a maximum of 125 hours
per year.

Unit ID: Tanks (DR

- FT

- 01 through DR

- FT

- 19 )

Emissions are generated from the storage of diesel fuel (17 tanks) and helicopter fuel in tanks (2 tanks) . The EPA TANKS 4.09d computer software program was used to calculate VOC emissions, using the properties of distillate fuel oil number 2 for diesel and Jet Napthha (JP

- 4)

. The average fuel usa ge for the drillship is 112 cubic meters /day; however, a throughput more than twice as large was used as a conservative assumption

.

Unit ID: Condensate Tanks (DR

- TP

- 24 through DR

- TP

- 26 )

The condensate stabilization process reduces the vapor pressure of the condensate liquids. This process separates the very light hydrocarbon gases from the heavier hydrocarbon components. Vapors produced from condensate stabilization are flared through the boom flare and these flash emissions are negligible. The stabilized condensate moves to th e condensate storage tanks, and this fuel generates emissions. The EPA TANKS 4.09d computer software program was used to calculate VOC emissions, using the default TANKS properties for Gasoline RVP 13. Maximum hourly emissions were calculated for the month of June

, which is the month with the historic highest emissions , and a throughput equal to twice the fuel usage was used as a conservative

measure.

Unit ID: Mud Degasser s (DR

- VG

- 01 through DR

- VG

- 0 4 )

The BlackHornet has four mud degassers onboard. Two of the degassers are equipped with Burgess Magna

- V ac vacuum degassers and two are equipped with Hampco degassers that are vertical separators that contain baffles. Drilling mud cools and lubricates the drill bit during t he drilling process. When the drilling mud resurfaces it could contain hydrocarbons. Once the mud reaches the surface

, it will off gas generating VOC emissions. The emission factor was based on a study commissioned by the BOEM, Year 2005 Gulfwide Emission Inventory Study, to develop a weighted average. The maximum hourly emissions per day are based on the expected ratio of annual throughputs of synthetic based m uds and the BOEM study . Annual emissions were estimated using pounds per day emissions factors an d 4,800 hours of operation per year.

Unit ID: Dus t Collectors (DR

- DC

- 01 through D R

- DC

- 04 )

Dry mud and cement are mixed with water to be used in drilling operations. Particulate matter in21

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- R4020 the form of dust is generated and controlled by using a dust colle ctor. The drillship will have three National Oilwell Varco dust collectors and one Vortex Ventures dust collector . The PM/PM 10 /PM 2.5 maximum hourly emission rate was calculated using a 0.00099 lbs/ton emission factor . The annual emission s were calculated based on 4,800 hours of operation

. Unit ID: Welding Operations (DR

- WO

- 01)

Welding occurs on the BlackHornet as part of maintenance activities and generates PM/PM 10 /PM 2.5 and HAP emissions. Emissions were calculated using 8 0 pounds per day of welding rods for 4,800 hours per year and 200 days per year.

Unit ID: Painting Operations (DR

- PO

- 01)

Painting occurs on the BlackHornet as part of maintenance activities , and generates PM/PM 10 /PM 2.5 , VOC, and HAP emissions. Anadarko will use a combination of air assisted and airless spray guns for different proposed painting operations. The calculations used an air assisted spray gun with 30% transfer efficiency. However, Anadarko may use an airless spray gun with a 50% transfer efficiency during operations. Anadarko will use both paint and thinner. The emission calculations used 5,200 and 1,300 gallons of p aints and thinner

. The particulate matter emissions were calculated by multiplying by a fall

- ou t factor. This fall

- out factor assumes that the majority of emissions will settle, and only a portion of the emissions will become airborne particulate matter.

Unit ID: Fugitive Emissions from Diesel Fuel Lines (DR

- FE

- 01)

F ugitive emissions are emitted f rom the diesel fuel lines. The component count is based on the number of diesel fuel valves, which was estimated from Table 2

- 4 of the EPA Protocol for Equipment Leak Emission Estimates. The connector count is a factor of the valve count, for a total of 48 4 connectors , 152 valves, and 16 pump seals

.
Unit ID: Flowback Boiler (DR

- TP

- 22)

The SIGMA FIRED SF

- 200SE, 8 MMBtu/hr flowback boiler will operate a maximum of 1

, 152 MMBtu/year based on 144 hours of annual operation during well completion activit ies

.
UNIT ID: Boom Flare (DR

- TP

- 23)

During well completion activitie s Anadarko may use a gas fired boom f lare capable of processing 60 MMScf/day or 360 MMScf/year . The applicant estimated a typical VOC reduction efficiency of 98%. The Boom Flare will generate emissions of PM/PM 10 /PM 2 .5 , CO, VOC, NO x , SO 2 , and GHGs.

5.3 Support Vessel Analysis

Various vessels that service the drilling vessel will generate emissions. These support vessels will transport personnel and supplies as r equired. The availability of specific support vessels22

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- R4020 during drilling operations was not known at the time of the application as outside vendors supply these units. The modeling calculations, described in Section 7.0, used one support vessel to estimate em issions , as described in the supplemental material submitted on February 7, 2014

. The permit limits the fuel use of all support vessels to 200 barrels per day (bbl/day) and 40,000 barrels per year ( bbl/year ) , to ensure that the emissions from all support v essels will not exceed those modeled. However, t he descriptions below list the estimated fuel and hourly consumptions used to derive the PTE , and these PTE numbers are not reflected in the permit

.

5.4 Supply Boat Analysis

Anadarko selected the largest expected supply boat ( HOS Coral ) as a worst

- case basis for emissions calculations. The emissions the supply boat will ge nerate within a 25 nautical mile radius of the BlackHornet are based on a fuel operating limit. Anadarko calculated their hourly usage t o determine that the supply boat will consume 200 bbl/day or 40,000 bbl/year of diesel fuel.

5. 5 Tug Boat Analysis

Various tug boats used during well completion activities will generate emissions. The availability of specific tug boats during well comple tion operations was not known at the time of the application as outside vendors supply these units.

Anadarko selected the largest expected tug boat as a worst

- case basis for emissions calculations. The emissions that the oper ation of the tug boat will generate within a 25 nautical mile radius of the BlackHornet are based on a fuel operating limit. Anadarko calculated their hourly usage to determine that the tug boat will consume 125 bbl/day or 25,000 bbl/year of diesel fuel.

5. 6 Barge Analysis

V arious barges used during well completion activities will generate emissions. The availability of specific barges during well completion operations was not known at the time of the application as outside vendors supply these units.

Anadarko selected the largest expected barge as a worst

- case basis for emissions calculations. The emissions that the op eration of the barge will generate within a 25 nautical mile radius of the BlackHornet ar e based on t he hourly operation of three electric generator engines r ated at 456 hp (BG

- LP

- 01 through BG

- LG

- 03). These engines will operate 4,800 hours per year per engine.

5. 7 Stimulation Vessel Analysis

Various stimulation vessels used during well completion activities will generate emissions. The availability of speci fic stimulation vessels during well completion operations was not known at the time of the application as outside vendors supply these units.

Anadarko selected the largest expected stimulation vessel as a worst

- case basis for emissions calculations. The emissions that the oper ation of the stimulation vessel will generate within a 2523

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- R4020 nautical mile radius of the BlackHornet are based on a fuel operating limit. Anadarko calculated their hourly usage to determine that the stimulation vessel will consume 225 bbl/day or 4,725 bbl/year of diesel fuel.

5. 8 Well Evaluation Vessel Analysis

Well evaluation vessels used during well completion activities will generate emissions. The availability of specific well evaluation vessels during well completion operations was not known at the time of the application as outside vendors supply these units.

Anadarko selected the largest expected well evaluation vessel as a worst

- case basis for emissions calculations. The emissions that the o per ation of the well evaluation vessel will generate within a 25 nautical mile radius of the BlackHornet are based on a fuel operating limit. Anadarko calculated their hourly usage to determine that the tug boat will consume 144 bbl/day or 28,800 bbl/year of diesel fuel.

Detailed emission factors for these sources are available in the application materials, which are included in the administrative record referenced i n Section 9.0 of this document.

5. 9 Compliance Methodology

Anadarko proposed a parametric emissions monitoring sy stem (PEMS) in their September 2

, 2014 submittal for the main diesel engines . This PEMS can monitor NO x , CO, and O 2 in ppm. CO 2 emissions will be calculated from measured O 2 to comply with the GHG BACT limit. This system m easures emissions in ppm which Anadarko will convert to g/KW

- hr or lb/hr to demonstrate compliance with the respective BACT limits using the engine power output and flow rate. The proposed PEMS record s the electric kilowatt power output and Anadarko will

c onvert it to mechanical kilowatts. The system does not measure flow rate; therefore, Anadarko will conduct stack tests to measure the flow rate and then graph the engine flow rate vs. engine load. The PEMS will also monitor NO x , CO, and O 2 once an hour and Anadarko will perform weekly calibrations. The PEMS cannot monitor VOC and particulate matter emi ssions. Anadarko will conduct a stack test and monitor the engine load in order to determine ongoing compliance with VOC and PM emissions

. The compliance demonstration method for the emergency generator diesel units (DR

- GE

- 01 ), the emergency air compressor engine (DR

- AC

- 01), the life boat engines (DR

- LB

- 01 through DR

LB

- 06), the fast rescue craft (DR

- FR

- 01), the simulation vessel pump engines (SV

- PE

- 01 through SV

- PE

- 08), the third party diesel engines ( DR

- TP

- 01 through DR

- TP

- 21 ) , and the flowback boiler (DR

- TP

- 22) will include monitoring and maintaining a contemporaneous record of the hours of engine operation using an engine hour meter or log of operating hours . These units must also meet any applicable NSPS and NESHAP monitoring requirements

.

The non

- combustion units, the dust collectors (DR

- DC

- 01 through DR

- DC

- 04), the boom flare (DR

- TP

- 23), painting operations (DR

- PO

- 01), and welding opera tions (DR

- WO

- 01), will24

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- R4020 demonstrate compliance through such methods as proper maintenance

, the amount and type of relevant material consumed , and or recording the amount of time the equipment is used,

. Compliance demonstration for the support vessels as s pecified in the draft permit shall include monitoring and maintaining a contemporaneous record of operating and standby time within the 25 mile radius of the drilling vessel

, barrels of diesel fuel on the support vessel entering the 25 mile radius

, and barrels of diesel fuel on the support vessel exiting the 25 mile radius , and determining and recording the sulfur content upon receiving each fuel shipment

. Anadarko will supply the EPA with all records upon request. In addition, Anadarko will provide

a s emi

- annual report of its emissions information and calculations in accordance with all relevant permit conditions. 

## 6.0 Best Available Control Technology (BACT) and Recordkeeping Requirements

A new major stationary source subject to PSD requirements is requ ired to apply BACT for each pollutant subject to regulation under the CAA that it has the potential to emit in amounts equal to or greater than the pollutant’s significant emission rate. See 40 CFR § 52.21(j). Based on the emission inventory for the projec t, presented in Table 4

- 1 of the preliminary determination, NO X , CO, VOC, PM/PM 10 /PM 2.5 , and GHGs are the CAA

- regulated pollutants that will be emitted by Anadarko in quantities exceeding the respective significant emission rate. Therefore, BACT must be de termined for each emission unit on the drillship BlackHornet that emit s these pollutants while operating as an OCS source and t he stimulation vessel p ump engines

.

The life boats and the fast rescue boat are included in the OCS source’s PTE and emissions modeling, as required by 40 CFR part 55

, and are subject to operating limits, monitoring, recordkeeping and reporting requirements to ensure they will not exceed the potential emissions assumed in the application and impact review. Vessels o perating within 25 miles of the OCS source are not subject to BACT requirements unless they are attached to the OCS, and then only the stationary source aspects of the vessel are regulated. See 40 CFR § 55.2. These units do not have any stationary source a spects as they are used for man overboard and emergency escape scenarios only

. 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 Administrator25

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- R4020 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 def inition, although the 1990 CAA amendments added “clean fuels” after “fuel cleaning or treatment” in the above definition. See CAA § 169(3).

On December 1, 1987, the EPA issued a memorandum describing the top

- down approach for determining BACT. Memorandum from J. Craig Potter, Assistant Administrator for Air and Radiation, to the EPA Regional Administrators regarding Improving New Source Review (NSR) Implementation (Dec. 1, 1987). In brief, the top

- down approach provides that all available control technolog ies 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 techn ologies.

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 eff ective control option.

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

Below is a summary of the EPA ’s top

- down BACT analysis for the BlackHornet and the equipment that is part of the OCS source during the well completion activi ties.

6.1 BACT Analysis for Internal Combustion Engines

The following large internal combustio n engines (i.e., engines greater than 500 hp), on BlackHornet are included in this sect ion of t he BACT analysis: eight (8 ) main diesel engines (DR

- M E

- 01 through DR

- ME

- 08 ) and one ( 1) emergency generator (DR

- GE

- 01 ). The following engines on the stimulation v essel are also included in this section and are considered large internal combustion engines: ei ght (8) stimulation vessel pump engines (SV

- PE

- 01 throu gh SV

PE

- 08).

The main diesel engines will not produce emissions at a steady rate. These engines operate at variable load based on drilling and operational power demand. The emergency generator eng ine will be tested periodically but not operated continuously. In addition, engine efficiency and26

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- R4020 performance typically degrade over time, resulting in increased emissions. These factors are important considerations in the BACT analysis for these units.

The following sm all internal com bustion engines (i.e. engines less than 500 hp), on BlackHornet are included in this section of the BACT analysis: one (1) emergency air compressor engine (DR

- AC

- 01), and (5) third party engines (DR

- TP

- 12 through DR

- TP

- 16 ). The temporary EPA Tier 2 certifi ed th ird party engines onboard the BlackHornet consist of three types of engines

, those rated less than or equal to 860 hp, 300 hp, or 126 hp. Therefore

, these engines will consist of both small and large engines. The applicant identified available control technologies in the BACT analysis as if all engines are large engines. These engines include DR

- TP

- 01 through DR

TP

- 11 and DR

- TP

- 17 through DR

- TP

- 21

.

6.1.1 NO X BACT Analysis for all Internal Combustion Engines

NO X emissions are generated as both a result of high temperature combustion (thermal NO X ) and oxidation of nitrogen present in the fuel (fuel

- bound NO X ). Thermal NO X emissions increase with an increase in combustion temperature, and are generally the main cau se of NO X emissions from a combustion source.

Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit application submitted in September 2013 and su pplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014 , September 2, 2014, and September 10, 2014 :

1. Selective Catalytic Reduction (SCR) (on the Large Internal Combustion Engines and Third Party Engines) ; 2. Sel ective Non

- Catalytic Reduction (SNCR) (on the Large Internal Combustion Engines and Third Party Engines) ; 3. Direct Water Injection ; 4. Exhaust Gas Recirculation System ; 5. De rating of Existing Engines ; 6. Water

- in

- Fuel Emulsions ; 7. Intake Air Humidification/Cooling ; 8. NO X Absorber/Scrubber Technology ; 9. CSNO x Emissions Abatement System (on the Large Internal Combustion Engines and the Third Party Engines) ; 10. Replacement of Older Engines with Newer Engines to Meet Higher EPA Tier Standard ; 11. Camshaft Replacement/Retooling of E ngines ; 12. Lean De

- NO X Catalyst or Hydrocarbon SCR ; 13. Low NO x Engine (LNE) Design (Turbocharger with Aftercooler and High Injection Pressure System) ; 14. Performance Management including a Parametric Emission Monitoring System ( Main Engines Only ) ;27

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- R4020 15. 4

- Way Catalyst Converter ; 16. Ignition Timing Retard ; and 17. Good Combustion Practices

. The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasi ble control options

After analyzi ng the 17 control technology options identified for the large diesel internal combustion engines, 13 of the options were eliminated as technically infeasible for all of the large diesel engines for the control of NO X emissions (options 1 through 9

, 11

, 12, 15

, and 16 ). Item 10 is technically feasible for the stimulation vessel pumps only, while item 14 only applies to the main generator engines.

After analyzing the 13 control technology options identified for the small internal combustion engines, 10 of the options were eliminated as technically infeasible for the control of NO X emissions from all small diesel internal combustion engines (options 3 through 8, 12, 13, 1 5

, and 16 ). Camshaft Replaceme nt/Retooling of Engines, item 11 , is technically feasible for only the well evaluation engines

. Below is a summary of the reasons for eliminating each of these options from further consideration in the top

- down BACT analysis for this project. For detailed descriptions of the control technologies and references, please refe r to the application submitted to the EPA in September 2013 and s upplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014 , September 2, 2014, and September 10, 2014

. SCR (on the Large Internal Combustion Engines and Third Party Engines): This option is technically infeasible due to limited space availability for the SCR unit and the necessary ancillary equipment ( e.g. , urea storage tanks ). The emergency diesel engine, third party engines, and the stimulation vessel pump engines will not operate for time periods long enough for the ca talyst to reach its working temperature. The EPA agrees that this control technology is not technically feasible in this instance.

SNCR (on the Large Internal Combustion Engines and Third Party Engines): This technology requires the temperature of the ex haust gas to be greater than 1,700° Fahrenheit. The main and emergency diesel engines will operate at temperatures in the range of 329

- 365° F, which is below the SNCR operating range. In addition, this technology is not feasible due to limited space availa ble for urea storage and other ancillary equipment.

Direct Water Injection: This technology is in development stages for marine applications and cannot be used at low loads (30

- 40%), which is within the planned operating loads for t he main engines on the drillship . Also, this technology is in the development stages for marine applications, and is not fe asible for smaller engines. The technology will require additional unavailable space for freshwater tanks. Injecting water into the engine increases the potential for28

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- R4020 engine damage as water may contact the combustion cylinder surface causing disintegration of lubricating oil film. This technology could also decrease the available power, which would caus e a safety risk on the drillship

.

Exh aust Gas Recirculation System: The technology is in development stages for marine applications and has primarily been applied to smaller high speed di esel engines (cars and trucks). In addition, use of EGR can reduce engine power output which can hinder safe drilling operations.

De rating of Existing Engines: This option is technically infeasible for all engines because it reduces peak power available for the engines, which is required to perform necessary operations, and thus impairs the ability to safely maintain the vessel’s position and perform other functions related to drilling operations. Furthermore, the emergency generator will need to be able to operate at peak power when the main engines are inoperable.

Water

- in

- Fuel Emulsions: This technology would require derating of the engines (see above), and emulsified diesel in marine vessels can cause fuel tank corrosion issues. Additionally, emulsifi ed fuel systems were designed for and installed on slow

- speed engines burning heavy fuel oil. The existing engines on the BlackHornet and the pump engines on the stimulation vessel are designed and will be burning medium density diesel fuel. Installing an untested emulsified fuel system designed for heavy fuel oil use on the existing engines increases the potential for mechanical failure and poses a safety risk. In addition, this technology requires the installation of

a mixing tank that would require signi ficant retrofitting to the vessel, and also need to be pressurized. Th e pressurized fuel would increase pr essure head that already exists in the fuel lines, and these lines could potentially fail.

Intake Air Humidification/Cooling: Humidification can req uire additional storage capacity for freshwater that is not available on the drill rig or stimulation vessel. Additionally, for the main diesel engines, heat input is required to produce high volumes of humid air, and at low loads the engines may not be ab le to produ ce a significant amount of heat making it difficult to control humidity.

NO X Absorber/Scrubber Technology: This technology has been used primarily for on

- road diesel applications or off

- road applications for smaller engines such as backhoes, graders, and wheel loaders. In addition, this technology has not been demonstrated for use on comparable marine vessels o r engines, and is still in the developmental stage.

CSNOx (on the Main Diesel Generator Engines ): This technology is not in the commercial resale stage of development. In addition, this technology has not been demonstrated for engines operating at variab le loads.

Replacement of Old Engines with New Engines (for the Main Diesel Generator Engines, the Emergency Generator, the Emergency Air Compressor Engine, the Third Party Engines , and Third Party Well Evaluation Engines ): The main diesel generator engin es currently meet the highest IMO Tier II standard available which is equal to the EPA Tier 2 (40 CFR Part 1043) standards for NO x .29

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- R4020 The drillship emergency gener ator currently meets the highest IMO Tier II certified rating. This engine is not EPA Tier certified, see Section 6.5.1, but it is the highest rated available engine

.

The emergency air compressor engine currently meets the highest EPA Tier 3 standard.

The cleanest available third

- party engines include E PA Tier III or Tier IV engines ; however, these engines, at most, comprise 20% o f the available inventory. P roposed drilling plans change on short notice, and require contracts within short timeframes. The vendors do not have their entire inventory available within these time constraints; therefore, they cannot guarantee the cleanest engines when the percentage of their inventory is this low.

The five third party well evaluation engine s are pre

- 1998 engines and are not certified to any tier standard. These engines require deepwater, high

- pressure , ratings. Currently only one vendor offers this technology and this vendor does not have any EPA Tier certified engines.

Camshaft Replacement/Retooling of Engines (Excluding T hird Party Well Evaluation Engines) : These retooling kits are only ava ilable for Detroit Diesel engines. This option has not yet been developed for larger engines ( e.g. , 4

- stroke); therefore, it is not technically feasible for all engines except the well evaluation engines that meet these requirements.

Lean De

- NO X Catalyst or Hydrocarbon SCR: According to the technology provider (Johnson Matthey Catalyst), this technology is not available for marine engines. This system also operates best at constant loads and is therefore not amenable for the main diesel engines o r for the long periods of engine idle experienced by the emergency generator and the pump engines on the stimulation vessel.

LNE Design (on the Emergency Air Compressor Engine , T hird Party Engines , Third Party Well Evaluation Engines, and Stimulation Vess el Pumps ): This technology is intrinsic to an engine and retrofitting these engines is not feasible.

4

- Way Catalyst Converter: The engines onboard the BlackHornet and the pump engines cannot sustain constant steady state loads and exhaust temperatures to sustain high catalyst performance. Non

- combustible chemical elements present in engine lube oils may collect over time and damage the catalyst. This technology is not available for the engines onboard the BlackHornet and the pump engines on the stimulation vessel.

Sea Scrubber: This technology has not been tested on engines that operate at variable load or intermittently.

Ignition Timing Retard: This technology is infeasible due to intrinsic engine design, and will reduce engine power and combustion hind ering stability.

The EPA agrees with the applicant that these control technologies are not technically feasible for the reasons discussed above.30

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- R4020 Step 3: Rank the remaining control technologies by effectiveness

The control options not eliminated as techn ically infeasible in Step 2 of the top

- down BACT analysis were then ra nked by effectiveness. Table 6

- 1 lists the remaining control technologies that have not been ruled out as technically infeasible options ranked by effectiveness for the engines on the dr illing vessel and the pump engines on the stimulation vessel.

Additional information regarding maintenance procedures and schedu les are provided in Appendix G of the September 2013 application.

Table 6

- 1: Step 3

- NO x Control Technologies Ranked by Effectiveness Engine Rank Control Description NO x Control Effectiveness Main Diesel Engines (DR

- ME

- 01 through DR

- ME

- 08 ) 1 LNE Design Including Turbocharger and Aftercoolers, and High Injection Pressure with Performance Management and Parametric Emissions Monitoring System (PEMS ) 45 %

2 LNE D esign Including Turbocharger and Aftercoolers, and High Injection Pressure 30%

3 G ood C ombustio n P ractices/ E ngine M aintenance Baseline

E mergency Generator Diesel Engine (DR

- GE

- 01 ) 1 LNE Design Including Turbocharger and Aftercoolers, and High Injection Pressure 30%

2 Good Combustion Practices Baseline

Emergency Air Compressor Engine (DR

- AC

- 01) 1 EPA 40 CFR part 1039 Tier 3 Certified Engine - b

2 Good Combustion Practices Baseline

Third Party Engines (DR

- TP

- 01 through DR

- TP

- 11 and DR

- TP

- 17 through DR

- TP

- 21) 1 EPA 40 CFR part 89 Tier 2 Certified Engine ~35 %

2 Good Combustion Practices Baseline

Third Party Well Evaluation Engines (DR

- TP

- 12 through DR

- TP

- 16) 1 C a mshaft Replacement/Retooling Engines

- b
2 Good Combustion Practices Baseline Stimulation Vessel Pump Engines (SV

- PE

- 01 through SV

- PE

- 08) 1 Replacement of Old Engines with New Engines Varies

2 Good Combustion Practices Baseline *The application contains a ranking and cost analysis for SCR control techn ology; however, since this technology was determined to be technically infeasible it is not listed here.
b Baseline emissions were not included to calculate the relative control effectiveness.
Step 4: Evaluate m ost e ffective c ontrols

The control technologies listed in S tep 3 are further discussed below, and are evaluated against any relevant economic, environmental, or energy considerations.31

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- R4020 Replacement of Old Engines with New Engines for the Stimulation Vessel Pump Engines: Anadarko provided a cost analysis in Appendix E of the September 2013 application for replacing the existing engines with newer engines meeting the EPA 40 CFR 89 tier 2 standards. The applicant estimated the cost of replacing the existing engines with compliant en gines would result in a cost effectiveness of $34,670 per ton of pollutant removed.

Cam s haft Replacement/Retooling of Engines for the Third Party Well Evaluation Engines: Clean Cam Technology Systems (CCTS) offers retrofit cam shaft reengineering kits for use on diesel engines. These kits are available for the well evaluation engines. The applicant determined that given the engine’ s minimal operating time of 125 hours per year the resulting emissions are minimal. Th ese units will emit less than 5 TPY of NO x . Given t he minimal planned o peration of this unit the Cams haft replacement/retooling for the well evaluation engines is cost prohibitive.

LNE Design for the Main Diesel Engines and Emergency Generator: LNE Design includes turbocharger, aftercooler, and a high injection press ure system. LNE design will reduce emissions by optimizing the intake valve’s closing timing, and thereby change the c ompression and expansion ration . This control technology is technically feasible for these engines.

Step 5: Select BACT

After taking into account energy, economic, and environmental impacts in Step 4 of the BACT analysis, the EPA determined BACT for the diesel engines on the BlackHornet and for the pump engines on the stimulation vessel as discussed below and summarized in Table 6

- 2.

Main Engines: The EPA proposes three limits for NO X emissions dependent on the engine load and based on the s ta ck test data submitted to EPA on July 15, 2014 . For all engines , the EPA
pr oposes an emission limit of 10.57 g/kw

- hr when the engines are operating at or above 50% load. This limit is based on the average emissions of the highest emitting engine

. For the smaller main engines, DR

- ME

- 01 through DR

- ME

- 06, the EPA proposes a NO X limit of 57.3 lb/hr when the se engines operat e at less than 50% load based on the upper bound of the 95% confidence interval of the stack test results for these engines operating at 60% load . For the larger main engines, DR

- ME

- 07 and DR

- ME

- 08, the EPA proposes a NO x l imit of 103.5 lb/hr when these

en gines operate at less than 50% load. This was also established on the stack test results and represent s the upper bound of the 95% confidence interval for the large engines operating at 50% load

. Emission limits for engines operating above 50% were set in g/kw

- hr, while those below 50% were set in lb/hr. The lb/hr emission limit better reflects the fuel usage of the engines while operating at low loads.

Anadarko must comply with 40 CFR part 60 subpart IIII, as maintained in Condition 6.11 , and described i n section 4.5.1 . All main engines operating within 10% of 100% peak load (or the highest achievable load) must comply with a NO X limit of 9.69 g/kw

- hr.

The EPA has included requirements for Performance Management that includes a Parametric Emission M onitoring System (P E MS). The P E MS will reduce NO x emissions by notifying the permittee of instances when the engines emissions are increasing outside an established operating range, whereby the permittee will adjust the engines to operate optimally . Given the32

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- R4020 significant load variations required by the operations on the drillship and the information provided by the applicant and vendor, the EPA has determined that an averaging period of 24 hours on a rolling basis is appropriate in this case.

Emergency Ge nerator Engine and Emergency Air Compressor Engine: The applicant estimated NO x emission s at 7.85 g/kW

- hr for the emergency generator and an operating time of 100 hours per year, and for the emergency air compressor engine the applicant estimated NO x emiss ion s at 0.012 lb/hp

- hr and an operating time of 100 hours per year. S ince these units will be operated minimally, measuring compliance with a numeric emission limit would be unreasonably burdensome and costly. Therefore, the EPA has determined that BACT for these two engines is use of work practice standards including good combustion practices and operating in accordance with the manufacturer’s specifications, EPA Tier 3

- cer t ified engine for the
emergency air compressor, LNE design for the emergency gener ator , and use of an IMO Tier

certified engine for the emergency generator. The engines will maintain compliance with the hourly operating limits specified above for each engine.

Pump Engines and Third Party Engines : These units will be used on an as

- neede d basis during drilling operations. The exact units are unknown prior to drilling, and therefore, other than monitoring these units ’ hourly usage, an advanced monitoring system would be cost prohibitive and impractical. Given the use of these emission unit s, the EPA has determined that BACT is more appropriately implemented as work practice standards to include either the use of EPA Tier

- certified engines and/or good combustion practices. Furthermore, to maintain consistency with the emission estimates in t he permit application, the draft permit includes operational limits for these units.

Table 6

- 2: NO X BACT Conclusion Emissions Unit ID BACT Control Options Technology and NO X BACT Emission Limits* DR

- ME

- 01 thru DR

- ME

- 08 IMO Tier II Standards, LNE D esign I ncluding Turbo charge r and Aftercoolers, and High Injection P ressure with Performance Management, P E MS, and G ood C ombustion P ractices ; NO x limit for loads at or above 50%: 10. 57 g/kW

- hr ; NO x limit for loads below 50 % for DR

- ME

- 01 through DR

- ME

- 06: 57.3 lb/hr; NO x limit for loads below 50% for DR

- ME

- 07 and DR

- ME

- 08: 103.5 lb/hr DR

- GE

- 01 IMO Tier II Standards, LNE D esign I ncluding Turbo charge r and Aftercoolers, and High Injection P ressure an d G ood C ombustion P ractices DR

- AC

- 01 40 CFR part 1039 EPA Tier 3 S tandards and G ood C ombustion P ractices Third Party Engines (DR

TP

- 01 through DR

- TP

- 11 and DR

- TP

- 17 through DR

TP

- 21) 40 CFR part 89 EPA Tier 2 S tandards and G ood C ombustion P ractices

Third Party Well Evaluation Engines (DR

- TP

- 12 through DR

- TP

- 16) G ood C ombustion P ractices33

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- R4020 SV

- PE

- 01 thru SV

- PE

- 08 G ood C ombustion P ractices *Short

- term limits are based on a 24

- hour rolling average

.
6.1.2 CO and VOC BACT Analyses for all Internal Combustion Engines

Incomplete combustion of the diesel fuel in the combustion chamber forms CO and VOC. Insufficient residence time during the final step in the oxidation of hydrocarbons during combustion will produce CO. The maximum oxidation of CO to CO 2 occurs when the combustion process maintains sufficient temperature, residence time, and oxygen supply. Also, most VOCs found in diesel exhaust are the result of unburned fuel, although some are formed as combustion products. VOC compounds participate in atmospheric photochemical reactions. These reactions can result in the formation of ozone. VOCs do not include methane, ethane, and other compounds that have negligible photochemical reactivity.

Step 1: Identify all available control technologies

The ap plicant identified the following available control technologies in their OCS permit application submitted in September 2013 and supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014 , Se ptember 2, 2014, and September 10, 2014 :

1. Diesel Oxidation Catalyst ; 2. Catalytic Diesel Particulate Filter ; 3. 4

- Way Catalyst Converter with Exhaust Gas Recirculation System ; 4. Replacement of Older Engines with Newer Engines ; 5. LNE Design (Turbocharger with Afterco oler and High Injection Pressure System) ; 6. Good Combustion Practices ; 7. Ignition Timing Retard ; and 8. Positive Crankcase Ventilation (VOC only)

. The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options

After analyzing the eight control technology options for the contr ol of CO and VOC emissions, five were eliminated as technically infeasible for all diesel intern al combust ion engines (options 1 through 3, 7, and 8 ). Option 5 was eliminated as technically infeasible for the main diesel engines

, the third party engines , and the third party well evaluation engines

. Below is a summary of the reasons for eliminating ea ch of these options from further consideration in the top

- down BACT analysis for this project. For detailed descriptions of the control technologies and references, please refe r to the application submitted to the EPA in September 2013 and

s upplemental mat erial submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014 , September 2, 2014, and September 10, 2014

.34

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- R4020 Diesel Oxidation Catalyst: The engines onboard the BlackHornet and the pump engines on the stimulation vessel cannot sustain constant steady state loads or temperatures for a sufficient time necessary for high catalyst performance. This control technology can also cause pressure drop across the exhaust flow that results in back pressure on all the engines that could cause plugging of the engine, and thereby cause a safety concern. Non

- combustible chemical elements present in engine lube oils may collect over time and damage the catalyst. In addition, this t echnology has not been designed or tested on large internal combustion engines nor is it commercially available

. Catalytic Diesel Particulate Filter: This control technology can cause pressure drop across the exhaust flow that results in back pressure on the engine that could cause plugging of the engine, and thereby causes a safety concern. Non

- combustible chemical elements present in engine lube oils may collect over time and damage the catalyst. In addition

, this t echnology has not been designed or tested on a commercially available scale comparable to the large main generator and emergency diesel engines

. The EPA agrees with the applicant that this control technology is not technically feasible in this instance.

4

- Way Catalyst Converter with Exhaust Gas Recirculation System: The engines onboard the BlackHornet and the pump engines on the stimulation vessel will not sustain constant steady

state loa ds or temperatures for a sufficient time necessary for high catalyst performance. Non

combustible chemical elements present in engine lube oils may collect over time and damage the catalyst. For these reasons, the EPA agrees with the applicant that this te chnology is not technically feasible.

Replacement of Old Engines with New Engines (for the Main Diesel Generator Engines, the Emergency Air Compressor Engine, the Third Party Engines, and Third Party Well Evaluation Engines ): This option is technically infeasible for these engines for the same rationale provided above in Section 6.1.1. In addi tion, the IMO Tier s tandard that the main diesel generator engines maintain does not have a CO or VOC emission standard. Since the ship i s already constructed, replacement of the engines at this juncture would require redesign and an engine certification process.

LNE Design (on the Emergency Air Compressor Engine, Third Party Engines, Third Party Well Evaluation Engines, and Stimulation V essel Pumps): This option is technically infeasible for these engines for the same rationale provided above in Section 6.1.1

. Ignition Timing Retard: This option is technically infeasible for these pollutants for the same rationale provided above in Secti on 6.1.1.

Positive Crankcase Ventilation (VOC only): This technology is intrinsic to the engine design. Engine manufacturers have strict restrictions on installing upgrades to avoid violating warranties. The engines onboard the BlackHornet and the pump engines cannot be retrofitted to accommodate this technology. This technology would require significant ship redesign.

The EPA agrees with the applicant that these control technologies are not technically feasible for the reasons discussed a bove.35

11/14/14 Anadarko BlackHornet PD OCS

- EPA

- R4020 Step 3: Rank the remaining control technologies by effectiveness

The control options not eliminated as technically infeasible in Step 2 of the top

- down BACT analysis were then ranked by effectiveness. Table 6

- 3 lists the remaining control technolog ies that have not been ruled out as technically infeasible options ranked by effectiveness for the engines on the drilling vessel and the pump engines on the stimulation vessel.

Additional information regarding maintenance procedures and schedules are pr ovided in Appendix E of the September 2013 application

.

Table 6

- 3: Step 3

- CO and VOC Control Technologies Ranked by Effectiveness Engine Rank Control Description CO and VOC Control Effectiveness Main Diesel Engines (DR

- ME

- 01 through DR

- ME

- 08) 1 LNE D esign I ncluding Turbocharger, A ftercoolers, and H igh I njection P ressure ~ 30 %

2 Good Combustion Practices Baseline
Emergency Generator Diesel Engine (DR

- GE

- 01) 1 Replacement of Old Engines with New Engines Varies

2 LNE Design Including Turbocharger and Aftercoolers, and High Injection Pressure ~30%

3 Good Combustion Practices Baseline Emergency Air Compressor Engine (DR

- AC

- 01) 1 EPA 40 CFR part 1039 Tier 3 Certified Engine - b

2 Good Combustion Practices Baseline Third Party Engines (DR

- TP

- 01 through DR

- TP

- 11 and DR

- TP

- 17 through DR

- TP

- 21) 1 EPA 40 CFR part 89 Tier 2 Certified Engine ~35 %

2 Good Combustion Practices Baseline Third Party Well Evaluation Engines (DR

- TP

- 12 through DR

- TP

- 16) 1 Cams haft Replacement/Retooling Engines

- b
2 Good Combustion Practices Baseline Stimulation Vessel Pump Engines (SV

- PE

- 01 through SV

- PE

- 08) 1 Replacement of Old Engines with New Engines Varies

2 Good Combustion Practices Baseline

b Baseline emissions were not included to calculate the relative control effectiveness.

Step 4: Evaluate Most Effective Controls

The control technologies listed in S tep 3 are further discussed below, and are evaluated against any relevant economic, environmental, or energy considerations.

Replacement of Old Engines with New Engines for the E mergency Generator: The current emergency generator is an IMO Tier 2 certif i ed engine; however, 40 CFR 89 Tier 2 compliant engines are the cleanest engines available. T he IMO Tier standard that t he emergency generator engine maintain s does not have a CO or VOC emission standard. Anadarko, estimated that since these engines will op erate no more than 100 hours per year, and therefore the replacement would be cost prohibitive.36

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- R4020 Replacement of Old Engines with New Engines for the Stimulation Vessel Pump Engines: T his option was determined to be cost prohibitive for CO and VOC control for the same rationale provided in Section 6.1.1.

LNE Design for the Main Diesel Engines and Emergency Generator: This option was determined to be technically feasible for CO and VOC control for the same rationale provided in Section 6.1.1.

Step 5: Select BACT

Main Engines: The EPA proposes three limits for CO emissions dependent on the engine load and based on the s tack test data submitted to EPA on July 15, 2014 . For all engines , the EPA
p roposes an emission limit of 2.8 g/kw

- hr when the engines are operating at or above 50% load. This limit is based on the 95% co nfidence interval of engine DR

- ME

- 08 operating at 90% load

. For the smaller main engines, DR

- ME

- 01 through DR

- ME

- 06, the EPA pro poses a CO limit of 16.6 lb/hr when the se engines operate at less than 50% load based on the limit proposed by Anadarko that reflects the emissions from the stack test results . For the larger main engines, DR

ME

- 07 and DR

- ME

- 08, the EPA proposes a VOC l imit of 23 .3 lb/hr when these engines operate at less than 50 % load. This limit represents the average of thirty data points from the stack test results for the highest emitting engine recorded at 50% load.

The EPA proposes three limits for VOC emissions dependent on the engine load and based on the stack test data, referenced above. For all engines

, the EPA proposes an emission limit of 0. 8 g/kw

- hr when the engines are operating at or above 50% load

. This limit is based on the 95% confidence interval of the highest emitting engine opera ting at 60% load

. For the smaller main engines , DR

- ME

- 01 through DR

- ME

- 06, the EPA proposes a VOC limit of 4.6 lb/hr when the se engines operate at less than 50% load

. For the larger main engines, DR

- ME

- 07 and DR

- ME

- 08

, the EPA proposes a VOC l imit of 6.2 lb/hr when these engines operate at less than 50% load. These limits are based on the stack test results submitted by Anadarko and the 95% confidence interval of the highest emitting engine operating at 60% and 50% load respectively

.

Emission limits for engines operating above 50% were set in g/kw

- hr, while those bel ow 50% were set in lb/hr. The lb/hr emission limit better reflects the fuel usage of the engines while operating at low loads.

Given the significant load variations required by the operation s on the drillship and the information provided by the applicant and vendor, the EPA has determined an averaging period of 24 hours on a rolling basis is appropriate in this case

. BACT for the main engines will also include work practice standards including good combustion practices based on the current manufacturer’s specifications for these and operating in accordance with the manufacturer’s specifications and LNE design

. Emergency Generator Engine and Emergency Air Compressor Engine : The BACT de termination in Section 6.1.1 is also applicable for CO and VOC.37

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- R4020 Pump Engines and Third Party Engines : The BACT determination in Section 6.1.1 is also applicable for CO and VOC.

After taking into account energy, economic

, and environmental impacts discu ssed above in Step 4 of the BACT analysis, the EPA determined BACT for the diesel engines on the BlackHornet and for the pump engines on the stimulation v essel as summarized in Table 6

- 4

.

Table 6

- 4: CO and VOC BACT Conclusions Emissions Unit ID BACT Control Technology and CO and VOC BACT Emission Limits* Main Diesel Engines (DR

- ME

- 01 thru DR

ME

- 08) LNE Design I ncluding Turbo charge r and Aftercoolers, and High Injection P ressure and G ood C ombustion P ractices ; CO limi t for loads at or above 50%: 2.8 g/kW

- hr ; CO limit for loads below 50 % for DR

- ME

- 01 through DR

ME

- 06: 16.6 lb/hr; CO limit for loads below 5 0% for DR

- ME

- 07 and DR

- ME

- 08: 23 .3 lb/hr LNE Design I ncluding Turbo charge r and Aftercoolers, and High Injection P ressure and G ood C ombustion P ractices ; VOC limit for loads at or above 50% : 0. 8 g/kW

- hr ; VOC limit for loads below 50 % for DR

- ME

- 01 through DR

- ME

- 06: 4.6 lb/hr; VOC limit for loads below 50% for DR

- ME

- 07 and DR

- ME

08: 6.2 lb/hr Emergency Generator Engine ( DR

- GE

- 01 ) LNE D esign I ncluding Turbo charge r and Aftercoolers, and High Injection P ressure and G ood C ombustion P ractices Emergency Air Compressor ( DR

- AC

- 01 ) 4 0 CFR part 1039 EPA Tier 3 S tandards and G ood Combustion Practices Third Party Engines (DR

- TP

- 01 through DR

TP

- 11 and DR

- TP

- 17 through DR

- TP

- 21) 4 0 CFR part 89 EPA Tier 2 S tandards and G ood C ombustion P ractices Third Party Well Evaluation Engines (DR

TP

- 12 through DR

- TP

- 16) G ood C ombustion P ractices

SV

- PE

- 01 thru SV

- PE

- 08 G ood C ombustion P ractices *Short

- term limits are based on a 24

- hour rolling average

.

6.1.3 PM/PM

10 /PM 2.5 BACT Analysis for Internal Combustion Engines

Diesel particulate emissions are primarily products of incomplete combustion of diesel fuel and lubrication oil in the combustion chamber. The majority of the PM emissions from stationary diesel engines are PM 2.5 ; therefore, BACT for PM/PM 10 /PM 2.5 is addressed concurrently since any control technology available for the control of PM 2.5 will also effectively control PM and PM 10

. Step 1: Identify all available control technologies38

11/14/14 Anadarko BlackHornet PD OCS

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- R4020 The applicant identified the following available control technologies in their OCS permit
ap plication submitted in September 2013 and supplemental material submitted on September 18, 2013, November 26, 2013, Dec ember 5, 2013, February 11, 2014, July 15, 2014 , September 2, 2014, and September 10, 2014 :

1. Baghouse (Fabric Filter) ; 2. Ultra

- Low Sulfur Diesel (ULSD) Fuel/ Low Ash Fuel ; 3. Diesel Oxidation Catalyst ; 4. Catalytic Diesel Particulate Filter ; 5. Positive Crankcase Ve ntilation ; 6. 4

- Way Catalyst Converter with Exhaust Gas Recirculation System ; 7. Replacement of Older Engines with New O nes ; 8. Good Combustion Practices ; 9. LNE design including Turbocharger with aftercooling and high injection pressure ; 10. Fuel Injection timing Retard ; and 11. Sea Scrubber

. The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options

After analyzing the 11 cont rol technology options for the control of PM/PM 10 /PM 2.5 emissions, six were eliminated as technically infeasible for all diesel interna l combustion engines (options 3 through 6

, 10

, and 11 ). Option 1 was only identified for the main diesel engines. Below i s a summary of the reasons for eliminating each of these options from further consideration in the top

- down BACT analysis for this project. For detailed descriptions of the control technologies and references, please refe r to the application submitted to t he EPA in September 2013 and

s upplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014 , September 2, 2014, and September 10, 2014

. Baghouse (Fabric Filter) (on the Main Diesel Engines Only): Baghouses could cause a high pressure drop across the exhaust flow resulting in excessive back pressure on the engine. To avoid a large pressure drop across the baghouse, a fabric area larger than the space available on the drillship would be required. Due to space constraints on the vessels

, this option is not feasible.

Diesel Oxidation Catalyst : This option is technically infeasible for these pollutants for the same rationale provided above in Section 6.1.2.

Diesel Particulate Filter/CDPF : This option i s technically infeasible for these pollutants for the same rationale provided above in Section 6.1.2.

Positive Crankcase Ventilation : This option is technically infeasible for these pollutants for the same rationale provided above in Section 6.1.2.39

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- R4020 4

- Way Catalyst Converter with Exhaust Gas Recirculation System : This option is technically infeasible for these pollutants for the same rationale provided above in Section 6.1.2.

Replacement of Old Eng ines with New Engines (for the Main Diesel Generator Engine s, the Emergency Air Compressor Engine, the Third Party Engines, and Third Party Well Evaluation Engines ): This option is technically infeasible for these engines for the same rationale provided above in Section 6.1.1. In addition, the main diesel generato r engines will comply with the most stringent PM standards available, specified in 40 CFR part 60, subpart IIII, and therefore this control technology is not applicable for these engines.

LNE Design on the Emergency Air Compressor Engines and Stimulation Vessel Pumps: This option is technically infeasible for these pollutants for the same rationale provided above in Section 6.1.1

.

Sea Scrubber : This add

- on control technology is used to reduce both SO 2 and particulate matter emissions. The EPA has contacted industry experts and has determined that this technology could be used on engines that operate at variable loads. However, the sea scrubber is skid mounted and would require additional unavailable space. Therefore, this technology is technic ally infeasible.

The EPA agrees with the applicant that these control technologies are not technically feasible for the reasons discussed above.

Step 3 : Rank the remaining control technologies by effectiveness

The control options not eliminated as tech nically infeasible in Step 2 of the top

- down BACT analysis were then ranked by effectiveness. Table 6

- 5 lists the remaining control technologies that have not been ruled out as technically infeasible options ranked by effectiveness for the engines on the d rilling vessel and the pump engines on the stimulation vessel.

Additional information regarding maintenance procedures and schedules are provided in Appendix E of the September 2013 application

.
Table 6

- 5: Step 3

- PM/PM 10 /PM 2.5 Control Technologies Ranked by Effectiveness

Engine Rank Control Description PM/PM 10 /PM 2. Control Effectiveness Main Diesel Engines (DR

- ME

- 01 through DR

- ME

- 08) 1 LNE D esign I ncluding T urbo c harge r, A ftercoolers, and H igh I njection P ressure , NSPS 40 CFR 60 Subpart IIII 30%

2 ULSD Varies 3 Good Combustion Practices Baseline Emergency Generator Diesel Engine (DR

- GE

- 01) 1 Replacement of Old Engines with New Engines Varies

2 LNE Design I ncluding T urbocharger, A ftercoolers, and H igh I njection P ressure 30%40

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- EPA

- R4020 3 ULSD

- b
4 Good Combustion Practices Baseline Emergency Air Compressor Engine (DR

- AC

- 01) 1 EPA 40 CFR part 1039 Tier 3 Certified Engine - b

2 ULSD

- b
3 Good Combustion Practices Baseline Third Party Engines (DR

- TP

- 01 through DR

- TP

- 11 and DR

- TP

- 17 through DR

- TP

- 21) 1 EPA 40 CFR part 89 Tier 2 Certified Engine ~35 %

2 ULSD

- b
3 Good Combustion Practices Baseline Third Party Well Evaluation Engines (DR

- TP

- 12 through DR

TP

- 16) 1 ULSD

- b

2 Good Combustion Practices Baseline
Stimulation Vessel Pump Engines (SV

- PE

- 01 through SV

- PE

- 08) 1 Replacement of Old Engines with New Engines Varies

2 ULSD

- b
3 Good Combustion Practices Baseline

b Baseline emissions were not included to calculate the relative control effectiveness.

Step 4: Evaluate most effective controls

The control technologies listed in S tep 3 are further discussed below, and are evaluated against any relevant economic, environmental, or energy considerations.

Replacement of Old Engines with New Engines for the Emergency Generator: This option was determined to be cost prohibitive for PM control for the same rationale provided in Section 6.1.2.

Replacement of Old E ngines with New Engines for the Stimulation Vessel Pump Engines: This option was determined to be cost prohibitive for P M control for the same rationale provided in Section 6.1.1 and 6.1.2.

LNE Design for the Main Diesel Engines and Emergency Generator: This option was determined to be technically feasible for PM control for the same rationale provided in Section 6.1.1 and 6.1.2

.

ULSD : The burning of fuel with ultra

- low sulfur content results in lower particulate matter emissions compared to diesel fuel with a higher sulfur content. This control technology is technically feasible.

Step 5: Select BACT

After taking into account energy, economic, and environmental impacts in Step 4 of the BACT analysis, the EPA determined BACT for the diesel engines on the BlackHornet and for the pump engines on the stimulation vessel as summarized below and in Table 6

- 6.

Main Engines: The EPA proposes three limits for PM/ PM 10 / PM 2. 5 emissions dependent on the engine load an d based on the stack test data submitted to EPA on July 15, 2014 . For all engines

,41

11/14/14 Anadarko BlackHornet PD OCS

- EPA

- R4020 the EPA p roposes an emission limit of 0.40 g/kw

- hr when the engines are operating at or above 50% load. For the smaller main engines, DR

- ME

- 01 through DR

- ME

- 06 the EPA

, the EPA proposes a PM/ PM 10 / PM 2. 5 limit of 2.0 lb/hr when the se engines operate at less than 50% load

. For the larger main engines, DR

- ME

- 07 and DR

- ME

- 08, the EPA proposes a PM/ PM 10 / PM 2. 5 l imit of 4.0 lb/hr when these engines operate at less than 50% load. All three limits were proposed by An a darko and reflect the emissions from the stack test results

. In addition, these limits will ensure that Anadarko com plies with their proposed modeling. Emission limits for engines operating above 50% were set in g/kw

- hr, while those below 50% were set in lb/hr. The lb/hr emission limit better reflects the fuel usage of the engines while operating at low loads.

Anadark o must comply with the limits of 40 CFR part 60 subpart IIII, as maintained in Condition 6.11 , and described in section 4.5.1 . All main engines operating within 10% of 100% peak load (or the highest achievable load) must comply with a PM/ PM 10 / PM 2.5 limit o f 0.15 g/kw

- hr.

Given the significant load variations required by the operations on the drillship and the information provided by the applicant and vendor, the EPA has determined an averaging period of 24 hours on a rolling basis is appropriate in this case. BACT will also include use ultra

- low sulfur diesel and work practice standards including good combustion practices and operating in accordance with the manufacturer’s specifications and LNE design.

Emergency Generator Engine and Emergency Air Compressor Engine : The BACT determination in Section 6.1.1 is also applicable for PM/PM 10 /PM 2.5

. In addition, BACT reduction of PM/PM 10 /PM 2 also includes use of ULSD.

Pump Engines and Third Party Engines : The BACT determination in Section 6.1.1 is also
ap plicable for PM/PM 10 /PM 2.5

. In addition, BACT for reduction of PM/PM 10 /PM 2 also includes use of ULSD.

Table 6

- 6: PM/PM 10 /PM 2.5 BACT Conclusions Emissions Unit ID BACT Control Technologies and PM/PM 10 /PM 2.5 BACT Limits* Main Diesel Generator Engines ( DR

- ME

- 01 thru DR

- ME

- 08 ) 40 CFR part 60, subpart IIII Standards, LNE D esign I ncluding Turbo charge r and Aftercoolers, and High Injection P ressure , ULSD, and G ood C ombustion P ractices ; PM/PM 10 /PM 2.5 limit for loads at or above 50% : 0. 40 g/kW

- hr ; PM/PM 10 /PM 2.5 limit for loads below 50 % for DR

- ME

- 01 through DR

ME

- 06: 2.0 lb/hr; PM/PM 10 /PM 2.5 limit for loads below 50% for DR

- ME

- 07 and DR

- ME

08: 4.0 lb/hr Emergency Generator Engine ( DR

- GE

- 01 ) LNE D esign I ncluding Turbo charge r and Aftercoolers, and High Injection P ressure , ULSD, and good combustion practices Emergency Air Compressor Engine ( DR

- AC

- 01 ) 40 CFR part 1039 EPA Tier 3 S tandards, ULSD

, and G ood C ombustion P ractices42

11/14/14 Anadarko BlackHornet PD OCS

- EPA

- R4020 Third Party Engines (DR

- TP

- 01 through DR

- TP

11 and DR

- TP

- 17 through DR

- TP

- 21) 40 CFR part 89 EPA Tier 2 S tandards, ULSD, and G ood C ombustion P ractices Third Party Well Evaluation Engines (DR

- TP

- 12 through DR

- TP

- 16) ULSD and G ood C ombustion P ractices

SV

- PE

- 01 thru SV

- PE

- 08 ULSD and G ood C ombustion P ractices *Short

- term limits are based on a 24

- hour rolling average

.

6.1. 4 GHG BACT Analysis for Internal Combustion Engines

The majority of GHG emissions from the diesel internal combustion eng ines are in the form of carbon dioxide (CO 2 ). CO 2 is formed in the combustion chamber as a result of complete combustion of diesel when the carbon in the fuel is converted to CO 2

. Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit
ap plication submitted in September 2013 supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014 , September 2, 2014, and September 10, 2014 :

1. Carbon Capture Storage (C CS); 2. Alternative/Biomass Fuel Sources; 3. CSNO x Emissions Abatement System; 4. Energy Efficiency; and 5. Good Combustion and Manufacturer Recommended Maintenance Practices.

The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options

After analyzing the five control technology options for the control of GHG emissions, three were eliminated as technically infeasible for all diesel internal combustion engines

. Below is a summary of the reasons for eliminating each of these options from further consideration in the top

- down BACT analysis for this project. For detailed descriptions of the control technologies and referen ces, please refer to the application submitted to the EPA in September 2013 and

s upplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, F ebruary 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014

.

CCS: T his control option is technically infeasible due to space constraints. The space needed for the equipment necessary to capture and separate CO 2 from engine exhaust is not available on the drillship. Furthermore, the mobile nature of the source renders atta chment to a fixed pipeline for CO 2 transport infeasible. Lastly, the injection of CO 2 in the deep sea has not been tested, and could significantly alter this ecosystem.

Alternative/Biomass Fuel Sources: The current supply market for biodiesel is not stable enough to be considered a viable option for this project. ( Biodiesel was the only fuel addressed).43

11/14/14 Anadarko BlackHornet PD OCS

- EPA

- R4020 CSNO X Emissions Abatement System: This technology is currently in the licensing and commercial demonstration phase of development. While this technol ogy is commercially available for certain types of marine uses, it has not been demonstrated in practice for use aboard a dynamically positioned mobile off shore drilling unit (i.e., vessels with variable load engines); therefore, it is technically infeasi ble for this project.

The EPA agrees with the applicant that these control technologies are not technically feasible for the reasons discussed above.

Steps 3/4/5:

The applicant iden tified energy efficiency operation and good combustion practices as BACT

. Energy efficiency for the main engines will be accomplished through the use of the Parametric Emission Monitoring System (P E MS) and the inherent LNE design of the engine, identified in Section 6.1.1; this system is designed to optimize combustion. In add ition, the main engines are some of the newest available. The LNE design of the emergency generator will also promote energy efficiency. The operation of the emergency air compressor engine, the third party engines, the third party well evaluation engines, and stimulation vessel pump engines per the manufacture design will ensure energy efficiency.

Main Engines: The EPA proposes three limits for GHG emissions dependent on the engine load and based on the stack t est data submitted to EPA on July 15, 2014

. For all engines , the EPA
p roposes an emission limit of 856 g/kw

- hr when the engines are operating at or above 50% load. This limit is based on the 95% confidence interval of the highest emitting engine operating at 50% load, for thirty of the data points

. For the smaller main engines, DR

- ME

- 01 through DR

ME

- 06, the EPA proposes a CO 2 limit of 4,700 lb/hr when the se engines operate at less than 50% load

. This is based on the 95% confidence interval for all small engines. For the larger main engines, DR

- ME

- 0 7 and DR

- ME

- 08, the EPA proposes a CO 2 l imit of 8,299 lb/hr when these engines operate at less than 50% load. This limit was proposed by An a darko and reflects the emissions from the stack test results

. Emission limits for engines operating above 50% were s et in g/kw

- hr, while those below 50% were set in lb/hr. The lb/hr emission limit better reflects the fuel usage of the engines while operating at low loads.

Given the significant load variations required by the operations on the drillship and the informa tion provided by the applicant and vendor, the EPA has determined an averaging period of 24 hours on a rolling basis is appropriate in this case. BACT will also include work practice standards including good combustion practices and operating in accordance with the manufacturer’s specifications and LNE design

. Emergency Generator Engine and Emergency Air Compressor Engine : The BACT determination in Section 6.1.1 is also applicable for GHGs

. Pump Engines and Third Party Engines : The BACT determination in Section 6.1.1 is also applicable for GHGs

.44

11/14/14 Anadarko BlackHornet PD OCS

- EPA

- R4020 After taking into account energy, economic

, and environmental impacts, the EPA determined BACT for the diesel engines on the BlackHornet and for the pump engines on the stimulation

v essel as summarized in Table 6

- 8

. The respective emission limits are based on 40 CFR 98 Subpart C.

Table 6

- 8 : GHG BACT Conclusions Emissions Unit ID BACT Control Technologies and CO 2 e Limits * Main Diesel Generator Engines ( DR

- ME

- 01 thru DR

- ME

- 08 ) P E MS, LNE D esign I ncluding Turbo charge r and Aftercoolers, and High Injection P ressure , and Good Combustion Practices ; CO 2 limit for loads at or above 50%: 856 g/kW

- hr ; CO 2 limit for loads below 50% for DR

- ME

- 01 through DR

- ME

- 06: 4

, 700 lb/hr ; VOC limit for loads below 50% for DR

- ME

- 07 and DR

- ME

- 08: 8

, 299 lb/hr Emergency Generator Engine ( DR

- GE

- 01 ) LNE D esign I ncluding Turbo charge r and Aftercoolers, and High Injection P ressure and G ood C ombustion P ractices Emergency Air Compressor Engine ( DR

- AC

- 01 ) G ood C ombustion P ractices Third Party Engines (DR

- TP

- 01 through DR

- TP

11 and DR

- TP

- 17 through DR

- TP

- 21) G ood C ombustion P ractices

Third Party Well Evaluation Engines (DR

- TP

- 12 through DR

- TP

- 16) G ood C ombustion P ractices

SV

- PE

- 01 thru SV

- PE

- 08 G ood C ombustion P ractices *Short

- term limits are based on a 24

- hour rolling average

.

6.2 BACT Analysis for Third Party Flowback Boiler

The BlackHornet will operate a small 8 MMBtu/hr diesel fired flowback boiler (DR

- TP

- 22 ) during well completion activities. The boiler is subject to BACT review for emissions of NO x , CO, VOC, PM/PM 10 /PM 2.5 , and GHGs

. Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit
ap plication submitted in September 2013 supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014 :

1. Flue Gas Recirculation (NO x only) ; 2. Low NO x Burners ; 3. Good Combustion Practices ; and 4. U LSD

.45

11/14/14 Anadarko BlackHornet PD OCS

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- R4020 The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options

After analyzing the four control technology options for the control of NO x emissions, two were eliminated as technically infeasible (options 1 and 2). Below is a summary of the reasons for eliminating each of these options from further consideration in the top

- down BACT analysis for this project. For detailed descriptions of the control technologies and references, please refe r to the application submitted to the EPA in September 2013 supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2 014, July 15, 2014, September 2, 2014, and September 10, 2014

.

Flue Gas Recirculation: This control technology require s retrofitting the boiler which would demand significant space reassignment. This is best suited for new units since it will require ins tallation of ductwork, recirculation fans, air foils, and controls. This technology is technically infeasible for the flowback boiler on the BlackHornet which has limited space and is already constructed

.

Low NO x Burners: This te chnology produces longer flames and is therefore inappropriate for retrofit on smaller boilers.

The EPA agrees with the applicant that these control technologies are not technically feasible for the reasons discussed above.

Steps 3/4/5:

The applicant plans to operate the flowback boiler 1

, 152 MMBtu per year and 144 hours per
year

. Given the limited use of this emission unit, the EPA has determined that BACT is more appropriately implemented as work practice standards including good combus tion practices based on the use of the most recent manufacturer’s specifications issued for this boiler at the tim e that the boiler is operating and use of ULSD.

6.3 BACT Analysis for Boom Flare

The BlackHornet will operate a boom flare (DR

- TP

- 23) subjec t to BACT review for emissions of NO x , CO, VOC, PM/PM 10 /PM 2.5 and GHGs. The boom supports the flare system and the associated piping. The boom primarily reduces heat radiation by locating flames far away from
t he drillship and person ne l. The boom flare will be leased from a third party vendor. Pilot gas assistance is not necessary for certain types of boom flares. If the boom flare leased from the vendor requires pilot gas assistance, the emissions resulting from pilot gas assistance will be negligible. The flaring operation will take place primarily during the well completion operations, and not during drilling.

Step 1: Identify all available control technologies46

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- R4020 The applicant identified the following available control technologies for NO x , CO, VOC, an d PM/PM 10 /PM 2.5 , and GHGs in their OCS permit application submitted in September 2013 and supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014 , September 2, 2014, and September 10, 201 4 :

1. Comply with 40 CFR 60.18 ; 2. Proper Equipment Design and Maintenance; 3. Maintain Presence of Flame at Flare Tip at all times; 4. Flare Gas Minimization; and 5. Good Combustion Practices

.

In addition the EPA further identified the following available control that is also referenced in our administrative record ( see Section 9.0 ) :

1. Flare Tip

. The EPA believes that the preceding list s identify all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options

The flare gas minimization and flare tip control options were determined to be technically in feasible and for the control of NO x , CO, VOC

, PM/PM 10 /PM 2.5 , and GHG. For detailed descriptions of the co ntrol technologies and references, please refer to the application submitted
to the EPA in September 2013 and supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014,

a nd September 10, 2014 , and the additional material found in the administrative record c ited in Step 1

.

Flare Gas Minimization : This requires a reconfiguration of the piping during a well control situation, and require s rerouting gas that would be directed to the flare back to the process which is infeasible during the offshore drilling process.

Flare Tip: Flare tips provide enhanced mixing by promoting an adequate air supply for efficient combustion. The type of flare tips available range dependi ng on the fuel stream (i.e., steam

assisted, air

- assisted, pressure

- assisted, or non

- assisted). The type of fuel and the pressure of the stream dictate which flare tip is appropriate. Since Anadarko will conduct an exploratory drilling project, the type of fuel and the amount of gas in the well are unknown. Therefore, this project cannot use a specified flare tip because the amount and pressure of the fuel cannot be determined beforehand and may vary during the project.

The EPA agrees with the applicant t hat these control technologies are not technically feasible for the reasons discussed above.

Steps 3/4/5:47

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- R4020 Based on a review of the available control technologies, the EPA has determined that BACT for NO x , CO, VOC, PM/PM 10 /PM 2.5

, and GHG emissions is more appropriately implemented as work practice standards including maintaining c ompliance with 40 CFR 60.18, u se of good combustion practices, and proper equipment design and maintenance presence of a flame at the flare tip at all times

. 6.4 BACT Analysis for Storage Tanks

The BlackHornet , the supply boat, and the anchor handling boat have various types of storage tanks subject to BACT revi ew for VOC emissions. The tank loading emissions for the supply boat and anchor handling boat qualify as regulated sta tionary source activities. Onboard the BlackHornet there are diesel fuel, helicopter fuel, and condensate storage tanks. The following tanks on the BlackHornet are included in thi s analysis: DR

- FT

- 01 through

- 19 (diesel fuel and helicopter fuel storage tan ks) and DR

- TP

- 24 through

- 26 (condensate tanks used for well completion activates). The tanks on the work boat are SB

- DT

- 01 through

- 15 (diesel fuel storage tanks). The tanks on the anchor handling boat are AB

- DT

- 01 through

- 19 (diesel fuel storage tanks). The fuel in these tanks will generate VOC emissions resulting from both breathing and working ( i.e. , loading) losses.

Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit applic ation submitted in September 2013 supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014 :

1. Vapor Recovery Unit ; 2. Thermal Oxidation System ; 3. Adsorption System ; 4. Internal Floating Roof or External Floating Roof ; 5. Submerged Fill Pipe ; and 6. Good Maintenance Practices

. The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options

After analyzing the above control technologies, all of the options were eliminated as technically infeasible for control of VOC emissions from the tanks , except for good maintenance practices

. Below is a summary of the reasons for eliminating each of the above options from further consideration in the top

- down BACT analysis for this project. For detailed descriptions of the control technologies and references, please refer to the application submitted to the EPA in September 2013 and supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014

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- R4020 Vapor Recovery Unit: Th is option is technically infeasible due to limited space availability.

Thermal Oxidation System: This option is technically infeasible due to limited space availability.

Adsorption System: This option is not effective for controlling low concentrations o f VOC generated by dies el and base oil storage tanks. Furthermore, this option is technically infeasible since it would require additional space that is not available on the vessels.

Internal Floating Roof or External Floating Roof: This option is not eff ective for controlling VOC emissions from stored liquids of low vapor pressures, such as diesel oil. Furthermore, this option is technically infeasible since it would require additional space that is not available on the vessels.

Submerged Loading: This technology is technically infeasible due to limited space availability.

The EPA agrees with the applicant that these control technologies are not technically feasible for the reasons discussed above.

Steps 3/4/5:

Based on a review of the available control technologies, the EPA has determined that BACT is use of good maintenance practices. This will limit tank leakage and excessive VOC emissions. The amount of VOC emissions emitted from the tanks is contingent upon both the fuel type and the amount of fuel. Therefore, the applicant will maintain records of the tank identification, volume, and fuel type stored. For the BlackHornet

, the EPA has determined that the fuel tanks DR

- FT

- 01 through

- 19 (diesel fuel and helico pter fuel storage tanks) wi ll have a VOC BACT limit of 0.69 tons per year and that the condensate tanks DR

- TP

- 24 through

- 26 wil l have a VOC BACT limit of 9.65 tons per year. The EPA has determined that the diesel fuel storage tanks (SB

- DT

- 01 through

- 15) on the supply boat will have a VOC BACT limit of 0. 0 11 tons per year and that the diesel fuel storage tanks (AB

- DT

- 01 through

- 19) on the anchor handling boat wi ll have a VOC BACT limit of 0.10 tons per year. All of these emissions limits are on a 12

- month rolling total basis. These emission limits reflect the modeling results from EPA ’s TANKS 4.0.9d program found in the September 2013 application.

6.5 BACT Analysis for Cement and Mud Mixing Operations

The BlackHornet has cement and mud mixing operations (DR

- DC

- 01 through DR

- DC

- 04) subject to BACT review for emissions of PM/PM 10 /PM 2.5

.

Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit applic ation submitted in Sep tember 2013 supplemental material submitted on September 18,49

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- R4020 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014 :

1. Dust Collector

.

A review of the RBLC database did not reveal any other potential control technologies for the mud and cementing operations aboard the BlackHornet

. The proposed dust collectors are cyclones that capture particulate matter and function as a control technology.

The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options

The applicant determined that use of dust co llectors i s technically feasible. For a detailed description of the control technology and references, please refer to the application submitted to the EPA in September 2013 and supplemental material submitted on September 18, 2013, November 26, 2013, Dece mber 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014

. Steps 3/4/5:

Based on a review of the available control technologies, the EPA has determined that BACT is the use of dust collector s with proper maintenance an d operation . DR

- DC

- 01 through DR

- DC

- 04 are not closed systems and no pressure reading can be taken. Therefore, Anadarko will ensure proper maintenance and operation of the dust collectors in accordance with the most recent manufacturer ’s specifications at th e time that the se dust collectors are operating under this permit . In addition

, Anadarko will ensure that the dust collector bin is not over capacity, and report any times where there is a high

- level alarm at which time the operator will investigate the cause and take corrective action.

6.6 BACT Analysis for Mud Degassing

The BlackHornet has mud degassing operations (DR

- VG

- 01 through DR

- VG

- 0 4 ) subject to BA CT review for emissions of VOCs and GHGs

. Step 1: Identify all available control technologies

A review of the RBLC database did not reveal any potential control technologies to capture and

co ntrol fugitive emissions from the mud degassing operations aboard the BlackHornet

. However, the mud degassers will vent through two control technologies. The vents are equipped with a vacuum degasser that will operate during normal operations. In addition, when a large amount of gas breaks out of the mud then the gas will pass through a vertical separator with baffles.

1. Best Management Practices.50

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- R4020 The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options

Best m anagement p ractices , the only control technology identified, was determined technically feasible

. For a detailed description of this control technolog y and references, please refer to the application submitted to the EPA in September 2013 and supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014

. Steps 3/4/5:

Based on a review of the available control technologies, the EPA ha s determined that BACT for VOC and GHG emissions from mud degassing is the use of best management practices and manufacturer recommended maintenance practices

. The EPA has determined the mud degassing operations will have a VOC BACT limit of 5. 36 TPY combi ned on a 12

- month rolling total basis. The EPA has determined the mud degassing operations will have a VOC BACT limit of 271 TPY of CO 2 e combined on a 12

- month rolling total basis , based on the Year 2005 Gulfwide Emission Inventory Study, US Department of Interior, Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, December 2007, referenced in Appendix B of the September 2013 application.

6.7 BACT Analysis for Painting Operations

The BlackHornet has painting operations (DR

- PO

- 01) subject to BACT review for emissions of VOC and PM/PM 10 /PM 2 .5

. Step 1: Identify all available control technologies

The application states that a review of the RBLC database did not reveal any potential control technologies for emissions from the painting operations aboard the BlackHornet . However, Anadarko identified four differe nt methods to apply paint in September 2 013 supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014 :

1. air assisted spray gun ; 2. airless spray gun ; 3. roller or brush ; and 4. best management p ractices.

The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options51

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- R4020 For detailed descriptions of the con trol technologies and references, please refer to the application submitted to the EPA in September 2013 and supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, an d September 10, 2014

.

Roller or Brush: T he use of a roller brush is unsuitable for marine conditions for a variety of reasons. The marine coatings must be applied at a designated thickness that this method cannot insure. Also, the roller method does not a chieve a good film continuity required for marine coatings. Lastly, application technology cannot reach all required areas aboard the drilling vessel.

Step 3: Rank the remaining control technologies by effectiveness

The control options not eliminated as technically infeasible in Step 2 of the top

- down BACT analysis were then ranked by effectiveness. Table 6

- 7 lists the remaining control technologies with their respective transfer efficiencies that have not been ruled out as technically infeasible options.

Table 6

- 7: Step 3

- VOC Control Technologies Ranked by Effectiveness for the Painting Operations

Rank Paint Application Method Transfer Efficiency 1 Airless spray gun 50%

- 80% 2 Air assisted spray gun 30%

Steps 4/5:

The airless spray gun is used to paint large deck areas or bulkheads , and an air assisted spray gun is used to paint smaller areas (e.g. , piping, brackets, and other multi

- angle items )

. The VOC contents of a coating dictate the preferred application area, and the method of operation. Low VOC paints tend to be very thick, which makes it difficult to apply to small areas. These paints are better for large areas.

Based on a review of the a vailable control technologies, the EPA has determined that BACT for VOC and PM/PM 10 /PM 2 emissions from painting is best management practices that include, but

are not limited to

, down spraying of paint and use of a containment system such as a shroud or a barrier around the section of the ship being painted whenever practical to prevent the airborne particulate matter from drifting into the atmosphere, and proper storage of coatings (and thinners) in non

- leaking con tainers

. The EPA has determined the painti ng operations will have an operating limit of 5,200 and 1,300 gallons per calendar year of p rimer and thinner, respectively , and Anadarko will use an airless spray gun with transfer efficiency of 50% or greater; where it is not practical to use an airless spray gun, the permittee may use an air assisted spray gun with a transfer efficiency of 30% or greater. The limits on the total gallons per year that A nadarko will use are based on their estimated annual usage.52

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- R4020 6.8 BACT Analysis for Welding Operations

T he BlackHornet has welding operations (DR

- WO

- 01) subject to BACT review for emissions of PM/PM 10 /PM 2 .5

. Step 1: Identify all available control technologies

The applicant identified the following available control technologies in the supplementa l informa tion submitted in September 2013 supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014 :

1. Emission Limit/Welding Rod Usage Limit ; 2. Best Manageme nt Practices ; 3. Routing to Control Device ; and 4. Body Shop

. The EPA believes that the preceding list identifies all relevant and available control technologies as of the date of this preliminary determination.

Step 2: Eliminate technically infeasible control options

After analyzing the above control technologies, options three and four were eliminated as technically infeasible for control of PM/PM 10 /PM 2 .5 emissions from welding operations. Below is a summary of the reasons for eliminating these options from further consideration in the top

down BACT analysis. For detailed descriptions of the control technologies and references, please refer to the application submitted to the EPA in September 2013 and supplemental material submitted on September 18, 2013, November 26, 2013, December 5, 2013, February 11, 2014, July 15, 2014, September 2, 2014, and September 10, 2014

. Routing to Control Device: The welding operations generate fugitive emissions tha t a control device canno t adequately capture ; therefore, this control technology is technically infeasible.

Body Shop: This control technology is technically infeasible due to space constraints.

Steps 3/4/5:

Based on a review of the available control technologies, the EPA has determined that BACT is requiring Anadarko to follow current manufacturer’s recommendations for all equipment used in welding operations at the time that that welding occurs under this pe rmit, including but not limited to, recommendations regarding voltage levels . This will limit excess PM/PM 10 /PM 2 .5 emissions. The applicant will maintain records of the types and amounts (in pounds) of welding rods used annually

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- R4020 6.9 BACT Analysis for Fugitive Emissions

The applicant did not i dentify fugitive emissions in the BACT analysis potion of their permit application. However, based on similar permit applications

, the EPA has determined that BACT is good maintenance practices to minimize fugitive emissions, including but not limited to minimizing the release of emissions from valves, pump seals, and connectors

. The applicant will perform a daily check and report any leaks and corrective action taken.



## 7.0 Summary of Air Quality Impact Analyses

7.1 Required Analyses

The PSD rules at 40 CFR § 52.21(k) require the permit applicant to demonstrate that, for all regulated air pollutants that would be emitted at or in excess of the significant emissions rates provided in 40 CFR § 52.21 (b)(23)(i), the allowable emission increases from a proposed new major stationary source or major modification, in conjunction with all other applicable emission increases or reductions at the source, would not cause or contribute to a violation of any NAA QS nor cause or contribute to a violation of any applicable “maximum allowable increase” over the baseline concentration in any area (known as PSD increments). 4 The ambient air quality impact analysis must be based on air quality models, databases, and oth er requirements specified in 40 CFR part 51, Appendix W, Guideline on Air Quality Models.

As discussed in Section 4 .0 above (Table 4

- 1), the estimated potential to emit of CO, NO X
, PM 10 , PM 2.5 , VOC and GHG from the proposed project are above the PSD signi ficant emission rates

. NO X is a measured pollutant for NO 2 and ozone. Therefore, the CO, PM 10 , PM 2.5 , NO 2 , and ozone NAAQS and the PM 10 , PM 2.5 , and NO 2 PSD increments are relevant to the air quality impact assessment

. There are no NAAQS or increments for GHG emissions.

As required by the May 8, 2008, final rules governing NSR implementation for fine particulate matter, 73 Fed. Reg. 28,321 (May 16, 2008), PSD permits must address directly emitted PM 2.5 as well as the pollutants responsible for secondary fo rmation of PM 2.5 which include SO 2 , NO X , VOC, and ammonia. Therefore, Anadarko must address compliance with the 24

- hour and annual PM 2.5 NAAQS considering both direct emissions and secondary contributions.

Under 40 CFR § 52.21(m), a PSD permit applicatio n must include an air quality analysis in connection with the demonstration required by 40 CFR §52.21(k). For each pollutant for which a NAAQS or PSD increment exists, 40 CFR § 52.21(m)(1)(iv) requires the analysis to include at least one year of pre

- const ruction ambient air quality monitoring data, unless the EPA approves a shorter monitoring period (not less than four months). 40 CFR § 52.21(i)(5)(i) allows exemption from the requirement for pre

- construction ambient monitoring if the net emissions increas e of a pollutant from the proposed source or modification would cause air quality impacts less than the ambient monitoring thresholds (i.e., Significant Monitoring Concentrations) listed in 40 CFR § 52.21(i)(5)(i), which are provided in Table 7

- 1 5 . 40 CFR § 52.21(m)(2) requires post

-

4 The maximum allowable PSD increments are listed in 40 CFR § 52.21(c).
5 Due to the recent vacatur of the its significant monitoring concentration for PM 2.5 (see Section 7.2), this exemption is not ap p licable for PM 2.5 .54

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- R4020 construction ambient air quality monitoring if the EPA determines it is necessary to determine the effect that emissions from the source or modification may have on air quality.

An additional impact analysis is required by 40 C FR § 52.21(o), including an analysis of the impairment to visibility, soils

, and vegetation that would occur as a result of the proposed project or that would occur as a result of any commercial, residential, industrial

, and other growth associated with th e source. Analysis for vegetation having no significant commercial or recreational value is not required.

For sources impacting Federal Class I areas, 6 40 CFR § 52.21(p) requires the EPA to consider project impacts to PSD increments in these areas and any demonstration by the Federal Land Manager (FLM) that emissions from the proposed source would have an adverse impact on air quality related values, including visibility impairment. If the EPA concurs with the demonstration, the rules require that the EPA shall not issue the PSD permit.

7.2 PSD Class II Air Quality Impact Assessment

An air quality impact assessment was performed for the operation of the BlackHornet deepwater drilling vessel and associated support vessels. The modeled operating scenario was that which produced the worst

- case impact.

As discussed in Section 4.0, the estimates of maximum annual emissions of NSR regulated pollutants from the BlackHornet drilling vessel and associated supporting vessels resulted in estimated emissions of CO, PM 10 , PM 2.5 , VOC, and NO X greater than the PSD significant emissions rate. Hence, CO, PM 10 , PM 2.5 , and NO 2 are subject to ambient impact assessment. The VOC and NO X pollutants are measured pollutants for ozone and precursors for PM 2.5 . Therefore, impact as sessments are also provided for ozone and secondary PM 2.5

. The modeling procedures took into consideration the January 22, 2013 decision by the federal Court of Appeals for the District of Columbia Circuit (D.C. Circuit) concerning use of the PM 2.5 signif icant monitoring concentration (SMC) and significant impact levels (SIL) as the basis for exemption from pre

- construction air quality monitoring and cumulative NAAQS and PSD increment compliance modeling. See Sierra Club v. EPA , 705 F.3d 458 (D.C. Cir. 201 3). The D.C. Circuit vacated and remanded the PM 2.5 SILs. Accordingly, project impacts less than the SILs cannot serve as the sole justification for eliminating cumulative NAAQS and PSD increment compliance modeling. While permit applicants may continue to use the PM 2.5 SILs in their analysis, they must provide additional information and justification to support a conclusion that a project’s impacts will not cause or contribute to a NAAQS or PSD increment exceedance.

The court also vacated the PM 2.5 SMC. A s a result of the court’s decision, project impacts less than the PM 2.5 SMC can no longer be used to exempt the project from pre

- construction ambient air quality monitoring. However, permit applicants may use existing air quality observations in lieu of pr e

- construction monitoring if supporting information demonstrates that the existing

6 Class I areas are defined in 40 CFR § 52.21(e). Mandatory Class I areas (which may not be redesignated to Class II or III) ar e international parks, national wilderness areas larger than 5,000 acres, memorial parks larger than 5,000 acres, and national parks larger than 6,000 acres.55

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- R4020 ambient air quality data provides representative or conservative ambient concentrations for the impact area.

The ambient impact modeling was performed using dispersion and transport models and modeling techniques that follow the EPA regulatory guidelines ( see 40 CFR Part 51, Appendix W) and applicable guidance memorandum ( see Support Center for Atmospheric Modeling (SCRAM); http://www.epa.gov/scram001/).

Since the proposed drilling will occur at several locations, the worst case emissions were assumed to be located at the drilling site where the greatest onshore and near shore impacts could occur. The OCS project impact area for the Class II area analysis, the area containi ng modeling receptors, was established 25 nautical miles from any state’s seaward boundary, extending shoreward until the project’s estimated impact is less than the significant impact level. For this project the nearest Class II area receptor is more than 50 km from the closest drilling location.

7.2.1 Air Quality Model Selection

Because the closest Class II area receptor is more than 50 km from the nearest proposed drilling location (i.e., limited to 100 nautical miles from shore in BOEM Central Planning Area and 125 nautical miles in the Eastern Planning Area) , the air quality impact analyses involve long

- range transport and dispersion conditions. The EPA’s preferred model for long

- range transport assessments (CALPUFF/CALMET modeling system Version 5.8 ( release 070623)) was selected to estimate potential impacts in the OCS Class II area. It should be noted that this same EPA

preferred long

- range transport and dispersion model is appropriate for the PSD Class I impact assessment. In addition, the Class II coherent plume visibility assessment was performed using the VISCREEN model (Version 88341). Figure 2

- 1 provides the modeling area used in the PSD Class II and Class I assessments as well as locations of other significant features ( e.g ., nearest PSD Class I area s ).

7.2.2 Characteristics of Modeled Operational Scenarios

The primary PM 10 , PM 2.5 , and NO X emission sources associated with the proposed exploration drilling activities are the diesel

- fired engines on the drilling vessel. Additionally, the OCS air

r egulations require emissions from vessels servicing the OCS sources while en route to and from the source when within 25 nautical miles of the drilling operation to be considered direct emissions from the OCS source . Therefore, the impacts from the associated fleet of vessels that support the primary drilling activity were included.

The BlackHornet and support vessel emission sources include the following:

• Main Diesel Generator Engines (8),

• Emergency Generator Eng ine (1),

• Emergency Air Compressor (1),

• Life Boat Engines ( 6 ),

• Fast Rescue Craft Engine (1),

• Dust Collectors (3),

• Mud Degassers (4)/ Degassing Vent s ( 3 ),56

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- R4020 • Dust Collectors (3),

• Fuel Storage Vessels (18),

• Fugitive Emissions (diesel fuel system),

• Flowback Boiler (1),

• Boom Flare (1),

• Cement and Mud Mixing,

• Third Party Engines (21)

,

• Painting and Welding Operations , and

• Support Vessels (i.e., barges, tug boat, evaluation vessel, supply boats)

.

The basis for the maximum short

- term (1 to 24 hour) and long

- term (annu al) emission rates for these sources are discussed below. The maximum hourly emission rates were conservatively used in all modeled impact assessments. Additionally, all NO X emissions were conservatively modeled to represent NO 2 emissions.

Six operating scenarios that could occur during drilling, well completion, and maintenance phases were considered. Because the exact emission units and their specifications were not available for each scenario, the potential worst

- case emission units and their maximum p otential emissions for each scenario were considered. The scenario providing the maximum emissions was used in this ambient impact assessment. This provides Anadarko sufficient operational flexibility to utilize various “equivalent” equipment in each scena rio. These scenarios were evaluated to determine which scenario would result in maximum hourly, 24

- hour, and annual potential to emit emission rates.

The basis of BlackHornet ’s modeled maximum short

- term (1

- hour to 24

- hour) emissions and annual emissions are provided in the August 2013 BlackHornet PSD/Title V Permit Application Operations in the Eastern Gulf of Mexico

, the August 2013 Air Quality Dispersion Modeling Analysis Report Black

Hornet EGOM Drilling, Completion, and Maintenance document

, and the supplemental material submitted on November 12, 2013, February 5, 2014, February 7, 2014, and July 18, 2014

, contained in the Administrative Record

.

Anadarko is requesting authorization f or the BlackHornet drilling vessel, and its associated support fleet, to operate in any of Anadarko ’s lease blocks located within the eastern Gulf of Mexico (EGOM) as listed in Section 2.2 of this document and any additional lease block in the EGOM whose n earest drilling location is at least 185 km (100 nautical miles) from the nearest shore in the Bureau of Ocean Energy Management (BOEM) Central Planning Area and more than 232 km (125 nautical miles) from the nearest shore in the BO E M Eastern Planning Area

. To ensure the modeled worst

- case impact conditions were include d , all impact modeling estimates were performed with the drilling vessel located at the northwest corner of the closest lease block to the shoreline and to the nearest PSD Class I area (Breto n National Wildlife Refuge (NWR)).

The modeling locations of the associated support vessels for the BlackHornet can also affect the modeled impacts. The modeled worst

- case impact location for the support boats is 25 nautical miles from the main drilling vessel in the direction of the closest receptor ( i.e. , toward the Breton NWR). This support vessel location was used for all impact assessment s. For dispersion analysis the maximum total emissions (i.e., drillship and support vessels) for each pollutant we re57

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- R4020 considered. The modeled emission rates represent the worst

- case combination among the different operating scenarios.

In addition to emission rates, the modeling analysis requires information regarding stack heights and other exit parameters that characterize exhaust flow from emission points. These release characteristics have an important influence on the results of the analysis. Exhaust stack parameters for the BlackHornet drilling vessel, as well as the support vessels

, assumed all emissions emitted through a single stack on the drillship and support boat. The stack parameters were based on the main engine of the drill ship and the characteristics of the worst

- case support boat emissions. Because of the long distance to the nearest modeled receptor, the vessel orientation and building downwash considerations were not considered as they should not significantly affect the modeled impacts.

7.2.3 Meteorological Data

The three

- year meteorological dataset (2001

- 2003) developed by the Visibility Improvement State and Tribal Association of the Southeast (VISTAS) was used for the PSD Class II and Class I impact assessments. This 4

- km VISTAS Domain 2 dataset was developed by the Federal Land Managers using the approved regulatory version of CALMET (Version 5.8, Level 070623). The dataset was developed using observations from 100 to 109 surface stations, 10 upper air stations, nine overwater stations and 92 to 103 precipitation stations, depending on the meteorological year. This sub

- domain includes a 50 km buffer past the Breton Class I area, far enough east for receptors along western Florida, and far enough south to include a 100 km buffer around the drilling location to allow re

- circulation of puffs.

7.2.4 Building Downwash

Building downwash accounts for the effect of nearby structures on the flow of emissions from their respective release structures. However, as noted above, buil ding downwash effects were not included in the modeling as they will not significantly affect concentrations when the nearest receptors are located more than 100 km from the location of the emissions. Because of this, FLMs typically do not request downwash be included in long

- range PSD Class I impact
assessments.
7.2.5 Receptor Locations

The seaward boundaries and Air Quality Control Regions for Louisiana, Mississippi

, and Alabama extend for three nautical miles offshore and for nine n autical miles offshore Florida. For the Anadarko Class II modeling analysis, discrete receptors were located 25 nautical miles from the seaward boundaries of Louisiana, Mississippi, Alabama, and Florida. The receptors were placed at 1

- km intervals but controlling concentrations were resolved to 100m, if needed. Because all of these receptors are over water, terrain elevations were assigned an elevation of 0 m ( i.e., sea level) for the Class II impact analysis

. Each Class I area receptor was obtained from the National Park Servic e website at: http://www.nature.nps.gov/air/Maps/Receptors/index.cfm.58

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- R4020 7.2.6 Project Impact Assessment

This section presents the estimated ambient concentrations associated with the emissions from the proposed BlackHornet exploration activities. If a pollutant’s estimated impact exceeds an EPA SIL for that pollutant, the impacts of the facility must be included with the impacts of other increment

- consuming sources to evaluate total increment consumption. Exceeding a SIL a lso requires that the evaluation of compliance with the applicable NAAQS take into account background concentrations and the contributions of other regional sources

. The SILs are screening values that have been used since 1980 to identify de minimis impa cts. However, as discussed above, on January 22, 2013, the D.C, Circuit vacated the PM 2.5 SIL and SMC provisions adopted in the EPA’s PSD Regulations (40 CFR 51.166 and 40 CFR 52.21). As discussed below, the EPA’s review of Anadarko ’s application is consis tent with the D.C. Circuit’s decision.

The proposed project ’s worst

- case hourly emissions from the BlackHornet drilling vessel, as well as the associated support vessels, were modeled for comparison to the SMC and SIL for NO 2 , PM 10 , and PM 2.5 . The maximum modeled project concentrations at the discrete 25

- nautical mile receptors were compared to the PSD Class II SILs for NO 2 , PM 10 , and PM 2.5 . Similarly, the maximum modeled pollutant concentrations at the discrete 25

- nautical mile receptors were compared to the SMC for these pollutants.

The impact modeling results are provided and compared to the SIL and SMC in Table 7

- 1. Because all maximum predicted NO 2 , PM 10 , and PM 2.5 concentrations are less than the SIL, the project’s estimated impacts are not considere d to cause or contribute to a violation of the associated NAAQS or PSD increments. Furthermore, all maximum predicted concentrations are also much less than the SMC; therefore, no pre

- construction ambient monitoring is required

.59

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- R4020 Table 7

- 1 Maximum Modeled PSD Class II Area Concentrations SIL Comparison

(Receptors 25 Nautical Miles from Shoreline)

Pollutant Averaging Period BlackHornet Max. Concentration (ug/m 3 ) Significant

Impact Levels (ug/m 3 ) Significant

Monitoring Concentrations (ug/m 3 ) NO 2 a 1

- hour b 5.04 7.5 None Annual 0.09 1.0 14
PM 2.5 24

- hr b 0.12 1.2 c V acated Annual 0.009 0.3 c None PM10 24

- hr 0.14 5 .0 10

Annual 0.01 1.0 None CO 1

- hour 13.66 2,000 None

8

- hour*

- 500 575

a Annual NO 2 was conservatively assumed to be 100 percent NO x . One

- hour NO 2 modeled value provided is three year average of the maximum daily 1

- hour NO X concentration at each receptor with 100 percent NO 2 conversion.

b Maximum (100 percentile) values are provided not 98 th percentile.

c The PM 2.5 , SIL, and SMC were vacated in January 2013. *The CO 8

- hour SIL is 500 ug/m 3

. Because the modeled 1

- hour concentration is below the CO 8

- hour SIL, the 1

- hour modeling results can be used to demonstrate compliance with the 8

- hour SIL
The vacatur and remand of the PM 2.5 SIL resulted in a need for additional demonstration that the use of the SIL is appropriate to identify insignificant impacts. Similarly, the SMC was vacated so
pre

- construction ambient air quality monitor is requi red. Applicants may submit existing ambient air quality data collected from existing monitoring networks in lieu of pre

- constr uction monitoring if such data are demonstrated to be representative or conservative for the impact area.

Anadarko reviewed the available PM 2.5 air quality monitoring data for the EGOM. Although there are no existing PM 2.5 measurements in the vicinity of Anadarko ’s lease blocks, there are a number of shore

- based monitors. Because of the scarcity of PM 2.5 sources in the EGOM and the project’s large distance from land

- based sources, the background ambient PM 2.5 concentration s in the EGOM OCS are expected to be lower than any onshore concentrations. Therefore, the existing onshore ambient monitoring data used in the application

, provid e s conservative background ambient PM 2.5 concentrations for the project location. The reported maximum PM 2.5 24

- hour and annual Design Values from the 18 existing shore

- based monitors for the 2009

- 2011 period were 28 and 10.4 ug/m 3 , respectively.

The PSD PM 2.5 24

- hour NAAQS is 35 ug/m 3 and the PSD Class II SIL is 1.2 ug/m 3 . The annual PM 2.5 NAAQS is 12 ug/m 3 and the Class II SIL is 0.3 ug/m 3 . The difference between the PM 2.5 NAAQS and the selected conservative ambient background concentrations are larger than the PM 2.5 Class II SILs. The fact that the maximum impacts from project emissions are substantially less than the SILs ( i.e., Table 7

- 1 Class II maximum project impacts are 10.0 % of the 24

- hour and 0. 3 % of the annual PM 2.5 SIL) provides further suppor t for the use of the SILs in this application. Hence, it is reasonable to conclude that this proposed source with a PM 2.5 impact below the PM 2.5 , SIL values will not cause or contribute to a violation of the PM 2.5 NAAQS.60

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- R4020 In terms of the PSD Class I areas where compliance with the PSD increments are of concern, the SILs are used as a screening tool to assess whether a full cumulative Class I increment assessment is needed. The PM 2.5 increments became effective relatively recently (Major Source Baseline date of October 20, 2010; trigger date of October 20, 2011). Because of different meteorological conditions, PSD increment consuming emissions from outside the EGOM would not affect a Class I area at the same time as emissions originating from the EGOM. Theref ore, given the conservative project emission rates and release location ( i.e ., nearest possible distance to a Class I ambient receptor), the small number of other possible PM 2.5 increment consuming emission sources in the EGOM and onshore areas, and the un likely combined simultaneous contributions from land

- based and OCS PM 2.5 emission sources, the use of the PM 2.5 Class I SILs should not jeopardize PSD Class I increments.

7.2.7 Ozone

Both VOC and NO X are precursors to ozone formation. T he project’s estima ted VOC and NO X
e missions exceed the significant emission rate of 100 TPY. Thus, assessment of the project’s ozone impacts is required. The estimated project emissions are provided in Table 4

- 1. An adequate ozone formation model has not been developed for this type of sole source application. Hence, the EPA concurred that a qualitative or relative assessment could be performed.

To put the project’s NO X and VOC emissions in perspective, the applicant compared the proposed project emissions to Gulf of Mexic o emissions reported in the 2008 Emissions Inventory from the Bureau of Safety and Environmental Enforcement (BSEE). This inventory indicates there are 3,027 point sources that emit either VOC or NO X located in the Gulf of Mexico west of 87 degree 30 minut e longitude. The 2008 Gulfwide Emission Inventory Study Report (latest inventory report of the Bureau of Energy Management, Regulation and Enforcement) provides estimates of total emissions of NO X and VOC from all the sources in the Gulf of Mexico. Compari ng the proposed project emissions with these estimates reveal s that the proposed project emissions are about 0.15 % of total NO X and 0.10 % of total VOC Gulf of Mexico emissions.

For further comparison, Table 7

- 2 presents the statewide total NO X emissions from the 2008 National Emissions Inventory (NEI) for the states around the Gulf of Mexico as summarized from information provided in the Technical Support Document for the EPA Federal Transportation Rule (EPA

- HQ

- OAR

- 2009

- 0491). This document shows that on

- road sources contributed the most to the total NO X emissions in the Gulf States. Estimated project emissions are very small when compared with the total NO X emissions of nearly 4.0 million tons from the five Gulf States.

Table 7

- 2

State NO X Emissions for Gulf States in the 2008 NEI

State NO X Emissions (TPY) Alabama 421,467 Florida 895,436 Louisiana 548,43961

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Mississippi 278,745 Texas 1,827,200 Total 3,971,287

Another consideration is the distance from the closest Anadarko lease location to the coastline. The nearest coastline is at the mouth of the Mississippi Delta more than 180 km from the nearest lease location. Therefore, e missions of NO X and VOCs from the project need to travel more than 100 miles to reach the coastli ne to potentially contribute to on shore ozone concentrations. In addition, the wind speeds and direction in the eastern Gulf of Mexico changes frequently, so the project emissions will be distributed over a wide area. Based on the above information and

con siderations, project emissions are not expected to significantly impact ozone formation along and near the coastal areas of the Gulf of Mexico.

7.2.8 Additional Impact Assessments

An additional impacts analysis was performed in accordance with PSD requirements in 40 CFR § 52.21(o). The analysis evaluates the potential impacts that the emissions from the proposed exploration activities could have on growth, soils, vegetation, and visibility in the OCS impact area of concern.

7.2.8.1 Growth

The potent ial growth of industrial, commercial, and residential sources as a result of the proposed exploration activities is expected to be minimal. The current infrastructure that supports the well

- developed oil and gas activities in the area just west of the prop osed drilling activities is adequate to support the proposed drilling activities and no additional growth is expected.

7.2.8.2 Soil and Vegetation
The potential impacts of the proposed project on the soils and vegetation in the project’s impact area must b e considered. Assessment of impacts to vegetation having no significant commercial or recreational values is not required. Due to the location of the proposed exploration activities in the eastern Gulf of Mexico more than 1 50 km from any coastline and the modeled project impacts of less than significant levels, no significant impact from the proposed project to soils or vegetation is expected.

7.2.8.3 Visibility
The estimate of project impact on visibility in the project’s impact area was assessed using the EPA plume impact screening model VISCREEN. The VISCREEN model estimates the potential visual impact of a plume caused by a proposed project’s emissions. A VISCREEN Level I analysis was conducted to determine if emissions from the proposed exploration acti vities could result in an adverse impact on visibility at the closest visibility sensitive Class II area receptor. The project’s particulate matter and NO X emissions were provided as inputs, while the default values were used for background ozone, stabilit y class, and wind speed (default background ozone concentration of 0.04 parts per million, and default stability and wind speed are 6 and 162

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- R4020 meter per second, respectively). VISCREEN conservatively evaluated whether a plume from the BlackHornet drilling vessel, and associated support vessels, will produce a plume perceptible to an observer under worst

- case meteorological conditions at a specific location. Several angles between the observer’s line of sight and the sun’s radiation (θ) were conside red.

The application of VISCREEN is limited to distance less than or equal to 50 km. Therefore, to conservatively estimate the potential visual impact in the impact area that is more than 150 km from the drilling location, the much smaller 50 km distance was used in the VISCREEN analysis. Two criteria are assessed in the analysis, delta E and contrast. Delta E, also called plume p erceptibility

, refers to the color difference between the plume and background ( i.e
., brightness, color hue, and color saturati on). The default threshold or “critical” value for delta E is 2.0 . Contrast, also referred to as green contrast value or Cp, represents the contrast of a plume against a background such as the sky or a terrain feature. Change in contrast is measured in ter ms of green color wavelength. The default threshold or “critical” value for contrast is 0.05.

Tables 7

- 3 provides the results of the VISCREEN modeling for the BlackHornet drilling vessel. This table shows that the default threshold for Delta E and contras t (Cp) were not exceeded for sky or terrain backgrounds by the drilling vesse l at 50 km distance

. T herefore, the proposed BlackHornet exploration activities are not expected to impair the local visibility at the closest areas of concern, 25 nautical miles from each state’s seaward boundary.

Table 7

- 3 VISCREEN Level 1 BlackHornet Results Background Θ Distance (Source

Observer) Delta E Contrast

Critical Plume Critical Plume

Sky 10 50 km 2.00 1. 870 0.05

- 0.007 Sky 140 50 km 2.00 0.599 0.05

- 0.011 Terrain 10 50 km 2.00 0.175 0.05 0.00 3 Terrain 140 50 km 2.00 0.055 0.05 0.00 2

7.3 PSD Class I Areas Analyses

The PSD Class I areas nearest to the project location are Breton National Wildlife Refuge (1 67 km distant ), Bradwell Bay Wilderness Area (285 km distant ), and Saint Marks Wilderness Area (281 km distant ) . The FLM for Breton and Saint Marks Wilderness Areas is the Fish & Wildlife Service (FWS). The FLM for the Bradwell Bay Wilderness Area is the National Forest Service. The proposed project impa cts to PSD Class I areas included v isibility and nitrogen and sulfate deposition (i.e., FLM’s Air Quality Related Values (AQRV) of concern) and EPA require d assessment of PSD Class I increments. The PSD increment s were assessed using the same model and mod eling procedures as used for the PSD Class II impact assessment.63

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- R4020 7.3.1 Air Quality Model Selection

The EPA

- preferred model for long

- range transport assessments , CALPUFF Version 5.8, was used to evaluate potential AQRV and PSD increment impacts. This model is also recommended by the FLM s

. 7.3.2 Modeling Procedures

The modeling procedures used for the Class I area impact analyses followed the recommendations of the Interagency Workgroup on Air Quality Modeling and the FLM Air Quality Related Values Workgroup (FLAG), outlined in the FLAG Phase I Report

- Revised (2010). The selected options for the CALPUFF modeling system followed the procedures and defaults approved by the FLM and/or the EPA. Total NO X emissions were modeled to represent NO 2 emissions. Visibi lity extinction coefficients and total deposition fluxes were calculated for 24

- hour and annual averages, respectively. Comparisons to the regulatory standards and/or FLM target values were based on the maximum modeled values from the modeled three

- year

me teorological dataset. Project Class I area SIL analysis did not include chemistry conversion and puff depletion.

The CALPUFF chemistry transformations depend on the ambient ammonia and ozone concentrations. Because of the low ammonia background concentra tion expected over the Gulf of Mexico, the FLM requested value of 3 ppb was used. The ozone background concentrations for the 2001

- 2003 modeled years were those included with the meteorological dataset. A conservative background value of 65 ppb was used fo r any missing values.

The Class I area modeling assessment used the operational scenarios that produce the maximum hourly emission s. These maximum hourly emission rates were used for both the short

- term ( i.e., 24

- hour) and long

- term annual impact assessments (see Section 7.2.2).

To provide the worst

- case impact condition the drilling vessel was located at their closest location

– the NW corner of the lease block nearest Breton. For all impact analyses, support vessels were modeled a s point sources located 25 nautical miles from the drilling vessel in the direction of the nearest shore receptor and Breton NWR.

7.3.4 Meteorological Data

The three

- year meteorological CALMET processed dataset (2001

- 2003) developed by the Visibility Impr ovement State and Tribal Association of the Southeast (VISTAS) was obtained from the Florida Department of Environmental Protection and used for the PSD Class I impact assessment. This dataset, the same as used for the PSD Class II impact assessment, cover s the Gulf of Mexico region of interest.

7.3.5 Modeling Results

The maximum Class I area estimated impacts from the proposed exploratory drilling emissions are provided in Table 7

- 4. The accepted PSD Class I annual SIL is also provided in this table. The maximum modeled concentrations associated with the proposed project emissions for the64

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- R4020 BlackHornet drilling vessel are less than the SIL. Therefore, the project is considered to have no significant impact on the PSD Class I increments.

Table 7

- 4 Maximum Modeled Class 1 Concentrations Class I Area Criteria

Pollutant Averaging Period BlackHornet Max. Concentration (ug/m 3 ) EPA SIL

(ug/m 3 )

Breton NWR NO 2 a Annual 0.0 279 0.1

PM2.5 b 24

- hr 0.0 639 0.07 c

Annual 0.0 042 0.06 c

PM10 24

- hr 0.0738 0.3

Annual 0.0049 0.2

St. Marks NWR and Bradwell Bay Wilderness* NO 2 a Annual 0.0027 0.1

PM2.5 b 24

- hr 0.0205 0.07 c Annual 0.0007 0.06 c PM10 24

- hr 0.0236 0.3 Annual 0.0008 0.2

*St Marks NWR and Bradwell Bay Wilderness were modeled together by including all receptors from both Class I areas. Therefore, the provided concentrations represent the worst

- case concentration for both Class I areas

.
a NO X was assumed to be 100 percent converted to NO 2
. b 100 percent (maximum) values are provided using direct PM 2.5 emissions only.

c The Class I PM 2.5 SIL was vacated in January 2013. Given the conservative emission rates and release location (i.e., nearest possible distance to Class I ambient receptor), an d small number of other possible increment consuming PM 2.5 emission sources in the eastern Gulf of Mexico, the use of the PM 2.5 SIL should not jeopardize PSD Class I increment at this area.

The CALPUFF estimates of deposition of acid

- forming compounds fr om the project’s emissions are provided in Table 7

- 5. This table also contains the FLM accepted Deposition Analysis Thresholds (DAT) established for areas east of the Mississippi. The DAT is defined as the additional amount of nitrogen or sulfur deposition within a PSD Class I area below which estimated project impacts are considered negligible [Federal Land Manager’s Air Quality Related Values Workgroup, Phase I Report

– Revised June 2008]. The estimated project deposition rates are much less than the DAT. Therefore, the project associated Class I area deposition should be negligible.65

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- R4020 Table 7

- 5 Estimated Class I Area Deposition Fluxes (kg/ha/yr)

Class I Area BlackHornet Nitrogen Deposition Sulfur Deposition Breton NWR 0.00716 0.0001 St. Marks/Bradwell Bay 0.00282 0.0000209 Deposition Analysis Threshold 0.010 0.005

The visibility concern at Breton NWR is regional haze. The project’s contribution to regional haze is addressed as the 24

- hour change in extinction. The FLM considers a five percent change in extinction to be just perceptible. The FLM accepted procedure known as Method 8 was used. Method 8 employs the IMPROVE extinction equation using monthly relative humidity adjustment factors, annual background aerosol concentrations, and 9 8 th percentile modeled values at each receptor to provide estimates of the change in extinction associated with project emissions.

Visibility extinction coefficients were calculated for 24

- hour averages

. Comparison with FLM

recommended criteria for regio nal visibility impacts is shown by calculating the change in 24

- hour extinction for each Class I receptor. The CALPUFF modeling system was used to predict both the extinction coefficient attributable to emissions from the project as well as the background extinction coefficients for that day’s meteorology.

The Method 8 estimated project associated changes in visibility extinction for the BlackHornet vessel resulted in a small number of days with more than five percent change in extinction. Table 7

- 6 provides a summary of the Method 8 visibility modeling assessment for both Breton NWR and St. Marks NWR. The BlackHornet assessment for Breton NWR resulted in two days over a three

- year period from 2001 through 2003 exceeding five percent change in extinction with a maximum of 5.18 percent. Both days had changes of less than 10 percent. Th e St. Marks NWR assessment resulted in no days exceeding five percent change in extinction and a maximum of 1.23 percent.

Table 7

- 6 Summary of Method 8 Maximum Estimated Change in Extinction for Drilling Operations

Class I Area Parameter Year

2001 2002 2003

Breton NWR 98 th Percentile 24

- hr

Average % Change 5.18 3.55 4.42

No. Days >5% Change 98 th Percentile Threshold 2 0 066

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No. Days >10 % Change 98 th Percentile Threshold 0 0 0

St. Marks NWR 98 th Percentile 24

- hr

Average % Change 1.23 0.87 1.18

No. Days >5% Change 98 th Percentile Threshold 0 0 0

No. Days >10 % Change 98 th Percentile Threshold 0 0 0

The estimated impacts of the proposed project’s emissions on the nearest PSD Class I area s hows visibility impacts for Breton NWR of 0.2% greater than the FLM perceptibility level on two days over a three year period . The drilling vessel’s deposition levels are less tha n the FLM’s DAT values. The Breton NWR FLM reviewed this PSD Class I area impact assessment and indicated that because of the conservative assumptions contained in the emission estimates and analyses, and the temporary nature of the activity, they expected no significant project

- related impacts.



## 8.0 Additional Requirements

8.1 Endangered Species Act and Essential Fish Habitat of Magnuson

- Stevens Act

Section 7(a)(2) of the Endangered Species Act (ESA) requires federal agencies, in consultation with the Nat ional Oceanic and Atmospheric Administration (NOAA) Fisheries Service and/or the U.S. Fish and Wildlife Service (collectively, “the Services”), to ensure that any action authorized, funded, or carried out by the agency is not likely to jeopardize the conti nued 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 prop osed 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 design ated lead agency on behalf of itself and the other involved agencies. See 50 CFR §§ 402.07. In addition, 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 MSA.

The Bureau of Ocean Energy Management (BOEM) of the DOI is the lead federal agency for authorizing oil and gas exploration activities on the OCS. Therefore, BOEM serve s as the Lead Agency for ESA section 7 and MSA compliance for Anadarko’s exploration activities. In67

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- R4020 accordance with section 7 of the ESA, BOEM consults prior to a lease sale with NOAA Fisheries and FW S to ensure that a sale proposal will not cause any protected species to be jeopardized by oil and gas activities on a lease. In addition, BOEM requests annual concurrence from the Services to ensure current activities remain consistent with the terms and conditions of the Biological Opinion issued for the lease sale activities.

Since the BOEM consultations address the same exploratory drilling activities authorized by the air permit that the EPA is issuing to Anadarko, the EPA relied in pa rt on those conc lusions for the preliminary determination. In addition, NOAA Fisheries considered the scope of the proposed action and did not identify any rout es of effects for air quality. Based upon the best available data and technical assistance from the Services, th e EPA determined that the issuance of this OCS permit to Anadarko for exploratory drilling is not likely to cause any adverse effects on listed species and essential fish habitats beyond those already identified, considered and addressed in the prior consu ltations.

8.2 National Historic Preservation Act

Section 106 of the National Historic Preservation Act requires federal agencies to take into account the effects of their undertakings on historic properties. Section 106 requires the lead agency official t o 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 National Register of Historic Places. The BOEM is the lead agency permitting Anadarko’s activity in the Gulf of Mexico. The environmental effects of offshore drilling in the Gulf were analyzed by the BOEM in multi

- sale Environmental Impact Statement s , covering sales in 2007 through 2012 , and for 2012 through 2017, accessible on the web at http://www.boem.go v/nepaprocess/#Recent NEPA Documents

. BOEM typically conducts section 106 consultation at the pre

- lease stage by prior agreement with the Advisory Counsel for Historic Preservation rather than at the individual post

- lease permit level. In order to reach a Finding of No Significant Impact, mitigation is carried out at the post

lease plan level by requiring remote sensing survey of the seafloor in areas considered to have a high probability for archaeological resources. Any cultural resources discovered duri ng that inspection are required by regulation to be reported to BOEM with 72 hours. No significant archaeological properties are anticipated in this location, but should anything be discovered there as a result of the operator's investigations, BOEM would consult with the State Historic Preservation Office and the Advisory Counsel for Historic Preservation.

8.3 Executive Order 12898

– Environmental Justice
Executive Order 12898, entitled “Federal Actions to Address Environmental Justice in Minority Populati ons and Low

- Income Populations,” directs federal agencies, including the EPA , to the extent practicable and permitted by law, to identify and address, as appropriate, disproportionately high and adverse human health or environmental effects of regulatory
p rograms, policies, and activities on minority populations or low

- income populations. See Executive Order 12898, 59 Fed. Reg. 7629 (February 11, 1994). Consistent with Executive Order 12898 and the EPA’s environmental justice policy (OEJ 7/24/09), in making decisions regarding permits, such as OCS permits, the EPA gives appropriate consideration to environmental justice issues on a case

- by

- case basis, focusing on whether its action would have68

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- R4020 disproportionately high and adverse human health or environmental effects on minority or low

income populations.

The EPA has concluded that this proposed OCS air permitting action for Anadarko’s exploratory drilling operation on the Gulf of Mexico would not have a disproportionately high adverse human health or environm ental effects on minority or low

- income populations. The closest drill site is located approximately 100 miles southeast of the nearest Louisiana shoreline, and 125 miles south of the nearest Alabama and Florida in the Gulf of Mexico. The project is locate d
more t han 150 miles offshore in ultra

- deepwater and the EPA is not aware of any minority or low

- income population that may frequently use the area for recreational or commercial reasons. In addition, since the project is located well away from land, the project’s emissions impacts will be dispersed over a wide area with no elevated concentration levels affecting any onshore populated area. See Section 7.0 of this document pertaining to air quality impact for further information

.



## 9.0 Public Participation

9.1 Opportunity for Public Comment

The EPA must follow the administrative and public participation procedures in 40 CFR part 124 used to issue PSD permits when processing OCS permit applications under Part 55 as well as the administrative and public parti c i pation procedures of 40 CFR part 71 when issuing Title V permits to OCS sources. 40 CFR § § 55.6(a)(3), 71.4(d). Accordingly, the EPA has followed the procedures of 40 CFR parts 71 and 124 in issuing the draft permit. As provided in 40 CFR part s 71 and 124, the EPA is seeking comments on the Anadar ko OCS air permit OCS

- EPA

- R4020 during the public comment period as specified in the public notice. Public notice is also being provided as required under 40 CFR § 71.

Any interested person may submit written comments on the draft permit during the public comment period. If you believe that 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 administrative record for this permit or cons ist of state or federal statutes or regulations, the 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. If you have comments regarding non

- air quality impacts, leasing, drilling safety, discharge, or other similar issues not subject to this public comment period, you should submit them during the leasing and plan approval proceedings of the BOEM, which is the lead agency for offshore drilling

.69

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- R4020 All timely comments related to the proposed action will be considered in making the final decision and will be included in the administrative record and responded to by the EPA

. The EPA may summarize t he comments and group similar comments together in our response instead of respon ding to each individual comment

. All comments on the draft permit must be received by email at R4OCS permits@epa.gov

, submitted electronically via www.regulations.gov (docket # EPA

- R04

- OAR

- 2014

- 0728 ), or postmarked by December 15 , 201 4

. Comments sent by mail should be addressed to: USEPA Region 4, Air Permits Section APTMD, 61 Forsyth Street, SW, Atlanta, GA 30303. An extension of the 30

- day comment period may be granted if the request for an extension is filed within 30 days and it adeq uately demonstrates why additional time is required to prepare comments. All comments will be included in the public docket without change and will be made available to the public, including any personal information provided, unless the comment includes Co nfidential Business Information or other information in which disclosure is restricted by statute. Information that you consider Confidential Business Information or otherwise protected must be clearly identified as such and must 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 noti fication of the EPA’s final decision regarding the permit and the EPA’s response to comments submitted during the public comment period.

For general questions on the draft permit, contact: Ms. Eva Land at 404

- 562

- 9103 or land.eva@epa.gov.

9.2 Public Hear ing

The EPA will hold a public hearing if the Agency determines that there is a significant degree of public intere st in the draft permit. Public h earing requests must be in writing and received by EPA by December 8 , 201 4

. Requests should be sent by email to R4OCSpermits@epa.gov or by mail addressed to: USEPA Region 4, Air Permits Section, 61 Forsyth Street, SW, Atlanta, GA 30303. Requests for a public hearing must state the nature of the issues proposed to be raised in the hearing. If a public hearing is held, you may submit oral and/or written comments on the draft permit at the hearing. You do not need to attend the public hearing to submit written comments. If the EPA determines that there is a significant degree of public interest, The EPA will hold a public hearing on December 18 , 201 4

, at:

West Florida Public Library

239 North Spring Street Pensacola, Florida 3250 (850) 436

- 5043

If a public hearing is held, the public comment period will automatically be extended to the close of the public hearing. If no timely request for a public hearing is received, or if the EPA determines that there is not a significant degree of public inter est, a hearing will not be held. Such an announcement will be posted on the EPA ’s website at:70

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- R4020 http://www.epa.gov/region4/air/permits/ocspermits/ocspermits.html

,

or you may call the EPA at the contact number above to verify if the public hearing will be held.

9.3 Administrative Record

The administrative record contains the application, supplemental information submitted by Anadarko, correspondence (including e

- mails) clarifyi ng various aspects of Anadarko’s application, other material used in EPA’s decision, and correspondence with other agencies. The administrative record and draft permit are available on www.regulations.gov (docket# EPA

- R04

- OAR

- 2014

- 0728 ) and through the EPA’s website at:

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

. These websites can be accessed through free internet services available at local libraries. The draft permit and the administrative record are also available for public review at the EPA Region 4 office at the address listed below. Please call in advance for available viewing times.

EPA Region 4 Office 61 Forsyth Street, SW Atlanta, GA 30303 Phone: (404) 562

- 9043

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 yarbrough.rosa@epa .gov

.
9.4 Final Determination

The EPA will make a decision to issue a final permit or to deny the application for the permit after the Agency has considered all timely comments on the proposed determination. 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.