Statoil OCS

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

Preliminary Determination & Statement of Bas is Outer Continental Shelf Air Permit OCS

- EPA

- R40 12 For

Statoil Gulf Services , LLC DeSoto Canyon Lease Blocks

August 9, 2013Statoil OCS

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## Table of Contents Abbreviations and Acronyms

................................ ................................ ................................ .................... iii 1.0 Introduction

................................ ................................ ................................ ................................ ........... 1 2.0 Applicant Information

................................ ................................ ................................ ........................... 1 2.1 Applicant Name and Address

................................ ................................ ................................ ........... 1 2.2 Facility Location

................................ ................................ ................................ ............................... 2 3.0 Proposed Project

................................ ................................ ................................ ................................ ... 2 3.1 Operating Scenario 1 (Maersk Developer )

................................ ................................ ....................... 3 3.2 Operating Scenario 2 (Transocean Discoverer Americas )

................................ ................................ 4 3.3 Support Vessel Operations

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

................................ ................................ ..................... 6 4.1 EPA Jurisdiction

................................ ................................ ................................ ............................... 6 4.2 OCS Air Regulations

................................ ................................ ................................ ........................ 6 4.3 Prevention of Significant Deterioration (PSD)

................................ ................................ ................. 7 4.4 Title V

................................ ................................ ................................ ................................ ............... 9 4.5 New Source Performance Standards (NSPS)

................................ ................................ ................... 9 4.5.1 Part 60 Subpart Dc

................................ ................................ ................................ ..................... 9 4.5.2 Subpart IIII

................................ ................................ ................................ ............................... 10 4.5.3 Subpart K

................................ ................................ ................................ ................................ . 13 4.5.4 Subpart Ka

................................ ................................ ................................ ............................... 14 4.5.5 Subpart Kb

................................ ................................ ................................ ............................... 14 4.6 National Emission Standards for Hazardous Air Pollutants (NESHAP)

................................ ........ 14 5.0 Project Emissions

................................ ................................ ................................ ................................ 15 5.1 Potent ial to Emit

................................ ................................ ................................ ............................. 15 5.2 Operating Scenario 1 ( Developer ) Emissions Source Analysis

................................ ...................... 17 5.3 Operating Scenario 2 ( Discoverer Americas ) Emissions Source Analysis

................................ .... 18 5.4 Support Vessel Analysis

................................ ................................ ................................ ................. 20 5.5 Compliance Methodology

................................ ................................ ................................ ............... 21 6.0 Best Available Control Technology (BACT) and Recordkeeping Requirements

.............................. 22 6.1 BACT Analysis Procedure

................................ ................................ ................................ .............. 22 6.2 Step 1: Identify all Available Control Technologies

................................ ................................ ...... 24 6.3 Step 2: Eliminate Technically Infeasible Control Options

................................ ............................. 24 6.4 Step 3: Rank the Remaining Control Techn ologies by Effectiveness

................................ ............ 28 6.5 Step 4: Evaluate the Energy, Environmental and Economic Impacts

................................ ............ 29 6.6 Step 5: Select BACT

................................ ................................ ................................ ....................... 30 7.0 Summary of Air Quality Impact Analyses

................................ ................................ .......................... 32 7.1 Required Analyses

................................ ................................ ................................ .......................... 32 7.2 PSD Class II Air Quality Impact Assessment

................................ ................................ ................. 33 7.2.1 Air Quality Model Selection

................................ ................................ ................................ .... 35 7.2.2 Characteristics of Modeled Operational Scenarios

................................ ................................ .. 35 7.2.3 Meteorological Data

................................ ................................ ................................ ................. 38 7.2.4 Building Downwash

................................ ................................ ................................ ................. 38 7.2.5 Receptor Locations

................................ ................................ ................................ .................. 38 7.2.6 Project Impact Assessment

................................ ................................ ................................ ...... 38 7.2.7 Ozone

................................ ................................ ................................ ................................ ....... 40 7.2.8 Additional Impact Assessments

................................ ................................ ............................... 41 7.3 PSD Class I Areas Analyses

................................ ................................ ................................ ........... 42ii

Statoil OCS

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................................ ................................ ................................ .... 42 7.3.2 Modeling Procedures

................................ ................................ ................................ ............... 42 7.3.4 Meteorological Data

................................ ................................ ................................ ................. 43 7.3. 5 Modeling Results

................................ ................................ ................................ ..................... 43 8.0 Additional Requirements

................................ ................................ ................................ .................... 45 8.1 Endangered Species Act and Essential Fish Habitat of Magnuson

- Stevens Act

............................ 45 8.2 National Historic Preservation Act

................................ ................................ ................................ . 46 8.3 Executive Order 12898

– Environmental Justice

................................ ................................ ............ 4 6 9.0 Public Participation

................................ ................................ ................................ ............................. 47 9.1 Opportunity for Public Comment

................................ ................................ ................................ ... 47 9.3 Administrative Record

................................ ................................ ................................ .................... 48 9.4 Final Determination

................................ ................................ ................................ ........................ 49iii

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## A bbreviations and A cronyms

AP

- 42 AP

- 42 Compilation of Air Pollutant Emissions Factors AQRV Air Quality Related Values BACT Best A vailable C ontrol T echnology BOE M Bureau of Ocean Energy Management Breton NWR Breton National Wildlife Refu g e BSEE Bureau of Safety and Environmental Enforcement Developer Maersk Developer Drill Rig or the Rig CAA Clean Air Act CEMS Continuous Emissions Monitoring System CFR Code of Federal Regulations CO Carbon M onoxide CO 2 Carbon D ioxide CO 2 e C arbon D ioxide E quivalent DOI United States Department of the Interior Discoverer Americas Transocean Discoverer Americas Drill S hip or the Ship EGOM Eastern Gulf of Mexico EPA United States Environmental Protection Agency ESA Endangered Species Act FLAG FLM Air Quality Related Workgroup FLM Federal Land Manager FWS United States Fish and Wildlife Service g/kW

- hr Grams per K ilowatt H our GHG Greenhouse Gas HAP Hazardous Air Pollutants HIP High Injection Pressure hp Horsepower IMO International Maritime Organization km Kilometer kPa Kilopascals kW Kilowatt kW

- hr Kilowatt H our LND Low NO X Engine Design

m 3 Cubic M eters MMBtu/hr Million British Thermal Units per Hour MSA Magnuson

- Stevens Fishery Conservation and Management Act NAAQS National Ambient Air Quality Standards NEI National Emissions Inventory NESHAP National Emission Standards for Hazardous Air Pollutants NO 2 Nitrogen Dioxide NOAA National Oceanic and Atmospheric Administration NO X Oxides of Nitrogen NMHC Non Methane Hydrocarbons NSPS New Source Performance Standards NSR New Source Review OCS Outer Continental Shelfiv

Statoil OCS

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- R4012 080913 OCSLA Outer Continental Shelf Lands Act OSV Offshore Support Vessel PM Particulate M atter PM 2.5 Particulate M atter (a erodynamic d iameter less than or equal to 2.5 m icrons ) PM 10 Particulate M atter ( aerodynamic diameter less than or equal to 10 microns )
ppm Parts per M illion PSD Prevention of Significant Deterioration PTE Potential to Emit RICE Reciprocating Internal Combustion Engine SAM Sulfuric Acid Mist SCR Selective Catalytic Reduction Statoil Statoil Gulf Services, LLC or the Applicant SIL Significant Impact Level SMC Significant Monitoring Concentration SO 2 Sulfur Dioxide Support Vessels Crew Boats and Offshore Support Vessels TPY or tpy Tons Per Year TRS Total Reduced Sulfur TVP True Vapor Pressure ug/m 3 Micrograms per Cubic Meter U.S.C. United States Code VISTAS Visibility Improvement State and Tribal Association of the Southeast VOC Volatile Organic C ompoundsStatoil OCS

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## 1. 0 Introduction

Statoil Gulf Services

, LLC (The Applicant or Statoil ) has applied for an Outer Continental Shelf (OCS) air permit pursuant to s ection 328 of the Clean Air Act ( CAA) from the United States Environmental Protection Agency (EPA) Region 4 . Statoil has proposed the mobilization and operation of deepwater drilling vessels and associated support fleets at multiple lease blocks on the OCS in the Gulf of Mexico. Statoil p lans to drill using one of two operating scenarios and

, dependant on the scenario, will use one of
two dynamically positioned deepwater drilling vessels

. T he Maersk Developer drill rig

, also referred to

as Operating Scenario 1, or the Transocean Discoverer Americas drill ship

, also referred to as Operating Scenario 2, along with associated support fleets will be used to conduct the permitted exploratory activities

. D rilling operations will last for approximately 1 8 0 days per year at multiple locations within Statoil’s DeSoto Canyon lease blocks and are expected to occur for approximately five to ten years. This application and any resultant permitting action from this application are for exploratory drilling only. If resource discove ries are made during exploration activities

, subsequent facilities

, including any
necessary production platforms

, would be permitted separately.

EPA Region 4 is the agency responsible for implementing and enforcing CAA requirements for OCS sources in the G ulf of Mexico east of 87 ° 30 ’ (87.5 ° )

. 1 The EPA has completed a review of Statoil’s application in addition to all supplemental materials provided and is proposing to issue Permit N umber OCS

- EPA

- R4 0 12 to Statoil for a multi

- year exploratory drilling program subject to the terms and conditions described in the draft permit

. The draft permit incorporates applicable requirements from the federal Prevention of Significant Deterioration (PSD) and t itle V operating permit programs, New Source Performance Standards (NSPS)

, and National Emission Standards for Hazardous Air Pollutants (NESHAP) as required by the OCS air quality r egulations in 40 CFR part 55.

This document serves as a fact sheet, preliminary determination

, and state ment of basis for the draft permit. It provide s an overview of the project, a summary of applicable requirements , the legal and factual b a sis for draft permit conditions, and the EPA’s analysis of key aspect s of the appl ication and draft permit such as the b est a vailable c ontrol t echnology (BACT) a nalysis and Class II/ Class I area 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

Statoil Gulf Services

, LLC 2103 CityWest Boulevard, Suite 800 Houston, Texas 77042

1 S ee CAA section 328

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

. 2 The procedures governing the issuance of both OCS and PSD permits are set forth at 40 CFR p art 124, s ubparts A and C

. See 40 CFR §§ 55.6(a)(3) and 124.1

. Accordingly, EPA has followed the p rocedures of 40 CFR part 124 in issuing the draft permit

. This Preliminary Determination describes the derivation of the permit conditions and the reasons for them as provided in 40 CFR § 124.7, and also serves as a Fact Sheet as required by 40 CFR § 124.8 and statement of basis as required by 40 CFR § 71.1(a)(5)

.2

Statoil OCS

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- R4012 080913 2.2 Facility Location

Statoil proposes to conduct exploratory drill ing at multiple sites within its DeSoto Canyon lease blocks designated Lease Sale areas 213 and 222 . These lease blocks ( numbers 143, 187, 188, 230, 231, 625, 669, 670, 671, 715, 716, 759, 760, and 804 ) are located i n OCS waters of the Gulf of Mexico east of longitude 87.5 °

, approximately 160 miles southeast of the mouth of the Mississippi River and 200 miles southwest of Panama City, Florida as illustrated below. Each lease block is approximate ly five kilometers by five kilometers.

Figure 2

- 1 Site Location

Image reproduced from Outer Continental Shelf Title V and PSD Permit Application DeSoto Canyon Drilling Exploration Project for Statoil Gulf Services LL C dated September 2012 , p repared by ENVIRON International Corporation Baton Rouge, Louisiana

. 

## 3

. 0 Proposed Project

Statoil proposes to operate either the Developer (Operating Scenario 1) or the Discoverer Americas (Operating Scenario 2) deepwater drilling vessels and their associated support fleets to perform explorat ory drilling activities for approximately 1 8 0 days per year at multiple locations within their currently held lease block s in the DeSoto Canyon area of the Gulf of Mexico

. It is expected that drilling operations will occur for approximately five to ten years

. Therefore, Statoil is applying for an OCS air permit that will incorporate PSD and title V operating permit program requirements.

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 less3

Statoil OCS

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- R4012 080913 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 s ulfur dioxide (SO 2 ), as well as other regulated air pollutants including volatile organic compounds (VOC) , oxides of nitrogen (NO X ), and greenhouse gas es (GHG s )

. 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 drill ing vessels’ main engines and in smaller engines that supply power for operating drilling equipment and support vessels

. Emissions may also be released from other equipment suc h as fuel and mud storage tanks and from activities such as cementing the well s , pumping heavy lubricating mud , painting, and welding

.

Based on emissions estimates and the applicable permitting thresholds, th is project will have significant emissions of NO X and is subject to the PSD and t itle V program s for NO X as the measured pollutant for criteria pollutants NO 2 and ozone and as a precursor to PM 2.5
. A ny facility that emits a regulated New Source Review (NSR) pollutant at levels exceed ing its PSD significant emission rate must perform a BACT analysis and comply with all subsequent regulatory obligations for that pollutant as described in Section 6.0 below

.

Based on Statoil ’s permit application, PM 2.5 will be emitted at close to its significant emission rate in both operating scenarios . Therefore, EPA has also included a condition in the draft permit that limit s the project’s total filterable and condensable PM 2.5 emissions.

3.1 Operating Scenario 1 (Ma ersk Developer )

The Developer (Figure 3

- 1) is a self

- powered, dynamically positioned semi

- submersible drill rig with pontoon structures below the water surface and a platform above the surface. P ositioning is achieved using a computer controlled system and the rig’s propellers and thrusters. Therefore, the Developer will not require the use of towing or anchoring vessels as part of its support fleet.

The rig is equipped with eight main generator engines to provide propulsion and electrical powe r, two cementing unit engines, an emergency generator, four life boats, a fast rescue boat (also known as a man overboard boat), and storage vessels for fuel and waste oil. Electric powered well logging wireline units

, vertical seismic profile compressors, forklifts, and cranes are used on the rig. However, since the electric units do not have combustion engines, they are not addressed as a se parate source of air emissions. Maintenance activities, such as welding and painting, also emit small amounts of air pollutants. Cement used in casing and drilling activities is mixed in an enclosed system on the Developer ; therefore, no emissions to ambient air are expected from this source.

Support vessels operatin g within 25 miles of the drill rig will include crew boats and offshore support vessels (OSVs) that will bring crew, supplies

, and materials to the rig as needed during exploratory drilling activities . In addition, crew and time

- sensitive supplies may be t ransported to and from the drill ship via helicopters

. Engine details and emissions information are provided in Section 5.0 of this document.4

Statoil OCS

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- R4012 080913 Figure 3

- 1 Maersk Developer Drill Rig

Image reproduced from Outer Continental Shelf Title V and PSD Permit Application DeSoto Canyon Drilling Exploration Project for Statoil Gulf Services LLC dated September 2012, p repared by ENVIRON International Corporation Baton Rouge, Louisiana.
3.2 Operating Scenario 2 (Transocean Discoverer Americas )

The Discoverer Amer icas is a dynamically positioned drill ship equipped with a computer controlled

sensor sy stem to maintain the vessel's position and heading over its location using the ship’s propellers and thrusters. As with the Developer , this drill ship does not require towing or anchoring vessel s as part of its support fleet

.

The Discoverer Americas ’ equipment includes six main engines that power electrical equipment and

serve as propulsion generators

, two forklift engines, an emergency generator , two emergency air
compressors, six life boats, a fast rescue boat (man overboard boat)

, a hot oil heater, and storage vessels for fuel and waste oil

. The drill ship also uses electric

- powered wireline units

, vertical seismic profile
compressors, cement uni ts, and cranes

. However, since these units do not have combustion engines, they are not addressed as separate sources of air emissions. A ctivities and equipment such as welding, painting, cement mixing , storage tanks

, and drilling mud also emit small amounts of air pollutants.

The drill ship is supported by various vessels operati ng within 25 miles . The support vessel fleet associated with the Discoverer Americas consists of the same crew boats and OSVs that would be used to service the Develop er , as discussed above

. Since the fleet to be used is the same in both operating scenarios , the same emission calculations for crew boats and OSV s are used for both

.

T he Discoverer Americas drill ship is pictured below in Figure 3

- 2

. Engine details and emissions information are provided in Section 5 .0 of this document

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Statoil OCS

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- R4012 080913 Figure 3

- 2 Discoverer Americas Drill Ship

Image reproduced from Outer Continental Shelf Title V and PSD Permit Application DeSoto Canyon Drilling Exploration Project for Statoil Gulf Services LLC dated September 2012, p repared by ENVIRON International Corporation Baton Rouge, Louisiana.
3.3 Support Vessel Operations

As discussed previously, Statoil will rely on a fleet of support vessels in two categories: OSVs and crew boats. Hence, specific support vessels are not necessaril y assigned to a specific project, rig

, or drill ship

. A llowable emission rate limits included in the draft permit for support vessels will apply to any support vessel within each category. Normally

, support vessels will keep under their own power when adjacent to the drilling vessel for loading or unloading purposes. The only expected physical connection would be in the form of product transfer hoses such as those used for refueling or drilling mud. E missions from these connections are accounted for in the storage vessel emission estimates for each drilling vessel.

To estimate annual emissions from representative crew boats and OSVs

, Statoil estimated the total fuel
usage for each type of vessel during a typ ical 18 0

- day drilling campaign from actual fuel usage data and hours of operation for similar vessels in conjunction with Air Pollutant Emissions Factors (AP

- 42) 3 . To estimate maximum hourly emissions for each vessel category , Statoil compiled engine and e missions data for several vessels of each type . From that information, Statoil derived the worst case emissions from each category of support vessel during any one hour of operation. Based on Statoil’s calculations, the potential emissions proposed for eac h type of support vessel are a reasonable estimate of emissions that would be expected from the highest emitting vessel in each category.

Section 5.0 of this document includes details regarding the methodology used to determine air emissions from the sup port vessels

.

3 S ee AP 42, Fifth Edition, Volume I, Chapter 3: Stationary Internal Combustion Sources , Sections 3.3 and 3.4, 1996.6

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## 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 areas of the OCS with the exception of the Gulf of Mexico w est of 87.5 ° longitude. Subsequently, the Consolidated Appropriations Act, 2012 (P.L. 112

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

4

. 2 OCS Air Regulation s
Section 328(a)(1) of the CAA requires the EPA to establish requirements to control air pollution from OCS sources under EPA’s jurisdiction, in order to attain and maintain federal and state ambient air quality standards and to comply with the provisions of part C (PSD) of title I of the CAA. The OCS Air R egulations at 40 CFR p art 55 implement s ection 328 of the CAA and establish the air pollution control requirements for OCS sources and the procedures for implementation and enforcement of the se requirements

. 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. ); or (2) Physically attached to an OCS facility, in which case only the stationary source aspects o f th e 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 p art 55 distinguish between OCS sources located within 25 miles of a state's seaward boundar y and those located beyond 25 miles of a state ’ s seaward boundar y [ see CAA § 328(a)( 1 ); 40 CFR §§ 55.3(b) and (c) ]. In this case, Statoil is seeking a permit for explorat ory drilling operation s that will be conducted exclusively beyond 25 miles of any state’s seaward boundar y

. Sources located beyond 25 miles of a state's seaward boundaries are subject to the NSPS in 40 CF R p art 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 to a major stationary source; standards promulgated under s ection 112 of the CAA

, if rationally related to the attainment and maintenance of federal and state ambient air quality
st andards or the requirements of part C of t itle I of the CAA; and the t itle V operating permit pr ogram in 40 CFR p art 71

. See 40 CFR §§ 55.13(a), (c), (d)(2), (e), and ( f )(2), respectively

. The applicability of these requirements to Statoil ’s exploratory drilling program is discussed below.

The OCS regulations also contain provisions related to monitoring, reporting, inspections, compliance,7

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. Section s 55.8(a) and (b) provide that all monitoring, reporting, inspection

, and compliance requirements of the CAA apply to OCS sources

. These provisions, al ong with the provisions of the applicable substantive programs listed above , provide authority for the monitoring, recordkeeping, reporting and other compliance ass urance measures included in the draft permit

.
4

. 3 P revention of S ignificant D eterioration (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 objective of the PSD program is to prevent s ignificant adverse environmental impact from air emissions by a proposed new or modified source

. T he PSD program requires an assessment of air quality impacts from the proposed project and the utilization of BACT as determined on a case

- by

- case basis takin g 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 “regulate d 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

. In addition to the preceding criteria, any stationary source is also considered a major s tationary 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 capacity 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 p art 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 consi dered direct emissions from such a source while at the source, and while en route to or from the source when within 25 miles of the source, and shall be included in the “potential 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 purposes 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 d rilling vessels and support fleet vessels may contain emissi on 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 nonroad 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.

Also, beginning on January 2, 201 1, greenhouse gases (GHGs) became subject to regulation under the PSD major source permitting program and a regulated NSR pollutant when emitted in amounts greater8

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. GHGs are a single air pollutant defined in 40 CFR § 5 2.21(b)(49)(i) as the aggregate group of the following six gases:

 C arbon dioxide (CO 2 ) ;

 N itrous oxide (N 2 O) ;

 M ethane (CH 4 ) ;

 H ydrofluorocarbons (HFCs) ;

 P erfluorocarbons (PFCs) ; and

 S ulfur hexafluoride (SF 6 )

.

Due to the nature of GHGs and their incorporation into the definition of “subject to regulation”, the determination of whether a source is emitting GHGs in an amount that triggers PSD applicability involves a calculation of the source’s CO 2 - equivalent (CO 2 e) emissions as well as its GHG mass emissions. See the EPA’s PSD and Title V Guidance for Greenhouse Gases ( March 2011 ) available online at www.epa.gov/nsr/ ghgdocs/ghgpermittingguidance.pdf

.

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 per mit application materials and Section 5.0 of this document contain information regarding the emissions factors used to determine PTE for the project. Emissions from support vessels servici ng each drilling vessel were considered direct emissions while within 25 miles of the drilling vessel and are included in the PTE.

T he requirements of the PSD program apply to this OCS source if the project PTE is at least 250 TPY for any regulated pollut ant

. Statoil ’s exploration drilling program is a major PSD source because emissions of NO X exceed the major source ap plicability threshold of 250 TPY

. Therefore, Statoil is required to apply BACT and address air quality impact requirements for NO X , both as the measure d pollutant for NO 2 and ozone and as a precursor to ozone and PM 2.5
. Based on the application materials, the PTE for all other regulated pollutants is below the applicable significant emissions rate

, and a PSD review and BACT analysis a re not required. Section 6.0 of this document contains a discussion of the BACT analysis

.
Table 4

- 1 Potential to Emit for Regulated NSR Pollutants

Pollutant Scenario 1

( Developer ) PTE (TPY) Scenario 2

( Discoverer Americas ) PTE (TPY) Significant Emission Rate (TPY) PSD Review

Required

CO 63.3 2 60. 08 100 No NO X 1 4 84. 26 559.7 2 40 Yes VOC 2 27.6 5 2 4.8 2 40 No PM 10. 6 3 10. 16 25 No PM 10 9. 8 1 9. 39 15 No PM 2.5 9. 5 1 9. 14 10 No SO 2 3 0. 37 0. 3 2 40 No CO 2 e 39,333.5 1 3 4,077

. 77 75,000 (subject to regulation threshold) No

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 for the criteria pollutant ozone.
3 SO 2 is a precursor for the criteria pollutant PM 2.5 .9

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- R4012 080913 4.4 Title V

T he requirements of the t itle V operating permit program, as set f orth in 40 CFR p art 71 , apply to major OCS sour ces located beyond 25 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 , it is considered a major source under title V and p art 71. Therefore, Statoil must apply for an operating permit as provi ded in 40 CFR § 71.5(a)(1)(i ) within 12 months of first becoming an OCS source on its lease blocks

. The OCS permit application submit ted by Statoil seeks to obtain a t itle V operating permit in accordance with 40 CFR § 55.13(f)(2) and 40 CFR part 71 concurrently with the OCS preco nstruction permit

. Part 71 forms for each operating scenario are included as Appendix A of Statoil ’s application

. The draft permit include s conditions necessary to meet the requirements of the t itle 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 emissions ) , as well as monitoring, recordkeeping

, and reporting requirements.

4.5 N ew S ource P erformance S tandards (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 construction or modification

. Potentially applicable NSPS are discussed below.

4.5.1 Part 60 Subpart Dc

Subpart Dc applies to steam gen erating units constructed after June 9, 1989

, with a maximum heat input capacity between 10 and 100 MMBtu/hr. See 40 CFR § 60.40c. A s team generating unit is defined as

a ny device that produces steam or heats any heat transfer medium from the combustion of any fuel . The Discoverer Americas is equipped with a hot oil heater (emis sion u nit HTR) which was constructed after the applicability date. The 17.4 MMBtu/hr

- rated unit heat s a circulating thermal fluid which then heats the drill ship ’s cargo tanks when o perating in areas subject to sub

- freezing temperatures. While located in the Gulf of Mexico, the heater is operated an estimated two hours per year for maintenance purposes only

.

As laid out in 40 CFR § 60.42c(d), if oil is used as the fuel source, SO 2 em issions shall not be in excess of 0.50 lb/MMBtu heat input; or, as an alternative, oil combusted in the unit shall contain less than 0.5 percent sulfur by weight. Subpart 60.42c(h) allows for compliance with the emission limits or fuel oil sulfur limits un der this section to be determined based on fuel supplier certification in addition to the appropriate rep orting and recordkeeping requirements detailed in subpart 60.48c. Statoil proposes to use the same ultra low sulfur diesel that is used in the diesel e ngines on board the drill ship to fuel the heater. C ompliance with this subpart will be demonstrate d with certifications from the fuel supplier indicating a sulfur content of 0. 0 015 percent or less by weight.

Per subpart 60.46c(e), the m onitoring requirements of subpart 60.46c are not applicable where compliance with the SO 2 standard is based on fuel supplier certification. Furthermore, since it will not reach a state of representative operating conditions, the limited use of the heater f or maintenance as described above will result in star tup and shutdown emissions only . Startup and shut down emissions do not constitute representative conditions for testing as are required in 40 CFR part 60 subpart A.10

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- R4012 080913 Therefore, the initial performance tes ting requirements as detailed in subpart 60.8 are not applicable to this unit.

There are no PM emissions standards or requirements p ursuant to this subpart ( see subpart 60.43c) for steam generating units with a maximum heat input of less than 30 MMBtu/hr.

4.5.2 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 e quipment specifications for the Developer and the Discoverer Americas are summarized in Tables 4

- 2 and 4

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

.

The life boa ts (LB

- 1 through LB

- 4 on the Developer and LB

- 1 through LB

- 6 on the Discoverer Americas ) and the fast rescue boats (MOB

- 1 on both drilling vessels) are classified as vessels. Therefore, only stationary source aspects are regulated. As they are used for man overboard and emergency escape scenarios, these units do not have any stationary source aspects with respect to NO X and are not subject to subpart IIII.

Developer The main diesel engines installed on the Developer were constructed after the applicability date of July 11, 2005 . T herefore 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 2006

- model GEN

- 1 through GEN

- 8 main engines which have a displacement greater than 10 liters per cycle

. A NO X emission standard of 11.5 g/kW

- hr was calculated for each 900 rpm engine. To demonstrate compliance with this requirement, Statoil has provided the International Maritime Organization ( IMO ) certificatio n indicating that these engines meet subpart 94.8 emissions standards.

C ompliance with the emissions standards contained in Table 1 of subpart IIII is required for the 2006

- model emergency generator engine (EGEN), which has a displacement less than 10 liters per c ycle

. This engine has been certified to achieve IMO standards

. In addition , b ased on information from the manufacturer (Caterpillar) , the emissions from this unit comply with EPA Tier 1 standards contained in 40 CFR part 89. Although the model year 2006 would be subject to Tier 2 standards to meet the requirements of 40 CFR § 89.112, the Tier 1 certification emissions limits for non road engines listed in sub part 89.112 are equal to the emissions standards contained in Table 1 of subpart IIII. Therefore, IMO certification and vendor test data is sufficient to demonstrate compliance with subpart IIII for this engine.

Compliance with the emissions standards contained in Table 1 of subpart IIII is also required for the 2 006 model cementing unit engines ( CMU

- 1 and CMU

- 2 )

, which have a displacement less than 10 liters per cycle

. These engines are certified to meet the more stringent emissions standards of 40 CFR § 94.8. Therefore, the EPA Tier 2 certification for marine eng ines under subpart 94.8 is sufficient to demonstrate compliance with subpart IIII for these engines.

Discoverer Americas The six main generator engines

, the em ergency diesel generator

, the two emergency air compressor engines, and the two forklift engines installed on the Discoverer Americas are subject to the emissions limitations and diesel fuel requirements of s ubpart IIII

.11

Statoil OCS

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- R4012 080913 The main engines were installed prior to 2012 and have a displacement g reater than 30 liters per cycle

. Therefore, compliance wit h the NO X and PM emissions standards contained in 40 CFR § 60.4204 for the 2008 model

, 720 rpm engines ( GEN

- 1 through GEN

- 6 ) is required

. Based on size, displacement

, and rotational speed, the NO X emission standard is 12.1 g/kW

- hr for these engines

. A PM emission standard of 0.15 g/kW

- hr must also be met . To demonstrate compliance, Statoil has provided IMO certification and engine data indicating that these engines meet the required emissions standards.

The two forklift engines (FORK

- 1 and FORK

- 2) mu st meet the Tier 2 standards for new nonroad engines set forth in Table 1 of 40 CFR § 89.112(a). Since the forklift engines are certified to meet the more stringent emissions standards of 40 CFR part 1039 , the EPA Interim Tier 4 certification is sufficient to demonstrate compli ance with subpart IIII for the forklift engines.

Based on specific engine sizes, model dates

, and displacements, 40 CFR part 60 subpart IIII require s the emergency generator (EGEN) and emergency air compressor engines (ACOMP

- 1 and ACO MP

- 2) on the Discoverer Americas to comply with Tier 2 emissions standards for new marine engines as set forth in 40 CFR § 94.8 and new nonroad engines as set forth in § 89.112, respectively. Compliance with the NSPS specifically requires that these engines be certified to the EPA Tier 2 standards. Since the Discoverer Americas is not a U.S. flagged vessel, it was constructed to IMO rather than EPA Tier standards . While these standards are often similar for later model years, the IMO standards do not require certification for these emergency engines. Since certification is an engine manufacturer process, it is not possible for these engines to obtain an EPA Tier certificate, even for emissions levels that meet the EPA certification requirements. See 4 0 CFR § 60.4211(c). Hence, compliance with the NSPS would require Statoil to replace these engines with engines certified to the emission standards in § 60.4205(b) that would be applicable for the same model year and maximum engine power

. Since these engin es have emission profiles very similar to those of an EPA Tier certified engines, as part of their permit application, Statoil is requesting exemptions from subpart IIII for the emergency generator and emergency air compress or engines

. 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 and e mergency air compressor engines on the Discoverer Americas

were sized to meet th e drill ship’s stringent space and weight distribution requirements in the vessel’s design phase. Based on consultations with Transocean, the drill ship owner, Statoil has dete rmined that

a ny replacement engine would have to meet exacting ` output, weight, physical size

, and shape restrictions dictated by the vessel ’s design constraints

. Statoil 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 communications to the EPA dated July 17, 2013 and included in the administrative record . Furthermore, if suitable replacement engines could be found, replacing t he se engines would likely require a redesign of the engine bed frame and vessel structural modifications that

w ould subsequently require recertification of the vessel

. Based on th ese source

- specific technical barriers

, the EPA concludes that replacement of the EGEN and ACOMP units for this operating scenario and this project is not technically feasible at this time

. Thus , the EPA proposes to grant Statoil’s request for an exemption from subpart IIII

. Any exemption under §55.7 would necessitate c ompliance with substitute emissions and/or work practice requirement s based on the next most stringent standard available. The EPA determined that the next most stringent standards for the EGEN unit on the Discoverer Americas are IMO certification12

Statoil OCS

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- R4012 080913 standard s for comparable engines. Detailed i nformation 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

.

A n exemption under §55.7 also requires an estimate of residual emissions derived from the difference between the estimated reductions that would be achieved by compliance with the original requirement and the estimated emission reductions that would be achi eved by compliance with the proposed substitute requirements. In accordance with 40 CFR § 55.7(e)(3)

, Statoil must then obtain emission reductions of a sufficient quantity to offset the estimated residual emissions. Statoil calculated the differences in em issions that would be achieved by compliance with the original emission standards for each engine versus the estimated emissions from the substitute requirements. These calculations are included in the application materials located in the a dministrative r e cord. T he total residual emissions for the three engines (EGEN, ACOMP

- 1 and ACOMP

- 2) detailed below is approximately 0.13 tons of NO X and hydrocarbons combined, and approximately 0.00072 tons of particulate matter.

As discussed above, t he emergency generator engine (EGEN) is a Category 2, commercial marine engine subject to emission standards located in 40 CFR part 94.8 Table A

- 1. The total NO X + non

methane hydrocarbon (NMHC) emissions residual for the emergency generator engine is estimated to be 0 .13 TPY. Potential emissions of CO and PM for the emergency generator under the substitute requirement are below the Tier 2 standards.

The emergency air compressor engines (ACOMP

- 1 and ACOMP

- 2) are classified as nonroad engines subject to emission standar ds located in 40 CFR part 89.112 Table 1. The total NO X + NMHC emission resi dual for both of these engines combined is estimated to be 0.0066 TPY. Residual PM emissions are approximately 0.00072 TPY. Potential emissions of CO for the emergency air compress ors under the substitute requirement are below the Tier 2 standards.

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 be protect ive 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 stan dards. As such, the EPA has determined that

, based on currently available data, the residual emissions are negligible and no emissions offsets will be required at this time. Taking into
account the quality of the emissions factors currently available to es timate the substitute emissions and the uncertainty inherent in these estimates , this determination will be revisited by the EPA upon review of project specific stack testing data from the Discoverer Americas that is required by the draft permit

. At that t ime, if the EPA determines that emissions reductions are appropriate, Statoil will work with the EPA to identify suitable offsets to satisfy this requirement.

Statoil must comply with all other applicable requirements of subpart IIII for these engines incl uding recordkeeping

, reporting

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

.13

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- R4012 080913 Table 4

- 2 Developer Engine Specifications

Emissions Unit ID Engine Description Manufacturer and Model Displacement

(L/cylinder) Rating a

(kW) Rating a

(hp) Manufacture

Date GEN

- 1 Main Generator Engine 1 Wärtsilä 16V26A 17.0 4960 6651 8/2006 GEN

- 2 Main Generator Engine 2 Wärtsilä 16V26A 17.0 4960 6651 8/2006 GEN

- 3 Main Generator Engine 3 Wärtsilä 16V26A 17.0 4960 6651 8/2006 GEN

- 4 Main Generator Engine 4 Wärtsilä 16V26A 17.0 4960 6651 8/2006 GEN

- 5 Main Generator Engine 5 Wärtsilä 16V26A 17.0 4960 6651 8/2006 GEN

- 6 Main Generator Engine 6 Wärtsilä 16V26A 17.0 4960 6651 8/2006 GEN

- 7 Main Generator Engine 7 Wärtsilä 16V26A 17.0 4960 6651 8/2006 GEN

- 8 Main Generator Engine 8 Wärtsilä 16V26A 17.0 4960 6651 8/2006 EGEN Emergency Generator

Engine Caterpillar 3516B 4.9 1902 2551 11/2006

CMU

- 1 Cement Unit Engine 1 Caterpillar C15 2.4 373 500 10/2006 CMU

- 2 Cement Unit Engine 2 Caterpillar C15 2.4 373 500 9 /2006 LB

- 1 Lifeboat 1 Engine BUKH

--- 22 29 8/2007 LB

- 2 Lifeboat 2 Engine BUKH

--- 22 29 8/2007 LB

- 3 Lifeboat 3 Engine BUKH

--- 22 29 8/2007 LB

- 4 Lifeboat 4 Engine BUKH

--- 22 29 8/2007 MOB

- 1 Fast Rescue Boat Engine Steyr Motors

--- 122 163 3/2007

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

Table 4

- 3 Discoverer Americas Engine Specifications

Emissions Unit ID Engine Description Manufacturer and Model Displacement (L/cylinder) Rating a

(kW) Rating a

(hp) Manufacture

Date GEN

- 1 Main Generator Engine 1 STX MAN 14V32/40 32.2 7000 9387 3/2008 GEN

- 2 Main Generator Engine 2 STX MAN 14V32/40 32.2 7000 9387 3/2008 GEN

- 3 Main Generator Engine 3 STX MAN 14V32/40 32.2 7000 9387 3/2008 GEN

- 4 Main Generator Engine 4 STX MAN 14V32/40 32.2 7000 9387 3/2008 GEN

- 5 Main Generator Engine 5 STX MAN 14V32/40 32.2 7000 9387 4 /2008 GEN

- 6 Main Generator Engine 6 STX MAN 14V32/40 32.2 7000 9387 4 /2008 EGEN Emergency Generator

Engine STX MAN 7L27/38 21.8 2309 3097 2/2008

ACOMP

- 1 Emergency Air

Compressor Engine 1 Duetz F3L912 0.9 37 50 1/2007

ACOMP

- 2 Emergency Air

Compressor Engine 2 Duetz F4L912 0.9 51 68 1/2007

FORK

- 1 Forklift Engine 1 Mitsubishi 8MVXL.0AAD 3.3 37 50 2008

FORK

- 2 Forklift Engine 2 Mitsubishi 8MVXL.0AAD 3.3 37 50 2008

LB

- 1 Lifeboat 1 Engine BUKH

--- 27 36 9/2006 LB

- 2 Lifeboat 2 Engine BUKH

--- 27 36 9/2006 LB

- 3 Lifeboat 3 Engine BUKH

--- 27 36 8/2006 LB

- 4 Lifeboat 4 Engine BUKH

--- 27 36 9/2006 LB

- 5 Lifeboat 5 Engine BUKH

--- 27 36 9/2006 LB

- 6 Lifeboat 6 Engine BUKH

--- 27 36 9/2006 MOB

- 1 Fast Rescue Boat Engine Steyr Motors

--- 158 212 9/2006

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

4.5.3 Subpart K

N SPS 40 CFR part 60 s ubpart K, applies to petroleum liquids tanks with a capacity of greater than 4 0,000 gallons and that commence construction or modification after March 8, 1974, and prior to May14

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- R4012 080913 19, 1978

, o r ha ve a capacity greater than 65,000 gallons and commence construction or m odification after June 11, 1973, and prior to May 19, 1978

. The Developer was built in 2006 and the Discoverer Americas in 2008 . Therefore, storage tanks in either oper ating scenario are not subject to s ubpart K based on construction dates

.
4.5.4 Subpart Ka

NSPS 40 CFR part 60 s ubpart K a applies to petroleum liquids tanks with a capacity of greater than 40,000 gallons that are used to store petroleum liquids and for which construction is commenced after May 18, 1978 , and prior to July 23, 1984

. Th e Developer was built in 2006 and the Discoverer Americas in 2008. T herefore

, all storage tanks are not subject to s ubpart Ka based on their construction date s

.
4.5.5 Subpart Kb

NSPS 40 CFR part 60 s ubpart Kb applies to each storage vessel 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 stora ge 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,

n o storage tanks on the Developer or the Discoverer Americas are subject to Subpart Kb based on operating pressure being less than 3.5 kPa or capacity being less than 75 m 3

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

Applicable NESHAP promulgated under s ection 112 of the CAA apply to OCS sources if rationally related to the attainment and maintenance of federal and state ambient air quality st andards or the requirements of part C of t itle 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. M any p art 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

s ection 112(a)(1) and 40 CFR § 63.2

. An area source is any source that is not a major source as defined in s ection 112(a)(2) and 40 CFR § 63.2. I n both operating scenarios

, Statoil has estimated emissions of less than 25 TPY for all HAP s combined and less than 10 TPY for each individual HAP

. This makes the project an area source of HAP s under either operating scenario

. The regulations also establish different standards for new and existing sources pursuant to CAA section 112. Area source e ngines rated above 500 hp that are co nstructed after December 19, 2002 and engines with a rating of 500 hp or less that are constructed after June 12, 2006 are considered “ new ” reciprocating internal combustion engines ( RICE )

.

The eight main generator engines (GEN

- 1 through GEN

- 8), the emergency diesel generator (EGEN)

, and the two cementing unit engines (CMU

- 1 and CMU

- 2) installed on the Developer drill rig were constructed after the applicability dates

. The six main generator engines (GEN

- 1 through GEN

- 6), the emergency diesel gene rator (EGEN), the two forklift engines (FORK

- 1 and FORK

- 2), and the two emergency air compressor engines (ACOMP

- 1 and ACOMP

- 2) installed on the Discoverer Americas drill ship were also constructed after June 12, 2006. Therefore, 40 CFR 63 s ubpart ZZZZ requ ires that1 5

Statoil OCS

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- R4012 080913 these engines comply with the requirements of 40 CFR 60 s ubpart IIII as discussed above in Section 4.5 .2

. No further requirements under s ubpart ZZZZ apply to these engines

.

Emissions from the life boat engines and the fast rescue boats on the Developer and the Discoverer Americas were included in the 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 the y will not exceed the potential emissions assumed in the application and impact review. However, these units do not have any stationary source aspects with respect to NO X emissions, as they are used for man overboard and emergency escape scenarios

, and are not subject to subpart ZZZZ standards

. 

## 5

. 0 Project Emissions

5.1 Potential to Emit

This section describes the calculation basis for air emissions generated during exploratory drilling operations from each emission source

. The calculations are based on AP

- 42 factors

, EPA publications, analysis of fuel sulfur content , vendor compliance certifications, and vendor

- supplied emissions factors

. The total projected emissions include estimates based on fuel consumption from the diesel engines

. Emissions from oth er sources on the drilling vessels and support vessels are based on worst case PTE conditions for the individual sources

. S ummar ies of the PTE from regulated NSR pollutants are given in Table s 5

- 1 and 5

- 2 below

. The estimated Operating Scenario 1 and 2 emi ssion estimates are based on exploration activities lasting approximately 18 0 days per calendar year

. Statoil is requesting permit limits be established based on emission rates as opposed to operating days to allow operating flexibility

.

Emissions calcul ations are included in Section 3 and Appendix B of Statoil’s September 2012 application which were modified and corrected in the updated emissions calculations submitted to the EPA in Statoil’s Second Response to EPA Incompleteness Determination dated Janu ary 28, 2013 and subsequent email communications dated April 25, 2013

. 4 All documents are included in the administrative record as discussed in Section 9.0 of this document.

Table 5

- 1 Potential to Emit Emissions

– Operating Scenario 1 ( Developer )

Emission Source Total VOC

(TPY) NO x

(TPY) CO (TPY) SO 2 (TPY) PM (TPY) PM 10 (TPY) PM 2.5

(TPY) GHGs

(CO 2 e) ( TPY ) Lead (TPY)

Wärtsilä Diesel Generator Engines 18.23 346.90 16.58 0.28 6.38 6.38 6.38 29,613.84 5.25e

- 03

Emergency Diesel Generator Engine 3.55e

- 02 0.76 0.28 5.47e

- 04 2.46e

- 02 2.02e

- 02 1.96e

- 02 57.63 1.02e

- 05

Lifeboat Engines 1.750e

- 03 8.582e

- 03 6.293e

- 03 7.566e

- 06 6.865e

- 04 5.644e

- 04 5.476e

04 0.80 1.41e

- 07

Fast Rescue Boat Engines 0.00 0.01 0.01 1.06e

- 05 6.43e

- 04 5.29e

- 04 5.13e

- 04 1.12 1.99e

- 07

Cement Unit Engines 0.08 0.36 0.25 3.26e

- 04 0.010 0.008 0.008 34.36 6.09e

- 06 Offshore Support Vessels 4.29 108.99 33.46 0.07 2.97 2.44 2.37 6,966.08 1. 23 e

- 03

Crewboats 1.76 27.24 12.75 0.03 0.77 0.63 0.61 2,635.57 4.67 e

- 04

4 E missions summary tables included in Appendix B of the September 2012 application incorrectly label the Discoverer Americas as Operating Scenario 1 and the Developer Operating Scenario 2 in the appendix headings. This does not affect the data included in th e tables or the resultant analysis.16

Statoil OCS

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- R4012 080913 Emission Source Total VOC

(TPY) NO x

(TPY) CO (TPY) SO 2 (TPY) PM (TPY) PM 10 (TPY) PM 2.5

(TPY) GHGs

(CO 2 e) ( TPY ) Lead (TPY)

Tanks and Fugitive Emissions 3.26

-- -- -- 0.48 0.33 0.12 24.11

--

Total 27.65 484.26 63.32 0.37 10. 63 9. 81 9. 51 39,333.51 0.00 697

Table 5

- 2 Potential to Emit Emissions

– Operating Scenario 2 ( Discoverer Americas )

Emission Source Total VOC

(TPY) NO x

(TPY) CO (TPY) SO 2 (TPY) PM (TPY) PM 10 (TPY) PM 2.5

(TPY) GHGs

(CO 2 e) (TPY) Lead (TPY)

STX MAN Diesel Generator Engines 15.01 422.49 13.09 0.23 5.25 5.25 5.25 24,381.00 4.32e

- 03

Emergency Diesel Generator Engine 0.0 3 0.88 0.0 2 4.88e

- 04 0.0 2 0.0 2 0.02 51.42 9.12 e

- 0 6

Lifeboat Engines 3.3e

- 03 1.60 e

- 0 2 1.17 e

- 0 2 1.41 e

- 0 5 1.28 e

- 0 3 1.05 e

- 0 3 1.02 e

- 0 3 1.48 2.63 e

- 07 Fast Rescue Boat Engines 3.2e

- 03 0.02 0.01 1.38 e

- 05 8.36e

- 04 6.88e

- 04 6.67e

- 04 1.46 2.58 e

- 07

Air Compressor Engines 4.4 e

- 04 0.01 1.18e

- 03 1.92e

- 06 4.74e

- 04 3.89e

- 04 3.78e

- 04 0. 20 3.59 e

- 0 8

Forklift Engines 0.03 0.09 0.10 1.29e

- 04 0.01 4.8e

- 03 4.66e

- 03 13.57 2.41e

- 06 Offshore Support Vessels 4.29 108.99 33.46 0.07 2.97 2.44 2.37 6,966.08 1.23 e

- 03

Crewboats 1.76 27.24 12.75 0.03 0. 77 0 .6 3 0.6 1 2,635

. 57 4.67 e

- 04 Tanks and Fugitive Emissions 3.72

-- -- -- 1.14 1.04 0.88 24.11

--

Hot Oil Heater 3.18e

- 05 2.55e

- 03 0.64 2.71e

- 05 4.20e

- 04 1.27e

- 04 3.18e

- 05 2.87 1.57e

- 07 Total 24.82 559.72 60.08 0. 32 10.16 9.39 9.14 34,077.77 6.04e

- 03

N o information has been identified by Statoil or by the EPA indicating a potential for fluoride emissions from the combustion of diesel fuel in internal combustion engines. In addition, no fluoride emission factor resulting from diesel combustion has been ide ntified

. Therefore, fluoride emissions resulting from the combustion of diesel are not considered to be present in engine emissions.

The potential emissions of SO 2 for proposed activities in the Gulf of Mexico are based on an emission factor developed using a mass balance approach. The factor is based on the sulfur content of ultra low sulfur diesel (0.0015 percent by weight ). It is assumed that 100 percent of the sulfur in the fuel is oxidized to SO 2 . However, to obtain a conservative estimate

, Statoil calculated potential total reduced sulfur (TRS) and sulfuric acid mist (SAM) emissions based on a draft EPA document, EPA 420

- R

- 03

- 008 titled “Draft Regulatory Impact Analysis: Control of Emissions from Nonroad Di esel Engines” dated April 2003. The basis of the potential TRS emissions is that 1 percent by weight of the sulfur in the fuel is emitted as TRS rather than being oxidized to SO 2 and could be converted to TRS or reduced sulfur compounds. With either design ation, the potential emissions of TRS are calculated to be less than 0. 01 TPY in each scenario

, considerably less than the relevant PSD significant emissions rate of 10 TPY

.

Similar to the TRS or reduced sulfur compound calculations, the basis for the potential SAM emissions is 2.247 percent by weight of the sulfur in the fuel being converted to SO 4 , which is then converted to sulfuric acid. The potential SAM emissions calculated with this methodology are estimated to be less than 0.014 TPY in Scenario 1 and less than 0.012 TPY in Scenario 2, considerably less than the relevant17

Statoil OCS

- EPA

- R4012 080913 PSD significant level of 7 TPY . Detailed emission calculations for TRS and SAM are included in Appendix B of the September 2012 application and updated in Statoil’s January 2013 response to EPA’s incompleteness determination and subsequent email communications dated April 25, 2013

. Fugitive emissions from each drilling scenario were based on the number of fugitive components (piping, valves, flanges, etc...) identified on each drilling vessel’s fuel system piping and instrumentation diagrams in conjunction with emissions factors contained in Table 2

- 4 of the Protocol for Equipment Leak Emission Estimates (EPA

- 453/R

- 95

- 017). Calculations for fug itive emissions and potential emissions from drilling mud are included in Section 3 and Appendix B of Statoil’s September 2012 application

, which were modified and corrected in the updated emissions calculations submitted to the EPA in Statoil’s Second Res ponse to EPA Incompleteness Determination dated January 28, 2013

. Calculations for emissions from maintenance activities, such as painting and welding on both drilling vessels , as well as cement mixing on the Discoverer Americas were included in email communications to the EPA dated April 25, 2013

. Cement mixing on the Developer is a completely enclosed, self

contained operation with no air emissions. Emissions from painting were based on an estimated amount of paint and paint thinner used during a 180 day drilling campaign, assuming 100% spray application for a conservative estimate. Welding emissions were calculated based on an estimated number of welding electrodes used per 180

- day drilling campaign. Emissions from dry cement mixing on the Discoverer Americas were based on the design flow rate of the mixer’s dust collector.

An additional potential source of emissions in either operating scenario are gases contained in drilling mud circulating from the well to the drilling vessel which may contain hydr ocarbons, particularly if the drill bit is passing through rock in a hydrocarbon zone. These gases can then volatilize to the atmosphere. Statoil has calculated emissions from the drilling mud using an estimate of one day of drilling in hydrocarbon

- contain ing rock per well and an estimated four wells drilled annually.

5 .2 Operating Scenario 1 ( Developer ) Emission s Source Analysis

The following is a description of the Developer’s emission units and how emissions were calculated for each source

. Since potential emissions of regulated air pollutants are estimated to be less than 2 TPY and HAP emissions are estimat ed to be less than 1,000 lb/yr from the lifeboat engines, fast rescue boat engines, mud degassing, welding activities, painting, and sto rage vessels , they are considered insignificant activities with respect to title V permit requirements per 40 CFR 71.5(c)(11)(ii).

Because Statoil has requested that the permit not restrict exploratory drilling activities to 180 days per year for operati onal flexibility, a n annual fuel limitation of 2,650,333 gallons of diesel fuel on a rolling 12

- month basis has been included in the draft permit. This estimate is based on emissions and fuel use estimates for a typical 180

- day drilling campaign as provide d in the application materials. If the drilling vessels are used sequentially during any rolling 12

- month period, the annual fuel use limitation must be prorated based on daily use.

GEN

- 1 through GEN

- 8: Main Diesel Generator Engines The Developer’s electrical power is provided by eight identical Wärtsilä 16V26A diesel generator engines (main engines) with a rated power output of approximately 6,651 hp each

. E missions estimates for the main engines were based on a n anticipated 18 0 days of drilling op eration per year ( 4

, 320 hours annually) and maximum emission factors based on AP

- 42 results and vendor

- supplied data

. Emissions estimates were calculated for normal operating conditions based on three engines operating at 6 0% load and five engines on standby at 0% load

. Maximum hourly emissions were calculated based on five18

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- R4012 080913 engine s at 6 0% load and three engines on standby at 0% load to account for the most engines running during any hour of operation at their highest power rating

. SO 2 emiss ions were estimated based on chemical analysis of the sulfur content of the diesel fuel

. Specific emission factors used to estimate the project’s emissions are included in Section 3 of Statoil ’s September 2012 application

. EGEN: Emergency Generator Engine The emergency generator’s diesel engine is powered by a Caterpillar (3516B) 2,551 hp engine. It provides emergency power to the drilling rig and is run periodically to ensure that the engine will operate properly in the event of an emergency. This p lanned operation time for routine testing and maintenance of 39 hours per year at 100% capacity was used for emission calculations and has been included as a limit in the draft permit to ensure consistency with the assumptions used in the application and impact review

. A total of 0.76 TPY NO X is estimated for this engine

.

CMU

- 1 and CMU

- 2 : Cement Unit Diesel Engines The cementing units are used to produce and pump cement around the well casing during drilling operations to provide stability to the casing

. Each unit has a 500 hp Caterpillar C15 diesel engine. Emissions were calculated for these units using an estimated annual operating schedule of 60 hours per year for each unit , which has been included as a condition in the draft permit to ensure consistency with the assumptions used in t he application and impact assessment

. A total of 0.36 TPY NO X combined is estimated for these engines.

LB

- 1 through LB

- 4 : Life Boats The 29 hp engines powering each life boat are operated during maintenance checks, safety checks and in the event of an emergency

. Planned operating time of 12 hours per year at maximum capacity was used for the emission calculations for each unit

. A n operational limit reflecting the planned operation time for routine testing , drills, and maintenance is included in the draft permit to ensure consistency with the assumptions used in t he application and impact assessment.

MOB: Fast Rescue Boat The 163 hp engine in the fast rescue boat , also known as a man overboard boat

, is operated during maintenance checks, safety checks and in the event of an emergency

. Planned operating time of 12 hours per year at maximum capacity was used for the emission calculat ions. An operational limit reflecting the planned operation time for routine testing , drills, and maintenance is included in the draft permit to ensure consistency with the assumptions used in t he application and impact assessment

. ST Units: Storage U nits Emissions are generated from the storage of diesel fuel, aviation fuel for the helicopters, and waste oil in tanks

. Refueling and unloading emissions associated with the support vessels are included in the storage unit emissions calculations

. The default EPA TANKS 4.09d computer software program was used for diesel and waste oil calculations. The EPA TANKS 4.09d default properties for Jet Naphtha were used for the aviation fuel estimates.

5.3 Operating Scenario 2 ( Discoverer Americas ) Emission s Source Anal ysis

The following is a description of the Discoverer Americas’ emission units and how emissions were calculated for each emission source

. Since potential emissions of regulated air pollutants are estimated to be less than 2 TP Y and HAP emissions are estima ted to be less than 1,000 lb/yr from the emergency air compressors, oil heater, mud degassing, lifeboat engines, fast rescue boat engines, painting, welding19

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- R4012 080913 activities, cement mixing, and storage vessels , they are considered in signific ant activities with respect to
t itle V permit requirements per 40 CFR 71.5(c)(11)(ii).

Because Statoil has requested that the permit not restrict exploratory drilling activities to 180 days per year for operational flexibility, an annual fuel limi tation of 2,179,983 gallons of diesel fuel on a rolling 12

- month basis has been included in the draft permit. This estimate is based on emissions and fuel use estimates for a typical 180

- day drilling campaign as provided in the application materials.

GEN

- 1 through GEN

- 6: Main Diesel Generator Engines The Discoverer Americas’ electrical power is provided by six identical STX Engine Company MAN 14V32/40 diesel generator engines (main engines) with a rated power output of approximately 9

, 387 hp each. Emission s estimates for the main engines were based on an anticipated 180 days of drilling operation per year (4

, 320 hours annually) and maximum emission based on AP

- 42 factor s and vendor

supplied data. Emissions estimates were calculated for normal operating cond itions based on three engines operating at 35 % load and three engines on standby at 0% load. Maximum hourly emissions were calculated based on four engines at 8 0% load and two engines on standby at 0% load to account for the most engines running during any hour of operation at their highest power rating. SO 2 emissions were estimated based on chemical analysis of the sulfur content of the diesel fuel. Specific emission factors

u sed to estimate the project’s emissions are included in Section 3 of Statoil’s September 2012 application.

EGEN: Emergency Diesel Engine The emergency generator’s diesel engine is powered by a n STX Engine C ompany 7L27/38 engine rated at 3,097 hp. It prov ides eme rgency power to the drill ship and is run periodically to ensure the engine will operate properly in the event of an emergency. Th e planned operation time for routine testing and maintenance of 41 hours per year at 100% capacity was used for emissi on calculations and has been included as a condition in the draft permit to ensure consistency with the assumptions used in t he application and impact assessment

. A total of 0.88 TPY NO X is estimated for this engine

.

ACOMP

- 1 and ACOMP

- 2: Emergency Air Compressor Unit Diesel Engines The emergency air compressors are used in the event the main air compressors are not operational. These engines are run periodically to ensure proper operation in the event of an emergency. One unit is equipped with a 50 hp Duetz F3L912 diesel engine and the other unit with a 68 hp Duetz F4L912 diesel engine

. Planned operation time of three hours per year for each unit at 100% capacity was used for the emission calculations

. This planned operation time for routine testing and maintenance of three hours per unit per year at 100% capacity was used for emission calculations and has been included as a condition in the draft permit to ensure consistency with the assumptions used i n the application and impact

assessment

. A total of 0.01 TPY NO X is estimated for these engine s.

FORK

- 1 and FORK

- 2: Forklifts Two forklifts, each powered by a 50 hp Mitsubishi diesel engine, are used for moving equipment and supplies on board the drilling vessel. Emissions were calculated for these units using an estimated annual operating schedule of 237 hours per year for each unit

. A n operational limit is included as a condition in the draft permit to ensure consistency with the assumptions used in the application and impact

assessment

. A total of 0.09 TPY NO X combined is estimated for these engines

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- R4012 080913 LB

- 1 through LB

- 4: Life Boats The 36 hp engines powering the life boats are operated during maintenance checks, safety checks and in the event of an emergency. Planned operating time of 12 hours per year at maximum capacity was used for the emission calculations for each unit. An operational limit reflecting the planned operation time for routine testing

, maintenance , and drills is included in the draft permit to ensure consistency with the assumptions used in the application and impact assessment

.

MOB: Fast Rescue Boat The 212 h p engine in the fast rescue boat, also known as a man overboard boat, is operated during maintenance checks, safety checks and in the event of an emergency. Planned operating time of 12 hours per year at maximum capacity was used for the emission calculati ons. An operational limit reflecting the planned operation time for routine testing

, maintenance , and drills is included in the draft permit to ensure consistency with the assumptions used in the application and impact assessment

.

HTR Unit : Hot Oil Heater The 17.4 MMBtu /hr diesel powered cargo tank heater will not be used while the drill ship is in the
eastern Gulf of Mexico with the exception of planned operating time for maintenance and testing. Calculations for emissions from this unit were based on its operating two hours per year

. A total of 0.003 TPY NO X is estimated for this unit. An operational limit is included as a condition in the draft permit to ensure consistency with the assumptions used in the application and impact assessment

.

ST Units: Storage units Emissions are generated from the storage of diesel fuel, aviation fuel for the helicopters, and waste oil in tanks. Refueling and unloading emissions associated with the support vessels are included in the storage unit emissions calculations. The default EPA TANKS 4.09d computer software program was used for diesel and waste oil calculations. The EPA TANKS 4.09d default properties for Jet Naphtha were used for the aviation fuel estimates.

5.4 Support Vessel Analysis

Various support vessels wi ll be used to transport personnel, supp lies

, and fuel to the drilling vessels for the duration of exploratory drilling

. A vailability of specific support vessels during the operation wa s not know n at the time of application

. As discussed previously, Statoil relies on a support fleet belonging to
two categories, OSVs and crew boats

. Representative emission factors for these sources are available in the application materials , which are included in the administrative rec ord referenced at the end of this documen t. The same fleet of support vessels will be used for both operating scenarios. Therefore, the emissions calculations described here and in Statoil’s application materials apply to either operating scenario.

Statoil based the estimate d annual crew boat and offshore support vessel emissions on total fuel used during the year (18 0 days of drilling operation s ) for similar vessels during similar historical drilling campaigns

. A ctual fuel usage data was used in conjunction with AP

- 42 emission factors to esti mate annual emissions associated with these activities

. Crew boat calculations were based on 618 operating hours per year with a result of 235,176 gallons of diesel consumed per year when within 25 miles of the drilling vessel . To estimate annual emissions from OSVs, Statoil based the calculations on 2,570 operating hours annually with a result of 621,468 gallons of diesel consumed per year when within 25 miles of the drilling vessel.21

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- R4012 080913 Statoil based estimate d maximum hourly emissions for crew boat and OSV emissions using specific engine data and emissions information for several vessels in each category

. From that information, Statoil derived the worst case emissions that could reasonably be expected from each type of support

vess el during any one hour of operation.

The OSV ( Peyton Candies ) and crew boat ( Sybil Graham ) were identified as the highest emitting support fleet vessels. Statoil used the maximum possible emissions from each of these vessels to estimate support vessel emiss ions in the application b ased on maximum load

. H owever, these are conservative worst

- case assumptions, and do not represent how these boats will typically operate

. Detailed emission factors for these sources are available in Statoil’s application materials , which are included in the administrative record referenced at the end of this document.

5. 5 Compliance Methodology

Continuous Emissions Monitoring (CEMS) instrumentation is often required to track specific emissions if monitoring of those emissions is c ritical to ensure that a requirement is being met, or to show that a requirement does not apply. However, the EPA understands that unique issues are involved in requiring CEMS for emission units on deepwater drilling vessels

, and an alternative system may be necessary to monitor pollutants. In consideration of the complexity of continuous compliance monitoring on a deepwater drill ship in the marine environment

, the draft permit allows Statoil to choose monitoring systems for NO X for the main generator d iesel units (GEN

- 1 through GEN

- 8 on the Developer drill rig and GEN

- 1 through GEN

- 6 on the Discoverer Americas drill ship ) and describes the use of an EPA

approved continuous emissions monitoring system, an EPA

- approved alternative parametric monitoring

me thod

, or a stack testing emissions monitoring system that may be used with prior written approval by the EPA.

The compliance demonstration method for the emergency generator diesel u nits (EGEN on both the Developer and the Discoverer Americas , ACOMP

- 1 and ACOMP

- 2 on the Discoverer Americas ), the small er on

- board diesel engines (CMU

- 1 and CMU

- 2 on the Developer , FORK

- 1 and FORK

- 2 on the Discoverer Americas ) and the emergency vessels ( LB

- 1 through 4 on the Developer , LB

- 1 through LB

- 6 on the Dis coverer Americas , and MOB on both drilling vessels ) will include monitoring and maintaining a contemporaneous record of the hours of engine operation using an engine hour meter, or recordkeeping of unit ID, date/time the engine started, date/time the engin e shut down, the printed name of the person operating the equipment and the signature of the person operating the equipment . These units must also meet any applicable NSPS and NESHAP monitoring requirements

. The recorded hours of operation will be used alo ng with the appropriate emissions factors for each engine to determine the total NO X emitted.

Compliance demonstration for the support vessels under both operating scenarios as specified 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

, determining and recording the sulfur content upon receiving each fuel shipment , gallons of diesel fuel on the support vessel entering the 25 mile r adius and gallons of diesel fuel on the support vessel exiting the 25 mile radius.

Statoil will supply the EPA with all records upon request. In addition, Statoil will provide a sem i

- annual report of its emissions information and ca lculations in accordance with all relevant permit conditions

.22

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- R4012 080913 

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

A new major stationary source subject to PSD requirements is required to apply BACT for each pollutant subject to regu lation under the CAA that it would have the PTE in significant amounts. See 40 CFR § 52.21(j). Based on the emission inventory for the project, presented in Table 4

- 1 of the preliminary determination, NO X is the only regulated NSR pollutant that will be em itted by Statoil in quantities exceeding the significant emission rate. Therefore, BACT must be determined for each emission unit on the drilling vessels ( Developer or Discoverer Americas ) which emits NO X while the drill ship is operating as an OCS source with the exception of the life boat and fast rescue craft engines

.

The life boats and the fast rescue boats 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, recor dkeeping and reporting requirements to ensure they will not exceed the potential emissions assumed in the application and impact review. Vessels operating within 25 miles of the OCS source are not subject to BACT requirements unless they are attached to th e 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 aspects with respect to NO X emissions, as they are used for man overboard and emergency escape scenarios only

.

The main generator engines on a drilling vessel continuously operate at variab le loads based on drilling and operational power demand. Consequently, NO X emissions are not emitted from these engines at a steady state. In addition, engine efficiency and pe rformance typically degrades over time, resulting in increased NO X emissions. These factors are important considerations in the BACT analysis for these engines.

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

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

6.1 BACT Analysis Procedure

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 whic h 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 o r modification through application of production processes or available methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event, shall application of best av ailable control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61. If the Administrator determines that technological or economic limitations on the application of measurement technology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to satisfy the requirement f or the application of best available control technology.23

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- R4012 080913 The CAA contains a similar BACT definition, although the 1990 CAA amendments added “clean fuels” after “fuel cleaning or treatment” in the above definition

. See CAA § 169(3)

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

- down approach for determining BACT. See, e.g., In re Prairie State Generating Co. , 13 E.A.D. 1 (EAB 2006). In brief, the top

- down approach provides that all available control technologies be ranked in descend ing order of control effectiveness. Each alternative is then evaluated, starting with the most stringent, until BACT is determined. The top

- down approach consists of the following steps:

Step 1: Identify all available control technologies.

Step 2: Evalua te 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 o f emission reduction potential.

Step 4: Evaluate the most effective controls from Step 3, considering economic, environmental and energy impacts of each control option. If the top option is not selected, evaluate the next most effective control option.

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

Statoil conducted a NO X BACT analysis for all l arge (>500 hp) diesel engines operating on the Developer (Operating Scenario 1) and the Discoverer Americas (Operating Scenario 2). This analysis included the eight main generator engines on the Developer (GEN

- 1 through GEN

- 8), six main generator engines on the Discoverer Americas (GEN

- 1 through GEN

- 6), and the emergency generator engines (EGEN) on both drilling vessels.

Statoil also submitted a NO X BACT analysis for the smaller (<500 hp) diesel engines on both drilling vessels i n the ir application materials . This analysis included the cement unit engines (CMU

- 1 and CMU

2) on the Developer and the emergency air compressor engines (ACOM P

- 1 and ACOMP

- 2) and forklift engines (FORK

- 1 and FORK

- 2) operating on the Discoverer Americas

.

The diesel

- fired cargo tank heater (HTR) on the Discoverer Americas is not included in the diesel engine BACT discussion that follows. However, this unit is subject to BACT and appropriate BACT limits are included in Tables 6

- 2 and 6

- 3 below, as well as in the draft permit. As discussed previously, the heater will not be used in the warm waters of the Gulf of Mexico with the exception of testing and maintenance. Statoil expects that this will require two hours of operation per year and that PTE from the heater would be approximately 0.003 TPY. Based on this information, re placement of the unit or the use of any available NO X - reducing add

- on technologies would prove economically infeasible. Therefore, the EPA has determined that limiting the unit’s operation to less than two hours per year and requiring good combustion and m aintenance practices for the heater represents BACT for the HTR unit for this project. As a unit subject to subpart Dc, as discussed in Section 4.5.1 above, this unit will also be subject to monitoring, recordkeeping, and reporting requirements. Statoil ha s also proposed to limit the use of fuel for the heater to diesel containing less than 0.0015 sulfur percent by weight.24

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- R4012 080913 6.2 Step 1: Identify all Available Control Technologies

The applicant identified the following available NO X control technologies in their OCS permit application submitted in September 2012 :

1. Exhaust Gas Recirculation 2. Ignition Timing Retard 3. Combustion Air Chiller/ Intake Air Cooling 4. Water Injection 5. Fuel Water Emulsions 6. Intake Air Humidification 7. Engine Re

- Tool ing (engine rebuild kits) 8. Derating the Engine 9. NO X Adsorber ( NO X Traps) 10. Lean NO X Catalyst or Hydrocarbon SCR 11. CS NO X Emissions Abatement System 12. Low NO X Engine Design (LND ) 13. Engine Replacement to meet higher EPA Tier standards (40 CFR part 89, 94 , or 1042 ) 14. Se lective Catalytic Reduction (SCR) 15. High Injection Pressure (HIP) 16. Turbocharger with Aftercooler 17. Good Combustion Practices (GCP)

A description for each technology is included in the September 2012 application

, which is contained in the administrative record described in Section 9.3 of this document.

6.3 Step 2: Eliminate Technically Infeasible Control Options

A summary of the rationale for either eliminating a technology from further consideration in the top

do wn BACT analysis for this project or for carrying it through the BACT analysis is listed below for the identified options.

Exhaust Gas Recirculation : Th is technology is in development stages for marine applications and has primarily been applied to small er high speed diesel engines (cars and trucks) and not to large, medium bore, medium speed engines such as the main generator engines and emergency generator engines . In addition, u se of exhaust gas recirculation can increase engine oil acidity, result ing in ineffic iency and increased engine wear and potentially reduc ing engine power output which can hinder safe drilling operations.

Ignition Timing Retard and Intake Air Coolers : Although not specifically discussed as technically infeasible in the application, the EPA is aware that these option s are technically infeasible since it would require derating the engine (see discussion of engine derating below in this section) and reduci ng power available from the engine . This would affect the ability to safely maintain the vessels’ position if used on the large engines and impair the operation of other engines while perform ing functions associated with drilling operations. Furthermore, i gnition timing increases exhaust temperatures, which may adversely impact exhaust valve life and turbocharger performance.

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

- 40 % )

. In addition, large quantities of fresh w ater are required with use of water25

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- R4012 080913 injection . Fresh water storage requirements are problematic with the limited space available on drilling vessels. Furthermore, based on information provided by engine manufacturer Wär tsilä, water injection

can cause damage to engine components, turbochargers

, and air coolers

. This technology could also decrease the available power, which would cause a safety risk on the drill ing vessels

. Similarly, t he combination of exhaust gas recirculation and water injection is also considered technically infeasible.

Fuel

- Water Emulsions : E mulsified fuel systems were designed for and installed on slow

- speed engines burning heavy fuel oil. The existing engines on the Developer and the Discover er Americas are designed for and will be burning medium density fuel (diesel) and will be operated at varying loads . Installing an untested emulsified fuel system designed for heavy fuel oil use on the existing engines increases the potential for mechanica l failure and poses a n unacceptable safety risk. In addition, this technology is considered technically infeasible due to problems associated with limited storage space for the fresh
water that is required for emulsion and concerns regarding fuel tank corr osion from the circulating fuel

water emulsion

.

Intake Air Humidification : Intake air humidification systems require up to double the volume of fresh water for vaporization that the water injection and emulsion systems discussed above involve. Limitations of available space to store the water and to install the necessary heat exchanger render the installa tion of an intake air humidification system technically infeasible on these offshore drilling vessels. Additionally, the heat required to vaporize the water is provided by the hot air from the engine turbocharger, which at low loads may not provide enough heat to operate the system. As discussed previously, the main en gines operate at varying loads and often at low loads.

CAM Shaft Retrofit Kits/Re

- Tooling: According to the kit manufacturer, the camshaft retooling kit is only available for two

- stroke Detroit Diesel engines (model series 71 or 92) and has not been developed for engines such as those used on the drilling vessels

. Derate Engines: While derating the engines can potentially reduce NO X emissions, this would likely decrease available power to the engines. A decrease in available power reduce s the vessel’s ability to maintain correct positioning during storms and loop current events and can impair the performance of the auxiliary engines during drilling activities

, thereby causing an unaccept able safety risk on the drilling vessels

.

NO X Adsorber: This technology is in the development stage and has been used primarily for on

- road diesel applications or off

- road applications for smaller engines such as backhoes, graders, and wheel loaders. According to the technology provider (Johnson Matthey Catalyst), neither technology is available for engines currently equipped on the drilling vessels

.

Lean NO X Catalyst or Hydrocarbon SCR : As with the adsorber technology discussed above

, t hese technologies are in the development stage and have been used primarily for on

- road diesel applications or off

- road a pplications for smaller engines such as backhoes, graders, and wheel loaders. N either technology is available for engines currently equipped on the drilling vessels

.

CSNO X Emission Abatement System: This technology is currently in the licensing and commer cial demonstration phase s of development. Ecospec, the manufacturer, has tested the system on engines operating at stable loads and found the tech nology reduces approximately 66% of NO X emissions as well as 70% of CO 2 and 99% of SO 2 emissions. While this technology is commercially available for26

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- R4012 080913 certain types of marine uses, it has not been demonstrated in practice for variable load engines and is therefore technically infeasible for this project.

Low NO X Engine Design (LND ): Althou gh identified as an available control technology in Step 1 of the BACT analysis, the EPA understand s that this would be technically infeasible because LND is inherent to engine design and would necessitate a replacement of any engine not manufactured with LND . Engine replacement is discussed separately in this section.

Engine Replacement for the Developer Main Generator Engines (GEN

- 1 through GEN

- 8): Based on data provided with the application materials, t he main generator engines on the Developer meet EPA 40 CFR part 94 Tier 2 NO X emission standards. A lthough these engines were m anufactured prior to the 2007 model year applicability date for Tier 2 emission standards established for engines of this size

, Statoil has demonstrated that they comply w ith the appropriate EPA Tier 2 standard with manufacturer emissions testing and IMO certification. Currently, there is no comparable “newer” engine on the market able to meet lower emission standards without the use of add

- on control technology. Therefore, replacement engines would not be required for these engines and this option is not carried through the next step of the BACT analysis

. Engine Replacement for the Discoverer Americas Main Generator Engines (GEN

- 1 through GEN

6): Based on data provided with the application materials, the main generator engines on the Discoverer Americas meet EPA 40 CFR part 94 Tier 1 NO X emission standards. Statoil has demonstrated that they comply with the EPA Tier 1 standard with manufacturer emi ssions testing and IMO certification. C omparable lower NO X - emitting replacement s for the existing Category 3 marine engines would have to be newly constructed to the more stringent EPA Tier 2 standards in 40 CFR part 1042. Replacement of the se engines with comparable units having a more stringent certification rating was considered technically feasible depending on the ability to satisfy size, space and weight restrictions for each engine while maintaining the same power rating and displacement to avoid any possible safety risk from a loss of power. Therefore, this option was carried through the next steps of the BACT analysis for these engines as discussed in Sections 6.4 and 6.5

. Engine Replacement for the Developer and Discoverer Americas Emergency Generator Engines (EGEN): The emergency generator engine s on the Discoverer Americas and the Developer currently
meet EPA Tier 1 NO X emissions standards and are certified to meet IMO Tier 1 emission standards, based on documentation provided in the application materials. Compliance with t he appropriate 40 CFR part 1042 Tier 3 and Tier 4 standards is an inherent part of engine design and no engine modifications or retrofits are currently available. Therefore, t o meet more stringent st andards, the engines would have to be replaced with newer engine s capable of the same performance under the same operating conditions

. However, in each case, t he emergency generator engine was sized to meet vessel space and weight distribution requirements in the vessel’s design phase. R eplacement of the engine may require a redesign of the engine bed frame and structural modifications of the vessel that could subsequently require recertification of the ship or rig

. As discussed above in connection with the exemption of the emergency generator engine on the Discoverer Americas from 40 CFR part 60 subpart IIII, the EPA concluded that replacing the emergency generator engine with a subpart IIII

- compliant engine is technically infeasible. Likewise, b ased on the technical limitations identified in the application materials, EPA concludes that replac ing the emergency generator engines for the Developer and Discoverer Americas is technically in feasible as BACT for this project

. Note that Statoil included cost information in their application; however, since EPA considers this option technically infeasible it was not relied upon in making our determination.27

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- R4012 080913 Engine Replacement for the Developer and Discoverer Americas Small Diesel Engines: After analyzing the identified control technologies, all were eliminated as technically infeasible for control of NO X emissions from the smaller diesel engines on the Developer and the Discoverer Americas except replacement with engines meeting stricter EPA Tier certific ation standards. Existing units CMU

- 1 and CMU

- 2 on the Developer are EPA Tier 2 certified. Likewise, the units FORK

- 1 and FORK

- 2 on the Discoverer Americas are EPA Tier 4 certified. No comparable, higher rated engines are currently available to replace the se units.

T he emergency air compressor engines on the Discoverer Americas (ACOMP

- 1 and ACOMP

- 2) have not been shown to comply with any EPA or IMO standard. Therefore, these engines are evaluated further in the BACT analysis with respect to engine replace ment. As with the larger diesel engines discussed previously, the emergency air compressor engines were sized to meet the drill ship’s space and weight distribution requirements in the vessel’s design phase. Replacement of the engine with the most stringen t 40 CFR part 1042 T ier 4 design could require a redesign of the engine bed frame and vessel structural modifications that could subsequently require recertification of the ship

. As discussed above in connection with the exemption of the emergency air comp ressor engines on the Discoverer Americas from 40 CFR part 60 subpart IIII, EPA concluded that replacing the emergency air compressor engines with subpart IIII

- compliant engine s is technically infeasible. Likewise, b ased on th e technical limitations descri bed in the application materials

, EPA concludes that replacing the emergency air compressor engines would be technically in feasible as BACT for this project

. Note that Statoil included cost information in their application; however, since EPA considers thi s option technically infeasible it was not relied upon in making our determination.

SCR for the Discoverer Americas M ain G enerator E ngines (GEN

- 1 through GEN

- 6) : T he main generator engines on the drilling vessels operate at highly variable loads based on power needs related to specific drilling activities

, environmenta l conditions, and safety needs . This means that t hese engines rarely operate at a steady load for any extended period of time. These operating conditions result in inconsistent exha ust gas temperatures that affect the operation and effectiveness of an SCR syste m. T he temperature of the exhaust gas is critical to selecting the correct catalyst, reducing the amount of unreacted reducing agent ( e.g ., urea) released, and minimizing the c reation of additional NO X from the reducing agent. Therefore , the N O X reduction efficiency would likely be considerably less than the 90 percent that is representative of the reduction efficiency of SCR under steady loads

. Weight and space constraints are a dditional technical considerations on drilling vessels , which are typically designed for maximum space utilization and efficiency. Therefore

, additional space for the SCR equipment and reducing agent storage tanks that was not originally part of the vessel design is often un available. Additionally, d rilling vessels are required to stay within specified overall weight and weight distribution limits to ensure that safety requirements for stability and buoyancy are met.

Based on information contained in Statoil’s September 2012 application, s pace limitations on the Discoverer Americas would not allow installation of the SCR equipment and urea storage tank without removal of a main generator engine

. Engine removal would reduce available power to the vessel creating a safety risk and could affect the vessel’s ability to maintain correct positioning during storms and loop current events. Therefore, SCR is considered to be technically in feasible as BACT for the main generator engines installed on the Discoverer Americas

.

SCR for the Developer M ain G enerator E ngines (GEN

- 1 through GEN

- 8) : Many of the technical considerations discussed above for the main generator engines installed on the Discoverer Americas apply to the Developer’s main generator engines as well. This includes space constraints, inconsistent28

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- R4012 080913 exhaust gas temperatures, and reduced efficiency of the SCR system. Wärtsilä, the engine manufacturer, estimated that a storage tank of roughly the same size and weight as one o f the main generator engines would be required for this project . However, since it may be possible to install the SCR systems without removal of existing equipment , as opposed to conditions on the Discoverer Americas

, the applicant determined that this tec hnology could be considered technically feasible for the Developer’s main generator engines. Therefore, SCR was carried through Steps 3 and 4 of the BACT determination for these engines. The applicant performed a cost analysis which is discussed in Section 6.5 of this document

.

SCR for the Developer and Discoverer Americas Emergency Generator Engines (EGEN): Based on technical references, SCR technology is not feasible for standby engines such as the emergency electrical generator that will be run intermi ttently and in emergency situations only. Note that Statoil included cost information in their application; however, since EPA considers this option technically infeasible it was not relied upon in making our determination.

SCR for small (< 500hp) diesel engines: Based on vendor information and literature searches, SCR technology is not available for the small er engines on board the drilling vessels

. Turbocharger and Aftercooler: All of the diesel engines on the Developer and the Discoverer Americas are equipped with a turbocharger and aftercooler.

6. 4 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 effecti veness. Table 6

- 1 lists the control technologies that have not been ruled out as technically infeasible options . These options are then ranked by effectiveness for the main generator engines and the emergency generator engines on each drilling vessel as well as the emergency air compressor engines on the Discoverer Americas

.

Table 6

- 1 : Step 3 Control Technologies Ranked by Effectiveness
Engine Rank Control Description NO x Control Effectiveness Developer Main Generator Engines (GEN

- 1 through GEN 8) 1 SCR with urea injection Up to 75 %

2 40 CFR part 94 Tier 2 Compliant Design including turbocharger, aftercooler, HIP and l ow NO X t uning with good combustion practices Baseline

Discoverer Americas Main Generator Engines (GEN

- 1 through GEN

- 6) 1 40 CFR part 1042 Tier 2 standards ( i.e., engine replacement for existing engines) Up to 20 %

2 40 CFR part 94 Tier 1 c ompliant design including turbocharger, a ftercooler and HIP with good combustion practices Baseline

Developer Emergency Generator (EGEN) 1 40 CFR part 94 Tier 1 compliant design including turbocharger, aftercooler and

e lec tronic fuel i njection with good combustion practices Baseline

Discoverer Americas Emergency Generator (EGEN) 1 40 CFR part 94 Tier 1 compliant design including turbocharger, aftercooler and HIP with good combustion practices Baseline29

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- R4012 080913 Discoverer Americas Emergency Air Compressor Engines (ACOMP

- 1 and ACOMP

- 2 ) 1 Turbocharger and aftercooler with good combustion practices Baseline

6.5 Step 4: Evaluate the Energy, Environmental and Economic I mpacts

SCR with Urea Injection on Developer Main Generator Engines: Use of an y SCR system comes with additional environmental concerns. SCR systems can allow ammonia to pass through un

- reacted releas ing ammonia into the atmosphere when exhaust temperatures are too low for the ammonia to react or the catalyst has degraded , a condition referred to as ammonia slip

. The released a mmonia is reactive in the atmosphere , generating odors, fi ne particula te matter, visibility concerns, and measurable opacity problems

. D epleted catalysts from SCR systems can be considered hazardous wastes requiring appropriate management and disposal. In addition, when used o n the OCS, transportation, storage, and handling of large quantities of urea for injection pose a potential threat to the surrounding marine environment from leaks and spills

.

In their September 2012 application and a January 2013 revised cost analysis , Statoil examined the environmental concerns discu ssed above, as well as the cost effectiveness of installing and operating SCR to control NO X emissions from the Developer’s main engines . Statoil provided estimates from engine manufacturer Wärtsilä and additional information indicating that a 75% reduction in NO X could be achieved with installation of SCR. The emissions reductions were based on the applicant’s originally proposed NO X BACT emission limit of 8.2 g/kW

- hr for an engine without SCR and 2.0 g/kW

- hr for an engine with SCR

. The estimated a verage cost effectiveness of reducing the resultant 32.74 TPY of NO X from each of the eight main engines was $ 22

, 286 per ton removed. Therefore, Statoil concluded that SCR should be eliminated as BACT as cost ineffective

. As discussed previously, t he main generator engines on a drilling vessel continuously operate at variab le loads based on drilling and operational power demand. Consequently, NO X is not emitted from these engines at a steady state and exhaust temperature var ies

. T he EPA believes that i nconsi stent exhaust gas temperatures from engines working at constantly varying loads and often at very low loads, as these engines do

, would make an SCR system technically infeasible. A t a minimum, the efficiency of the SCR system would be reduced and wou ld likely be render ed ineffective for much of the engines’ operating time . This would contribute to significant ammonia slip when exhaust temperatures fall below approximately 300°C

. However, since Statoil feels that the technology could potentially be fea sible, the EPA evaluated the cost analysis included in the application materials.

T he EPA’s independent cost analysis excluded the estimated Direct Annual Costs from Statoil’s analysis because there was no supporting documentation. As a result, t he total cost effectiveness of installing and operating an SCR was calculated to be approximately $ 20

, 171 per ton of NO X removed. Therefore, the EPA concludes that requiring SCR to control NO X emissions is not cost effective and is not BACT for the Developer’s main generator engines.

Meeting Higher EPA Tier 2 Standards (40 CFR part 1042 ) with Engine Replacement of Main Generator Engines on the Discoverer Americas : Since Tier 2 standards of 40 CFR part 1042 are intrinsic to an engine ’s original design, the Disc overer Americas’ main engines would have to be replaced with newer engines designed to meet the lower standards. T he applicant provided information regarding the cost effectiveness of replacing the Discoverer Americas’ Category 3 main engines with30

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- R4012 080913 newer di esel engines meeting EPA Tie r 2 emission standards found in 40 CFR p art 1042 to achieve a control efficiency of approximately 20%

. Based on the originally proposed BACT emissions limit for the EPA Tier 1 compliant engines of 12.07 g/kW

- hr of NO X emissions and the calculated EPA Tier 2 standards for Category 3 engines with 720 rpm of 9.7 g/kW

- hr, the applicant estimated that 10.37 TPY of NO X from each of the six main generator engines would be removed. Statoil estimated 100 days of downtime (16.7 days per e ngine) would be needed to replace the six engines at $500,000 per day. They calculated the average cost effectiveness to be approximately $ 85

, 821 per ton removed

, and concluded that replacing the main engines is not cost effective and should be eliminated as BACT.

The applicant based the cost effectiveness of replacing the main engines on the Discoverer Americas solely on the downtime associated with the vessel

. The EPA considers the cost associated with the downtime of the ship to be an appropriate retrofit cost similar to that of “lost production” as discussed in Chapter 2 of the EPA Air Pollution Control Cost Manual

. Since the pur pose of an exploratory drill ship is to gather information about a potential well site for the ope rator , it is reasonable to equate the loss of this information with the idea of lost production typical of a more traditional manufacturing facility. When evaluating the replacement of engines on the Discoverer Americas as well as the SCR installations dis cussed above, it is appropriate to consider the daily lease rate paid by the applicant as “lost production” in the capital cost portion of the BACT cost analyses

, but only for those days that information gathering activities would have taken place. The EPA concluded that the cost analysis submitted by the applicant was done appropriately and is conservative since it does not include any capital or annual costs in addition to lost production costs. Therefore, the EPA concludes that requiring replacement of t he main engines on the Discoverer Americas with newer engines to control NO X emissions from this particular project is not cost effective and is not BACT.

It should be noted that calculations in the September 2012 application erroneously used eight engin es to determine the start

- up costs related to 100 days of vessel downtime (12.5 days per engine) resulting in $6,250,000 Total Indirect Cost per engine . If 100 days are needed to replace six engines (16.7 days per engine)

, as was confirmed in Statoil’s Dec ember 2012 submittal, the cost would be $8,333,333 and the cost effectiveness would be $112,504 per ton of NO X removed. The conclusion that this is not cost effective and not BACT for these engines would not change.

6.6 Step 5: Select BACT

After taking into account energy, economic and environmental impacts discussed above in Step 4 of the BACT analysis, the EPA determined that the control options ranked in Step 3 of the top

- down BACT analysis for diesel engines on the Developer and Discover er Americas are BACT as summarized in Table 6

- 2

. The EPA’s BACT conclusion for the cargo tank heater on the Discoverer Americas is also included in Table 6

- 2.

Developer Main Engines: The EPA propose s NO X emission limits of 8. 6 g/kW

- hr as BACT for the mai n engines on the Developer . This limit is based on IMO certification data included with the application materials and a 5% margin of compliance to account for t he variability of each engine ’s NO X emission rate with the varying engine load level and the number of operating hours each engine has logged since significant maintenance was last performed. Given the significant load variations required by the operations on the drill rig , the EPA has determined an averaging period of 24 hours is appropriate in this case.

Discoverer Americas Main Engines: The EPA propose s NO X emission limits of 12. 7 g/kW

- hr as BACT for the main engines on the Discoverer Americas based on IMO certification data included with31

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- R4012 080913 the application materials and a 5% margin of compliance to account for t he variability of each engine ’s NO X emission rate with the varying engine load level and the number of operating hours each engine has logged since significant maintenance was last performed

. Consistent with EPA ’s past BACT determinations for engines on vessels with NOx emissions of 12.7g/k

- W

- hr, EPA has include d requirements for an Enhanced Performance Management System (EPMS)

. The EPMS designed by the owner of the drillship, Transocean, is intended to enhance the fuel oil, lubricant oil and power management of the main engines on the D iscoverer Americas to ensure good combustion efficiency, maintain load levels to an average of 40% and minimize emissions. Given the significant load variations require d by the operations on the drill ship and the information provided by the applicant and vendor, the EPA has determined an averaging period of 24 hours is appropriate in this case

. Emergency Generator Engines : The applicant proposed a NO X emission limit o f 9.2 g/kW

- hr for the emergency generator on the Developer and an operating time of 39 hours per year. However, s ince the emergency generator will only operate approximately 1.5 hours per week, measuring compliance with a numeric emission limit would be un reasonably burdensome and costly. Therefore, the EPA has determined that BACT for the emergency generator engine is use of work practice standards including good combustion practices and operating in accordance with the manufacturer’ s specifications.

The applicant proposed a NO X emission limit of 9.8 g/kW

- hr for the emergency generator on the Discoverer Americas

. However, s ince the emergency generator will operate less than two hours per week (41 hours per year), measuring compliance with a numeric emission limit would be unreasonably burdensome and costly. Therefore, the EPA has determined that BACT for the emergency generator is use of work practice standards including good combustion practices and operating in accordance with the manufacturer’s specifications

.

Small Diesel E ngines : The application indicates that each cementing unit on the Developer will be used on an as needed basis during drilling operations and would operate for up to 60 hours per year. Statoil anticip ates that each emergency air compressor engine on the Discoverer Americas would be operated less than three hours per year during routine checks of their operation, and each forklift on the Discover Americas would operate for 237 hours per year. Given the limited use of these emission units, 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 consistenc y with the emission estimates in the permit application, the draft permit includes operational limits for these units.

Table 6

- 2 : BACT Conclusions

Operating Scenario 1 Emission Units Control Option Emission Limit Developer Main Generator Engines (GEN

- 1 through GEN

- 8) Use of main engines with 40 CFR 94 Tier 2 compliant design (including low NO X tuning , turbocharger, after

c ooler, and high injection pressure ) with good combustion practices based on current manufacturer recommendations. 8.6 g/kW

- hr

Developer Emergency Generator Engine (EGEN) Use of engine with 40 CFR 94 Tier 1 compliant design (including turbocharger, after cooler and32

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- R4012 080913 electronic fuel injection) with good combustion practices based on current manufacturer recommendations. Developer Cementing Unit Engines (CMU

- 1 and CMU

- 2) Use of engine with 40 CFR 94 compliant design and good combustion practices. Operating Scenario 2
Discoverer Americas Main Generator Engines (GEN

- 1 through GEN

- 6) Use of main engines with 40 CFR 94 Tier 1 compliant design (including turbocharger, after cooler and high injection pressure ) with good combustion practices based on current manufacturer recommendations. 12.7 g/kW

- hr

Discoverer Americas Emergency Generator Engine (EGEN) Use of engine with 40 CFR 94 Tier 1 compliant design (including turbocharger, after cooler and high injection pressure ) with good combustion practices based on current manufacturer recommendations with use of EPMS and NOx measurement system. Discoverer Americas Forklift Engines (FORK

- 1 and FORK

- 2) Use of engine with 40 CFR 1039 (Non

- road) Interim Tier 4 compliant design with good combustion practices based on current manufacturer recommendations.
Discoverer Americas Emergency Air Compressor Engines (ACOMP

- 1 and ACOMP

2) Use of engine with turbocharger and after cooler with good combustion practices based on current manufacturer recommendations.

Discoverer Americas Cargo Tank Heater (HTR) Use of good combustion practices based on current manufacturer recommendations.



## 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, in conjunction with all other applicable emission increases or reductions at the source, would not cause or contribute to a violation of an y NAAQS nor cause or contribute to a violation of any applicable “maximum allowable increase” over the baseline concentration in any area (known as PSD increments). 5

5 The maximum allowable PSD increments are listed in 40 CFR § 52.21(c).33

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- R4012 080913 The ambient air quality impact analysis must be based on air quality models, databases, an d other requirements specified in 40 CFR part 51, Appendix W, Guideline on Air Quality Models.

As discussed in Section 4 above and provided in Table 4

- 1, under the proposed OCS permit for exploration drilling operations in the Gulf of Mexico, the potentia l emissions from the proposed OCS source would be above the PSD significant emission rate for NO X . Emissions of other measured air pollutants do not equal or exceed the significant emission rates. NO X is the measured pollutant for NO 2 and ozone. Therefore, the NO 2 and ozone NAAQS and NO 2 PSD increments are relevant to the air quality impact assessment

. 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 formation of PM 2.5 which include SO 2 , NO X , VOC, and ammonia. Direct project emissions of PM 2.5 will not be significant

, but the project will have increases of NO X greater th an the threshold of 40 tons per year . Therefore, Statoil must address compliance with the 24

- hour and annual PM 2.5 NAAQS.

Under 40 CFR § 52.21(m), a PSD permit application must include an air quality analysis in connection with the demonstration require d 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

construction ambient air quality monitoring data, unless the EPA approves a shorter moni toring 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 increase of a pollutant from the proposed source or modification would cause air quality i mpact s 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. 40 CFR § 52.21(m)(2) requires post

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

An a dditional impact analys i s is required by 40 CFR § 52.21(o), including an analysis of the impairment to visibility, soils and vegetation that would occur as a result of the proposed source modification, or that would occur as a result of any commercial, residential, industrial and oth er growth associated with the source modification. 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 any demonstrati on 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 is sue the PSD permit.

7.2 PSD Class II Air Quality Impact Assessment

An air quality impact assessment was performed for the operation of both the Maersk Developer and Transocean Discoverer Americas deepwater drilling vessels and associated support vessels

. The

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.34

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- R4012 080913 modeled operating scenario of each vessel was that which produced the worst

- case impact for each vessel and operation

. As discussed in Section 4.0, the estimates of maximum annual emissions of all pollutants from the two possible drilling vessels and their respective supporting vessels resulted in estimated emissions of NO X greater than the significant emissions rate . Hence, NO X is subject to ambient impact assessment

. This pollutant is also a measured pollutant for ozone and a precursor for PM 2.5
. Th erefore, impact assessments are also provided for ozone and PM 2.5
. An impact assessment addressing the project’s potential impact on the ambient NAAQS and PSD increment is performed in two stages

. The initial stage estimates the impact of only the project’s emissions to determine if they will cause a significant ambient impact , i.e., an impact equal to or greater than the PSD significant impact levels

. If no project pollutant subject to review causes a significant impact, the project is not consider ed to significantly contribute to any NAAQS or PSD increment violation

. Therefore, there is no need to perform the second stage modeling that includes the project and applicable other emission sources in a cumulative assessment to determine NAAQS and PSD i ncrement compliance subsequent to the project’s operation.

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 sign ificant 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. 2013). The D.C. Circuit vacated and remanded the PM 2.5 SIL s. Accordingly, p roject impacts less than the SIL s cannot serve as the sole justification for eliminat ing 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 a dditional information and justification to support a conclusion that a project’s impacts w ill not cause or contribute to a NAAQS or PSD increment exceedance.

The court also vacated the PM 2.5 SMC . As a result of the court’s decision, p roject impacts less than the 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 pre

- c onstruction monitoring if supporting information demonstrates that the existing ambient air quality data provide s 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 Modeli ng (SCRAM); http://www.epa.gov/scram001/)

. Since the proposed drilling will occur at several locations within the DeSoto Canyon lease blocks, the worst case emissions were assumed to be located at the drilling site where the greatest onshore and nearshor e impacts could occur. The OCS project impact area for the Class II area analysis, the area containing 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.35

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- R4012 080913 7.2.1 Air Quality Model Selection

Because the closest Class II area receptor is more than 50 km from the neares t proposed drilling location, 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 asse ssment was performed using the VISCREEN model (Version 88341)

. Figure 7

- 1 provides the modeling domain 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 )

. Figure 7

- 1 CALPUFF M odeling D omain

Image reproduced from the Revised Air Quality Impact Assessment dated June 2013 from ENVIRON

. 7.2.2 Characteristics of Modeled Operational Scenarios

The primary NO X emission sources associated with the proposed exploration drilling activities are the diesel

- fired engines on the drillships

. Additionally, the OCS air regulations define the OCS source to include direct emiss ions from vessels servicing the OCS sources while en route to and from the source when within 25 miles of the drilling operation

. Therefore, the impacts from the associated fleet of vessels that support the primary drilling activity were included

.

The De veloper drillship and support vessel NO X emission sources include the following:

• Main Diesel Generator Engines (8)

,

• Emergency Generator Engine (1)

, Modeling Domain

– Dark Blue 25

- nautical mile Receptors

– Red Class I Receptors

– Purple Radii

– Light Blue36

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- R4012 080913 • Cementing Unit Diesel Engines (2)

,

• Life Boat Engines (4)

,

• Rescue Boat Engine (1)

,

• Fuel Storage Vessels

,

• Fugitives Emissions (diesel fuel system)

,

• Support Vessels (e.g., crew boats), and

• Painting and Welding Activities

.

The Discoverer Americas drillship and support vessel NO X emission sources include the following:

• Main Diesel Generator Engines (6)

• Emergency Generator Engine (1)

• Life Boat Engines (6)

• Rescue Boat Engine (1)

• Emergency Air Compressor Engines (2)

• Forklift Engines (2)

• Fuel Storage Vessels

• Fugitives Emissions (diesel fuel system)

• Support Vessels (e.g., crew boats), and

• Painting , Cement/Mud Mixing, and Welding Activities

.

The basis for the maximum short

- term (1 to 24 hour) and long

- term (annual) emission rates modeled for these sources are discussed below.

The Developer is a self

- powered, dynamically positioned semi

- submersible drilling vessel with pontoon
structure s below the water surface and a platform above the surface. The Discoverer Americas is a dynamically positio ned drill ship. Each vessel uses a computer controlled sensor system to maintain position and heading over its location using the vessel ’s propellers and thrusters . Neither drilling vessel require s towing or anchoring vessels as part of its fleet

. Because of the long distance to the nearest modeled receptor, the vessel orientation and building downwash considerations shoul d not significantly affect the modeled impacts.

Multiple operating scenarios for each drilling vessel were considered including a range of emissions and release parameters (including partial loads) and varying locations of associated support vessels

. The se scenarios were e valuat ed to determine which scenario would result in maximum short

- term and long

term impacts at the modeled receptors

. The following described operating scenarios were determined to produce the worst

- case impacts.

For each drilling ves sel scenario ( Maersk Developer or Transocean Discoverer Americas ), two sets of emission rates were developed

, short

- term and long

- term rates

. The short

- term emission rates were used for the following assessments, as applicable :

• Class II 1

- hour NO 2 SIL (NAAQS)

• Class I and II 24

- hour PM 2.5 SIL (NAAQS and PSD Increment)

• Class I and I I visibility

The long

- term emission rates were used for the remaining assessments:37

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- R4012 080913 • Class I and Class II annual NO 2 SIL (NAAQS and PSD Increment)

• Class I and II annual PM 2.5 SIL (NAAQS and PSD Increment)

• Class I annual Nitrogen deposition rate

The Develope r ’s modeled maximum 1

- hour emissions are based on five m ain g enerator engines operating at 60% load and auxiliary equipment ( i.e., emergency generator engine, life boa ts, fast rescue boat and cementing unit engines) operating at 100% load

. Hourly emissions for support vessels (i.e., crew boats and supply boats) are derived from the maximum fuel usage rates , specific engine data

, and emission information for the respecti ve vessels

. Annual emissions for the annual NO 2 modeling analysis are based on three main engines operating at 60% load, all auxiliary equipment at 100% load, and support vessels based on the maximum engine operation and fuel use for the proposed annual ru n time ( i.e., crew boat at 618 hours/year resulting in 235

, 176 gallons of diesel fuel per year and OSV at 2

, 570 hours/year resulting in 621,468 gallons of diesel fuel per year for operation within 25 nautical miles of the drilling vessel)

.

The Discoverer Americas modeled maximum 1

- hour emissions are based on four Main Generator engines operating at 80% load and the emergency generator engine operating at 70% load (testing scenario). Auxiliary equipment ( i.e., emergency air compressor engine, forklift engi ne, life boats and fast rescue boat) operate at 100% load

. Hourly emissions for support vessels are derived from the specific engine data and emission information for the respective vessels

. Annual emissions are based on three Main Generator engines operat ing at 35% load and the emergency generator engine operating at 70% load (testing scenario)

. Annual emissions also include all auxiliary equipment at 100% load and support vessels based on the adjusted fuel usage and maximum engine operation for the proposed annual run time

. The bas i s for the support vessel emissions ( i.e., crew boats and supply boats) for both the hourly and annual periods is the same for both drilling vessels.

Statoil is requesting authorization for either the Developer or the Disc overer Americas drilling vessel, and its associated support fleet, to operate in any of Statoil’s lease blocks located within the eastern Gulf of Mexico as listed in Section 2.2 of this document. To ensure the modeled worst

- case impact conditions include t he worst

- case project location, 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 (Breton National Wildlife Refuge (NWR) )

. The modeling location s of the associated support vessels ( i.e.
, c rew b oats and OSV s) for each drilling vessel can also affect the modeled impacts

. The modeled worst

- case impact location for the c rew b oats and OSVs is 25 nautical miles from the main drilli ng vessel in the direction of the closest receptor ( i.e.
, toward the Breton NWR )

.

The Developer and Discoverer Americas drilling vessels require no support vessels during deployment so there is no distinction between the maximum 1

- hour and maximum 24

- hour emission rates used for the Class I visibility assessment

. 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 rele ase characteristics have an important influence on the results of the analysis. Exhaust stack parameters for the Developer and Discoverer Americas drilling vessels, as well as the crew boats and OSVs , are provided in the September 2012 Outer Continental S helf Title V and PSD Permit Application DeSoto Canyon Drilling Exploration Project and June 2013 Revised Section 6

- Air Quality Impact Assessment documents38

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- R4012 080913 contained in the Administrative Record (see Section 9.3). Ma ximum short

- term and long

- term emission rates are provided in this document

. 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 impac t 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

sou th to include a 100km 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 , a s noted above , building 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 n ot 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 nauti cal miles offshore Florida . For the Statoil 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 100

- m, if needed

. The location of these receptors is shown in Figure 7

- 1 as the dark/red line parallel to the shoreline

. Because all of these receptors are over
wat er, terrain elevations were assigned an elevation of 0 m ( i.e., sea level) for the Class II impact analysis: [Note: Class I receptors for the Breton Wilderness were obtained from the National Park Service website (http://www.nature.nps.gov/air/Maps/Recept ors/index.cfm)

. These FLM

- specified receptors include elevations that range from 0.021 to 0.375 m.]

7.2.6 Project Impact Assessment

This section presents the estimated ambient concentrations associated with the emissions from the proposed Statoil explorati on activities . I f 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 also require s that the evaluation of compliance with the applicable NAAQS take into account background concentrations and the contributions of other regional sources

.

The SIL s are screening values that have been used since 1980 to identify de minim i s impacts

. 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 Statoil’s application is consistent with the D.C. Circuit’s decision.39

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- R4012 080913 The proposed project emissions from the Developer and Discoverer Americas drilling vessels, as well as the associated support vessels

, were modeled for comparison to the SIL for NO 2 and PM 2 and SMC for NO 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 and PM 2.5
. Similarly, the maximum modeled pollutant concentrations at the discrete 25

- nautical mile receptors were com pared to the SMC for NO 2
. The impact modeling results are provided and compared to the SIL and SMC in Table 7

- 1

. Because all maximum predicted NO 2 concentrations are less than the SIL, the project’s estimated impacts are not considered to cause or contrib ute to a violation of the NO 2 NAAQS or PSD increments

. Furthermore, all maximum predicted NO 2 concentrations are also much less than the NO 2 SMC; therefore, no pre

construction ambient monitoring is required for NO 2
.

Table 7

- 1 Maximum Modeled PSD Class II Area Concentrations

Pollutant Averaging

Period Developer

Max. Concentration (ug/m 3 ) Discoverer

Americas Max. Concentration (ug/m 3 ) Significant

Impact Levels (ug/m 3 ) Significant

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

- hour b 5.4 7. 3 7.5 None Annual 0. 03 0. 04 1 .0 14
PM 2.5 24

- hr b 0. 10 0. 11 1.2 vacated Annual 0. 0009 0. 0008 0.3 None

Notes: a NO X was conservatively assumed to be 100 percent NO 2 . b Maximum (100 percentile) values are provided not 98 th percentile.

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

construction ambient air quality monitor is required. Applicants may submit existing am bient air quality data collected from existing monitoring networks in lieu of pre

- construction monitoring if such data is demonstrated to be representative or conservative for the impact area.

Statoil reviewed the available PM 2.5 air quality monitoring data for the Eastern Gulf of Mexico (EGOM). Although there are no existing PM 2.5 measurements in the vicinity of Statoil’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 lar ge distance from land

- based sources, the background ambient PM 2.5 concentration in the EGOM OCS are expected to be lower than any onshore concentrations. Therefore, the existing onshore ambient monitoring data will provide conservative background ambient PM 2.5 concentrations for the project location. The 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 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 SIL s ( i.e., Table 7

- 1 Class II maximum project impacts are 9.2% of the 24

- hour and 0.3% of the annual PM 2.5 SIL ) provides further support for the use of the SIL s in this application. Hence, it is reasonable to conclude that a 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.40

Statoil OCS

- EPA

- R4012 080913 In terms of the PSD Class I areas where compliance with the PS D 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; trigg er 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. Therefore, given the conservat ive 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 unlikely combined simultan eous contributions from land

- based and OCS PM 2.5 emission sources, the use of the PM 2.5 Class I SIL s should not jeopardize PSD Class I increment s.

7.2.7 Ozone

Both VOC and NO X are precursors to ozone formation

. Although the project’s estimated VOC emissio ns are less than the significant emission rate of 100 TPY, the project’s estimated NO X emissions exceed the significant emission rate

. Thus, assessment of the project’s ozone impacts is required

. The estimated project emissions are provided in Table 4

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

To put the project’s NOx and VOC emissions in perspective, the applicant compared the proposed project emissions to Gulf of Mexico 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 minute l ongitude . 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

. Comparing the proposed project emissions with these estimates reveal project emissions are about 0.8% of total NO X and 0.04% of total VOC Gulf of Mexico emissions.

For further comparison, Table 7

- 3 2 pr esents 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 St ates.

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 548,439 Mississippi 278,745 Texas 1, 827,200 Total 3,971,28741

Statoil OCS

- EPA

- R4012 080913 Ano ther consideration is the distance from the closest Statoil 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

. Emissions of NO X and VOCs from the project need to travel more than 100 miles to reach the coastline to potentially contribute to on

- shore ozone concentrations . In addition , the wind speeds direction in the eastern Gulf of Mexico change s frequently

, so the project emissions will be distributed over a wide area

. Based on the a bove information and considerations, 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 acco rdance 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 G rowth

The potential growth of industrial, commercial, and residential sources as a result of the proposed DeSoto Canyon 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 proposed 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 th e project’s impact area must be 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 150 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 impa ct 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 estimate if the emissions f rom the proposed exploration activities 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 emission s were provided as inputs, while the default values were us ed for background ozone, stability class, and wind speed ( default background ozone concentration of 0.04 parts per million

, and default stability and wind speed are 6 and 1 meter per second , respectively ). VISCREEN conservatively evaluated whether a plume from the Developer or Discoverer Americas drilling vessels

, 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) are considered

. 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 drill ing location, the much smaller 50 km distance was used in the VISCREEN analysis

. Tables 7

- 3 and 7

- 4 provide the results of the VISCREEN modeling for the two drilling vessels . These tables show that the default threshold for Delta E and contrast (Cp) were n ot exceeded for sky or terrain backgrounds by42

Statoil OCS

- EPA

- R4012 080913 either drilling vesse l at 50 km distance

. T herefore, the proposed exploration activities are not expected to impair the local visibility at the closest area s of concern

, 25 nautical miles from each state’s seaw ard boundary

.

Table 7

- 3 VISCREEN Level 1 Developer Results Background Θ Distance

(Source

- Observer) Delta E Contrast

Critical Plume Critical Plume Sky 10 50 2.00 1. 088 0.05

- 0. 006 Sky 140 50 2.00 0. 337 0.05

- 0. 007 Terrain 10 50 2.00 0. 087 0.05 0. 001 Terrain 140 50 2.00 0. 026 0.05 0. 001

Table 7

- 5 4 VISCREEN Level 1 Discoverer Americas Results Background Θ Distance

(Source

- Observer) Delta E Contrast

Critical Plume Critical Plume Sky 10 50 2.00 1.449 0.05

- 0.008 Sky 140 50 2.00 0.449 0.05

- 0.010 Terrain 10 50 2.00 0.118 0.05 0.002 Terrain 140 50 2.00 0.036 0.05 0.002

7.3 PSD Class I Areas Analyses

The four closest PSD Class I areas to the project location are Breto n National Wildlife Refuge (175 km), Bradwell Bay Wilderness Area (307 km), Saint Marks Wilderness Area (313 km ) and Chassahowitzka Wilderness Area (641 km)

. The FLM for Breton, Chassahowitzka, and Saint Marks Wilderness Areas is the Fish & Wildlife Service (FWS) . The FLM for the Bradwell Bay Wilder ness Area is the National Forest Service

. Discussions with the FWS concerning the proposed project resulted in a request for an Air Quality Related Values (AQRV) assessment for the nearest PSD Class I area. Visibility and nitrogen and sulfate deposition are the AQRV of concern at the Breton Nation al Wildlife Refuge. In addition to AQRV of concern to the FLM, the EPA requires the assessment of PSD Class I increments. The PSD increment at the Breton NWR was assessed using the same model and modeling procedures as used for the PSD Class II impact asse ssment.
7.3.1 Air Quality Model Selection

The EPA’s preferred model for long

- range transport assessments is also recommended by the FLM. Therefore, the same model used in the PSD Class II area impact assessment

- CALPUFF Version 5.8 (release 070623)

– was used to evaluate potential AQRV and PSD increment impacts at the Breton NWR (PSD Class I areas).

7.3.2 Modeling Procedures

The modeling procedures used for the Class I area impact analyses followed the recommendations of the Interagency Workgroup on Ai r 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

.43

Statoil OCS

- EPA

- R4012 080913 The CALPUFF

- estimated hourly PM 2.5 and NO 2 concentrations were averaged for the annual and 24

- hour periods

. Visibility extinction coefficients and total deposition fluxes were calculated for 24

- hour and annual averages, respectively

. Comparisons to the r egulatory standards and/or FLM target values were based on the maximum modeled values from the modeled three

- year meteorological dataset.

The CALPUFF chemistry transformations depend on the ambient ammonia and ozone concentrations

. Because of the low ammo nia background concentration 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 val ue of 65 ppb was used for any missing values.

The Class I area modeling assessment used the maximum short

- term ( i.e., 24

- hour emission rate) and long

- term emission scenarios for both the Developer and Discoverer Americas drilling vessels (see Section 7.2 .2)

. The operational scenarios that produce the maximum hourly emission for the vessels were used to obtain the maximum 24

- hour impact values.

To provide the worst

- case impact conditions the drilling vessels were located at their closest location

– the N W corner of the lease block nearest Breton

. Crew boats and OSVs were modeled as 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 dataset (2001

- 2003) developed by the Visibility Improvement State and Tribal Association of the Southeast (VISTAS) was used for the PSD Class I impact assessment

. This dataset, the same as used for the PSD Class II impact assessment, covers the Gulf of Mexico region of interest

. This analysis used a 4

- km grid size to better resolve the impacts.

7.3.5 Modeling Results

The maximum Class I area estimated annual NO 2 impacts from the proposed exploratory drilling emissions are provided in Table 7

- 5. The accepted PSD Class I annual SIL and the PSD increment are also provided in this table. The maximum modeled annual concentration associated with the proposed project emissions for the Developer and Discoverer Americas drilling vessels are much less t han the SIL. Therefore, the project is considered to have no significant impact on the PSD Class I NO 2 increment.

Table 7

- 5 Maximum Modeled Class 1 NO 2 Concentrations Class I Area Developer D iscoverer Americas Annual Average (ug/m 3 ) Annual Average (ug /m 3 ) Breton NWR Max. Concentrations 0.0 2 0.0 2

EPA Proposed SIL 0.1 0.1 Class I PSD Increment 2.5 2.5 Note: NOx was assumed to be 75 percent converted to NO 2 . The maximum Class I area estimated annual and 24

- hour PM 2.5 impacts from the proposed project emissions are provided in Table 7

- 6. The PSD Class I SIL and the PSD increments are also provided in44

Statoil OCS

- EPA

- R4012 080913 this table. The maximum modeled annual concentrations associated with the proposed project emissions for the Developer and Discoverer Americas dril ling vessels are much less than the SIL

. The estimated project maximum PM 2.5 24

- hour concentration for the Developer and Discoverer Americas are also less than the SIL

.

Table 7

- 6 Maximum Modeled Class I PM 2.5 Concentrations

Class I Area Developer Discoverer Americas

24

- hour Average (ug/m 3 ) Annual Average

(ug/m 3 ) 24

- hour Average

(ug/m 3 ) Annual Average

(ug/m 3 ) Breton NWR Max. Concentrations 0. 04 0. 0004 0. 04 0. 0004

EPA SIL 0.07 0.06 0.07 0.06 Class I PSD Increment 2 1 2 1

Given the conservative emission rates and release location (i.e., nearest possible distance to Class I ambient receptor), and 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 fact that the maximum modeled project emissions are substantially lower than the SIL ( i.e., the Table 7

- 6 maximum project impacts are 57.1% of the 24

- hour and 0.7% of the annual PM 2.5 SIL) adds support for the use of the SIL as an indicator of insignificant project impacts in this application.

The CALPUFF estimates of deposition of acid

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

- 7. This table also contains the FLM acc epted 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.

Table 7

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

Class I Area Developer Discoverer Americas Nitrogen Deposition Nitrogen Deposition Breton NWR 0. 0013 0. 0014 Deposition Analysis Threshold 0.010 0.010

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 consider s a five percent change in extinction to be just perceptible . The FLM accepted procedures known as Method 8 was used. Method 8 emp loys the IMPROVE extinction equation using monthly relative humidity adjustment factors, annual background aerosol concentrations, and 98 th percentile modeled values at each receptor to provide estimates of the change in extinction associated with project emissions

.45

Statoil OCS

- EPA

- R4012 080913 The Method 8 estimated project associated changes in visibility extinction for both the Developer and Discoverer Americas vessels resulted in a number of days with more than five percent change in extinction

. The Developer assessment resulted in 15 days exceeding five percent change in extinction with a maximum of 15.51 percent

. Fourteen of the 15 days had changes of less than 10 percent. The Discoverer Americas vessel emissions resulted in 27 days exceeding five percent ch ange in extinction and a maximum of 21.88 percent. Nineteen of the 27 days had changes of less than 10 percent

. Table 7

- 8 provides a summary of the results of the Method 8 modeling analysis. This table reveals that the three year average Method 8 98 th perc entile values for the drilling vessels are less than the target five percent change in extinction for Developer but just greater than the target five percent for the Discoverer Americas

.

Table 7

- 9 8 Summary of Method 8 Maximum Estimated Change in Extinction for Breton Wilderness

Criteria Developer (%) Discoverer Americas (%) Highest Value 15.51 21.88 Number Days > 5% Change 15 27 Number Days >10% Change 1 8 98 th Percentile Change 2001 5.01 7.19 98 th Percentile Change 2002 3.51 5. 06 98 th Percentile Change 2003 3. 69 5.07 98 th Percentile Change 3 year average 4.07 5.77

The estimated impacts of the proposed project’s emissions on the nearest PSD Class I area shows visibility impacts for one of the drilling vessels ( i.e., Discoverer Americas) just greater than the FLM target value

. Both drilling vessels’ deposition levels are less than the FLM’s target or threshold values. The Breton NWR FLM reviewed this PSD Class I area impact assessment and indicated that because of the conservativ e 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

- S tevens Act

Section 7(a)(2) of the Endangered Species Act (ESA) requires federal agencies, in consultation with the National Oceanic and Atmospheric Administration (NOAA) Fisheries Service and/or th e U.S. Fish and Wildlife Service (collectively, “ the Servic es”), to ensure that any action authorized, funded, or carried out by the agency is not likely to jeopardize the continued existence of a species listed as threatened or endangered, or result in the destruction or adverse modification of designated critica l 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 modificatio n of critical habitat proposed to be designated for such species. See 16 U.S.C. § 1536(a)(4); see also 50 CFR §§ 402.10

. Further, the ESA regulations provide that where more than one federal agency is involved in an action, the consultation requirements ma y be fulfilled by a designated lead agency on behalf of itself and the other involved agencies

. See 50 CFR §§ 402.07.46

Statoil OCS

- EPA

- R4012 080913 Section 305(b)(2) of the Magnuson

- Stevens Fishery Conservation and Management Act (MSA) requires federal agencies to consult with NOAA w ith 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 ser ved as the Lead Agency for ESA s ection 7 and MSA compliance for Statoil ’s exploration activities

. In accordance w ith s ection 7 of the ESA, BOEM consults prior to a lease sale with NOAA Fisheries and FWS 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 ensur e 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 Statoil

, the EPA relied in part on those conclusions for our preliminary determination

. In addition, NOAA Fisheries considered the scope of the proposed action and did not identify any routes of effects for air quality. Based upon the best av ailable data and technical assistance from the Services, the EPA determined that the issuance of this OCS permit to Statoil 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 consultations

. The proposed OCS permit includes a condition requiring Statoil to comply with all other applicable federal regulations , which includes the results of any current and future biological opinions

.
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 to ensure that any federally funded, permitted, or licensed undertaking will have no effect on historic properties that are on or may be eligible for the National Register of Historic Places

. The BOEM is the lead agency permitting Statoil 's activity in the DeSoto Canyon lease b locks

, which were in cluded in BOEM Lease Sales 213 and 222

. The environmental effects of Sale s 213 and 222 were analyzed in a multi

- sale Environmental Impact Statement, covering sales in 2007 through 2012 accessible on the web
at http://www.gomr.boemre.gov/PDFs/2007/2007

- 018

- Vol1.pdf

. BOEM typically conducts s ection 106 consultation at the pre

- lease stage by prior agreement with the Advisory Counsel fo r 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 consider ed to have a high probability for archaeological resources

. At the time these leases were sold

, the area was not considered to have a high probability for containing archaeological remains such as a shipwreck

. Any cultural resources discovered during 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 o perator's investigations, BOEM would enter in to consultation 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 Populations and Low

- Income Populations,” directs federal agencies, including t he 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 programs, policies, and activities on47

Statoil OCS

- EPA

- R4012 080913 minority populations or low

- income populations

. See E xecutive O rder 12898, 59 Fed. Reg. 7629 (February 11, 1994)

. Con sistent with E xecutive O rder 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, focusi ng on whether its action would have 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 Statoil ’s exploratory drilling
ope ration on the Gulf of Mexico would not have a disproportionately high adverse human health or environmental effects on minority or low

- income populations

. The drill ing area is located approximately 160 mile s southeast of the mouth of the Mississippi River and 200 miles southwest of Panama City, Florida in the Gulf of Mexico. T he project is located more than 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

. 

## 9

. 0 Public Participation

9 .1 Opportunity for Public Comment

These proceedings are subject to the EPA Procedures for Decision

- making , set forth at 40 CFR § 124. As p rovided in p art 124, the EPA is seeking comment s on the Statoil OCS air permit OCS

- EPA

- R4012 during the public comment period as specified in the public notice.

Any interested person may submit written comments on the draft permit during the public comment period. If you believe 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 record for this permit or consist of state

or federal statutes or regulations, EPA documents of general applicability, or other generally available referenced materials.

Comments should focus on the proposed air quality permit, the permit terms, and the air quality aspects of the project. If you ha ve general 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

. 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 EPA

. The EPA may summarize the comments and group similar comments together in our response and will not respond to individual commenters directly

. 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

- 2013

- 0577 ), or postmarked by September 9 , 2013

. 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 comment48

Statoil OCS

- EPA

- R4012 080913 period may be granted if the request for an extension adequately demonstrates why additional time is required to prepare comments. All comments will be included in the publ ic docket without change and will be made available to the public, including any per sonal information provided, unless the comment includes Confidential Business Information or other information in which disclosure is restricted by statute. Information that you consider Confidential Business Information or otherwise protected should be cl early identified as such and should not be submitted through e

- mail. If you send e

- mail directly to the EPA, your email address will be captured automatically and included as part of the public comment. Please note that an e

- mail or postal address must be provided with your comments if you wish to receive direct notification of the EPA’s final decision regarding the permit and the EPA’s response to comments submitted during the public comment period.

For general questions on the draft permit, contact: Ms. Lori Shepherd at 404

- 562

- 8435 or shepherd.lorinda@epa.gov.

9.2 Public Hearing

The EPA will hold a public hearing if the Agency determine s that there is a significant degree of public interest in the draft permit. Public Hearing requests must be in writing and received by EPA by August 30, 2013

. Requests should be sent by email to R4OCSpermits@epa.gov or by mail addressed to: USEPA Reg ion 4, Air Permits Section

, 61 Forsyth Street, SW, Atlanta, GA 30303. Requests for a public hearing must state the n ature 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 EPA determines that there is a significant degree of public interest, EPA will hold a public hearing on September 16 , 2013, at :

Bay County Public Library Northwe st Regional Library System 898 W 11th Street Panama City, FL 32412

- 0625 (850) 522

- 2119

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 re ceived, or if EPA determines that there is
not a significant degree of public interest , a hearing will not be held. S uch an announcement will be posted on EPA’s website at:

h ttp://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 Statoil , and correspondence ( including e

- mails ) clarifying various aspects of Statoil ’s application. The administrative r ecord and draft permit are available on www.regulations.gov (docket# EPA

- R04

- OAR

2013

- 0577 ) and through the EPA’s website at :

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

.49

Statoil OCS

- EPA

- R4012 080913 These web sites 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 Fors yth 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

A decision to issue a final permit, or to deny the application for the permit, shall be made after all timely
comments on the proposed determination have been consid ered

. 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.