Outer Continental Shelf Title V and PSD Permit Application

Regulatory Applicability 4-1 ENVIRON

4 Regulatory Applicability

In this section of the permit application, we present the regulatory applicability determinations 

that have been made in support of the requested Title V and PSD permit for the Developer and 

Discoverer Americas. Both the Developer and Discoverer Americas will be an exploratory OCS 

source, as this term is defined in 40 CFR § 55.2.1

 Because these proposed OCS sources will 

operate beyond 25 miles of any state seaward boundary, regulatory applicability for the sources 

is determined in accordance with 40 CFR § 55.3(c), which means that state regulations will not 

be applicable to the proposed OCS sources. Instead, the federal requirements listed in 40 CFR 

§ 55.13 will be applicable to the Developer and Discoverer Americas. Additionally, pursuant to 

§ 328 of the Clean Air Act (CAA), the emissions from vessels servicing or associated with an 

OCS source shall be considered direct emissions from such a source while at the source and 

while traveling to and from the source when within 25 miles of the source. Therefore, in 

determining the potential to emit emissions for the Developer and Discoverer Americas, we 

have accounted for their respective support vessel emissions.

4.1 Prevention of Significant Deterioration

In accordance with 40 CFR § 55.13(d), the PSD regulations of 40 CFR § 52.21 apply to the 

OCS sources proposed with this permit application, the Developer and Discoverer Americas. 

Each proposed OCS source is a “new major stationary source” because it is new stationary 

source having the potential to emit 250 tpy or more of a PSD regulated pollutant. Because this 

application is for a new major stationary source, the potential to emit of each PSD regulated 

pollutant proposed to be emitted by the source was compared to respective PSD significant

threshold amounts to determine which pollutants would be subject to PSD review. As 

documented in Table 4.1-1 below, both the Developer and Discoverer Americas would have the 

potential to emit NOX emissions greater than 40 tpy, the pollutant’s PSD significant threshold

amount. Therefore, for each of these sources, PSD review is required for NOX. The Developer

is presented as Operating Scenario 1; the Discoverer Americas is Operating Scenario 2.

Table 4.1-1

PSD Significance Analysis

Pollutant

Operating

Scenario 1

PTE

(tpy)

Operating

Scenario 2

PTE

(tpy)

PSD 

Significance 

Threshold

(tpy)

Subject to PSD 

Review?

(Yes/No)

NOx 469.5 545.0 40 Yes

VOC 28.7 26.0 40 No

SO2 0.4 0.3 40 No

CO 74.5 71.2 100 No

PM2.5 9.1 8.0 10 No

 1 Exploratory source or exploratory OCS source means any OCS source that is a temporary operation conducted for 

the sole purpose of gathering information. This includes an operation conducted during the exploratory phase to 

determine the characteristics of the reservoir and formation and may involve the extraction of oil and gas. (40 CFR 

55.2)
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Regulatory Applicability 4-2 ENVIRON

Pollutant

Operating

Scenario 1

PTE

(tpy)

Operating

Scenario 2

PTE

(tpy)

PSD 

Significance 

Threshold

(tpy)

Subject to PSD 

Review?

(Yes/No)

PM10 9.2 8.1 15 No

PM 9.8 8.7 25 No

CO2e2 41,457.5 36,210.4 75,000 No

H2S Negligible Negligible 10 No

Lead 0.0074 0.0064 0.6 No

TRS 0.009 0.008 10 No

RSC 0.009 0.008 10 No

Sulfuric Acid Mist 0.014 0.012 7 No

Fluorides Negligible Negligible 3 No

Because the proposed OCS sources are subject to PSD review, BACT and ambient air quality 

analyses must be performed as part of this permitting effort. Please see Section 5 for a 

discussion of the BACT analyses that have been performed pursuant to the PSD regulations. 

Furthermore, please see Section 6 for a summary of the ambient air quality analysis that has 

been performed in support of this permit application.

4.2 New Source Performance Standards (40 CFR Part 60)

4.2.1 Subpart Dc – Standards of Performance for Small Industrial-CommercialInstitutional Steam Generating Units for Which Construction, 

Reconstruction, or Modification Commenced After June 9, 1989

Except for certain steam generating units associated with stationary combustion turbines and 

waste incinerators, this subpart applies to each steam generating unit for which construction, 

modification, or reconstruction is commenced after June 9, 1989 and that has a maximum 

design heat input capacity of 100 MMBtu/hr or less, but greater than or equal to 10 MMBtu/hr. 

A steam generating unit means a device that combusts any fuel and produces steam or heats 

water or heats any heat transfer medium. This term includes any duct burner that combusts fuel 

and is part of a combined cycle system. This term does not include a process heater, which 

means a device that is primarily used to heat a material to initiate or promote a chemical 

reaction in which the material participates as a reactant or catalyst.

The Hot Oil Heater (Emission Unit ID HTR) located on the Discoverer Americas heats a thermal 

fluid that is used to transfer heat to cargo tanks on the vessel. This oil-fired heater has a heat 

input capacity equal to 17.4 MMBtu/hr, which is greater than the 10 MMBtu/hr applicability 

threshold of this regulation, and the heater was constructed after the applicability date of June 9, 

1989. Therefore, the heater is an affected facility subject to applicable requirements of this 

regulation.

 2 Greenhouse gas (carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, perfluorocarbons, and sulfur 

hexafluoride) emissions expressed as carbon dioxide equivalent (CO2e).
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Regulatory Applicability 4-3 ENVIRON

Specifically, the sulfur content of the oil used in the Hot Oil Heater (Emission Unit ID HTR) is 

limited to 0.5 percent by weight (40 CFR 60.42c(d)), and Statoil must maintain fuel certifications 

from the fuel supplier to demonstrate compliance with the fuel sulfur limits (40 CFR 

60.42c(h)(1)). Statoil will also be required to submit initial notifications and semi-annual reports 

of fuel certifications and monthly totals of fuel combusted in the cargo heater. The fuel oil to be 

delivered to both drill vessels will be ultra-low sulfur diesel (ULSD), which will have a sulfur 

content of 0.015 percent by weight or less. As a result, this ULSD fuel for the heater will be 

compliant with the regulation’s 0.5 percent by weight sulfur limit. The PM emission standards of 

this regulation are not applicable to the Hot Oil Heater (Emission Unit ID HTR) because the 

heater has a maximum heat input less than 30 MMBtu/hr, which is the threshold below which 

PM emission standards do not apply. 

The Developer is not equipped with any steam generating unit that could potentially be subject 

to this regulation.

4.2.2 Subpart Kb – Standards of Performance for Volatile Organic Liquid Storage 

Vessels for Which Construction, Reconstruction, or Modification 

Commenced After July 23, 1984

Except for storage vessels with a capacity greater than or equal to 151 m3 (39,890 gallons) 

storing a liquid with a maximum true vapor pressure3 less than 3.5 kPa (0.508 pounds per 

square inch-absolute (psia)) or with a capacity greater than or equal to 75 m3 (19,812.9 gallons) 

but less than 151 m3 storing a liquid with a maximum true vapor pressure (TVP) less than 15.0 

kPa (2.176 psia), this subpart applies to each storage vessel with a capacity greater than or 

equal to 75 m3 that is used to store volatile organic liquids (VOLs) for which construction, 

reconstruction, or modification commenced after July 23, 1984.

The storage vessels located on the Developer and Discoverer Americas that contain VOLs were 

constructed after the July 23, 1984 applicability date of this regulation. Therefore, for each of 

these storage vessels, we have evaluated the vessel’s capacity and the maximum TVP of the 

material proposed to be stored in the vessel to determine whether subpart Kb is applicable.

Table 4.2-1 below summarizes the subpart Kb applicability determinations made for the VOL 

storage vessels located on the Developer. As documented in the table, subpart Kb does not 

apply to any of the storage vessels on the Developer.

 3 Maximum true vapor pressure means the equilibrium partial pressure exerted by the volatile organic compounds (as 

defined in 40 CFR § 51.100) in the stored VOL at the temperature equal to the highest calendar-month average of the 

VOL storage temperature for VOL’s stored above or below the ambient temperature or at the local maximum monthly 

average temperature as reported by the National Weather Service for VOL’s stored at the ambient temperature, as 

determined:

(1) In accordance with methods described in American Petroleum Institute Bulletin 2517, Evaporation Loss From 

External Floating Roof Tanks, (incorporated by reference – see § 60.17); or

(2) As obtained from standard reference texts; or

(3) As determined by ASTM D2879–83, 96, or 97 (incorporated by reference – see § 60.17); or

(4) Any other method approved by the Administrator. (40 CFR 60.111b)
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Regulatory Applicability 4-4 ENVIRON

Table 4.2-1

Summary of Developer VOL Storage Vessel Subpart Kb Applicability

Emissions 

Unit ID Description

Capacity

(m3) Service

Max. 

TVP 

(kPa) Subpart Kb Applicability 

Determination

FO ST Pontoon Fuel Oil Tank No.1 

(P)

1,305 Diesel 0.0724 NOT APPLICABLE: Does not 

apply because capacity is 

>151m3

, but maximum TVP of 

liquid stored is <3.5 kPa. (40 

CFR 60.110b(b))

Pontoon Fuel Oil Tank No. 2 

(S)

1,305 Diesel 0.0724

Pontoon Fuel Oil Tank No. 3 

(P)

875 Diesel 0.0724

Pontoon Fuel Oil Tank No. 4 

(S)

875 Diesel 0.0724

FO SER ST Upper Hull Fuel Oil Tank No.

1 (P)

49 Diesel 0.0724 NOT APPLICABLE: Does not 

apply because capacity is 

<75m3

. (40 CFR 60.110b(a)) Upper Hull Fuel Oil Tank No. 

2 (S)

57 Diesel 0.0724

FO SET ST Upper Hull Fuel Oil Tank No. 

3 (P)

34 Diesel 0.0724

Upper Hull Fuel Oil Tank No. 

4 (S)

35 Diesel 0.0724

FO E GEN 

ST

Emergency Generator Fuel 

Oil Tank

8 Diesel 0.0724

WO ST Waste Oil Tank No. 1 (P) 35 Waste Oil 0.0724

Waste Oil Tank No. 2 (S) 35 Waste Oil 0.0724

AV ST Aviation Fuel Tank No. 1 3 Aviation Fuel 12.07

Aviation Fuel Tank No. 2 3 Aviation Fuel 12.07

Aviation Fuel Tank No. 3 3 Aviation Fuel 12.07

FO LB ST Lifeboat No. 1 Fuel Tank 0.2 Diesel 0.0724

Lifeboat No. 2 Fuel Tank 0.2 Diesel 0.0724

Lifeboat No. 3 Fuel Tank 0.2 Diesel 0.0724

Lifeboat No. 4 Fuel Tank 0.2 Diesel 0.0724

FO MOB ST Fast Rescue Boat Fuel Tank 0.2 Diesel 0.0724

FO CMV ST Cement Unit Fuel Oil Tank 2 Diesel 0.0724

Similar to the above Table 4.2-1 for the Developer, Table 4.2-2 below summarizes the subpart 

Kb applicability determinations made for the VOL storage vessels located on the Discoverer

Americas. As documented in the table, subpart Kb does not apply to any of the storage vessels

on the Discoverer Americas.

Table 4.2-2

Summary of Discoverer Americas VOL Storage Vessel Subpart Kb Applicability

Emissions 

Unit ID Description Capacity 

(m3) Service

Max 

TVP 

(kPa) Subpart Kb Applicability 

Determination

FO ST Deck 2 Fuel Oil Tank No. 1 

(P)

2,591 Diesel 0.0724 NOT APPLICABLE: Does not 

apply because capacity is 

>151m3, but max TVP of liquid 

stored is <3.5 kPa. (40 CFR 

60.110b(b))

Deck 2 Fuel Oil Tank No. 2 

(S)

2,591 Diesel 0.0724
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Regulatory Applicability 4-5 ENVIRON

Emissions 

Unit ID Description Capacity 

(m3) Service

Max 

TVP 

(kPa) Subpart Kb Applicability 

Determination

Overflow Fuel Oil Tank No. 1 

(P)

130 Diesel 0.0724 NOT APPLICABLE: Does not 

apply because capacity is >75 

m3 but <151m3, but max TVP 

of liquid stored is <15.0 kPa. 

(40 CFR 60.110b(b))

FO SET ST Deck 1 Fuel Oil Tank No. 3 

(P)

216 Diesel 0.0724 NOT APPLICABLE: Does not 

apply because capacity is 

>151m3, but max TVP of liquid 

stored is <3.5 kPa. (40 CFR 

60.110b(b))

Deck 1 Fuel Oil Tank No. 4 

(S)

216 Diesel 0.0724

FO SER ST Deck 1 Fuel Oil Tank No. 5 

(P)

108 Diesel 0.0724 NOT APPLICABLE: Does not 

apply because capacity is >75 

m3 but <151m3, but max TVP 

of liquid stored is <15.0 kPa. 

(40 CFR 60.110b(b))

Deck 1 Fuel Oil Tank No. 6 

(S)

108 Diesel 0.0724

FO E GEN 

ST

Emergency Generator Fuel 

Oil Tank

16 Diesel 0.0724 NOT APPLICABLE: Does not 

apply because capacity is 

<75m3

. (40 CFR 60.110b(a)) WO ST Waste Oil Tank No. 1 (P) 35 Waste Oil 0.0724

Waste Oil Tank No. 2 (S) 62 Waste Oil 0.0724

AV ST Aviation Fuel Tank 8 Aviation Fuel 12.07

FO LB ST Lifeboat No. 1 Fuel Tank 0.2 Diesel 0.0724

Lifeboat No. 2 Fuel Tank 0.2 Diesel 0.0724

Lifeboat No. 3 Fuel Tank 0.2 Diesel 0.0724

Lifeboat No. 4 Fuel Tank 0.2 Diesel 0.0724

Lifeboat No. 5 Fuel Tank 0.2 Diesel 0.0724

Lifeboat No. 6 Fuel Tank 0.2 Diesel 0.0724

FO MOB ST Fast Rescue Boat Fuel Tank 0.2 Diesel 0.0724

4.2.3 Subpart IIII – Standards of Performance for Stationary Compression 

Ignition Internal Combustion Engines

This subpart is applicable to manufacturers, owners, and operators of certain stationary 

compression ignition (CI) internal combustion engines. The applicability of this subpart to a 

particular CI engine is dependent on the model year, displacement, and intended use of the 

engine. For owners and operators, the emission standards of the subpart apply to the following 

four subcategories of CI engines:

• Non-emergency engines;

• Emergency (non-fire pump) engines;

• Emergency (fire pump) engines; and

• Reconstructed engines.

Excluding fire pump stationary CI engines, this subpart applies to a stationary CI engine that 

was manufactured after April 1, 2006 and for which the owner or operator commenced 
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Regulatory Applicability 4-6 ENVIRON

construction after July 11, 2005. For the purposes of this subpart, the date that construction 

commences is the date the engine is ordered by the owner or operator.

First, the life boat and fast rescue boat CI engines that are present on the Developer and 

Discoverer Americas are not subject to this regulation. As documented by EPA, life boats and 

fast rescue boats do not have stationary source aspects with respect to NOX emissions 

because they are used for man overboard and emergency escape scenarios.4

 Only the 

stationary aspects of vessels attached to an OCS are subject to stationary source regulations.

Developer

Table 4.2-3 below summarizes the engines on the Developer that are subject to subpart IIII 

because they were ordered after July 11, 2005 and manufactured after April 1, 2006.

Table 4.2-3

Summary of Developer Engines Subject to Subpart IIII

Emission 

Unit ID Model Year

Engine 

Rating

(hp)

Cylinder 

Displacement 

(L/cylinder) Engine Use

GEN-1 8/2006 6,651 17.0 Non-Emergency

GEN-2 8/2006 6,651 17.0 Non-Emergency

GEN-3 8/2006 6,651 17.0 Non-Emergency

GEN-4 8/2006 6,651 17.0 Non-Emergency

GEN-5 8/2006 6,651 17.0 Non-Emergency

GEN-6 8/2006 6,651 17.0 Non-Emergency

GEN-7 8/2006 6,651 17.0 Non-Emergency

GEN-8 8/2006 6,651 17.0 Non-Emergency

EGEN 11/2006 2,551 4.9 Emergency

CMU-1 10/2006 500 2.4 Non-Emergency

CMU-2 9/2006 500 2.4 Non-Emergency

Developer Main Generator Engines

In accordance with § 60.4204(a) of this subpart, because the eight main generator engines 

(Emission Unit IDs GEN-1 through GEN-8) are pre-2007 non-emergency CI engines with a 

displacement of greater than or equal to 10 L per cylinder and less than 30 L per cylinder, the

engines must comply with the emission standards in 40 CFR 94.8(a)(1). Based on the 

applicable emission limitation equation found in § 94.8(a)(1)(ii) and the engines having a 

maximum engine speed of 900 revolutions per minute (rpm), the eight main generator engines 

must comply with a NOX emission standard of 11.5 g/kW-hr. Each of these main engines has 

been certified with an Engine International Air Pollution Prevention (EIAPP) Certificate, which 

documents compliance with the NOX emission standard required by 40 CFR 94.8(a)(1).

 4 Final Determination and Response to Comments: Outer Continental Shelf Air Permit OCS-EPA-R4006, Shell 

Offshore, Inc.
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Regulatory Applicability 4-7 ENVIRON

In accordance with § 60.4207(b) of this subpart, because the main generator engines have a 

displacement less than 30 L per cylinder, the engines must use diesel fuel that meets the 

requirements of 40 CFR 80.510(b) for nonroad diesel. The following is a summary of the 

nonroad diesel requirements under 40 CFR 80.510(b): 15 ppm maximum sulfur content, and a 

minimum cetane index of 40 or a maximum aromatic content of 35 volume percent.

Developer Emergency Generator Engine

In accordance with § 60.4205(a) of this subpart, because the emergency generator engine 

(Emission Unit ID EGEN) is a pre-2007 non-fire pump emergency CI engine with a 

displacement less than 10 L per cylinder, the engine must comply with the following emission 

standards contained in table 1 of subpart IIII.

• CO – 11.4 g/kW-hr

• NOX – 9.2 g/kW-hr

• PM – 0.54 g/kW-hr

• HC – 1.3 g/kW-hr

The emergency generator engine has been certified as a Tier 1 engine under 40 CFR 89.112, 

meaning the engine has been certified to comply with the 9.2 g/kW-hr Tier 1 emission standard 

identified in § 89.112. Therefore, the engine is in compliance with the applicable emission 

standards of this subpart.

In accordance with § 60.4207(b) of this subpart, because the emergency generator engine has 

a displacement less than 30 L per cylinder, the engine must use diesel fuel that meets the 

requirements of 40 CFR 80.510(b) for nonroad diesel. The following is a summary of the 

nonroad diesel requirements under 40 CFR 80.510(b): 15 ppm maximum sulfur content, and a 

minimum cetane index of 40 or a maximum aromatic content of 35 volume percent.

Developer Cement Unit Engines

In accordance with § 60.4204(a) of this subpart, because the two cement unit engines 

(Emission Unit IDs CMU-1 and CMU-2) are pre-2007 non-emergency CI engines with a 

displacement less than 10 L per cylinder, the engines must comply with the following emission 

standards contained in table 1 of subpart IIII.

• CO – 11.4 g/kW-hr

• NOX – 9.2 g/kW-hr

• PM – 0.54 g/kW-hr

• HC – 1.3 g/kW-hr
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Regulatory Applicability 4-8 ENVIRON

Both cement unit engines have been certified as Tier II engines under 40 CFR 94.8, which

incorporates more stringent emission standards for this size of engine than subpart IIII.

In accordance with § 60.4207(b) of this subpart, because the cement unit engines have a 

displacement less than 30 L per cylinder, the engines must use diesel fuel that meets the 

requirements of 40 CFR 80.510(b) for nonroad diesel. The following is a summary of the 

nonroad diesel requirements under 40 CFR 80.510(b): 15 ppm maximum sulfur content, and a 

minimum cetane index of 40 or a maximum aromatic content of 35 volume percent.

Discoverer Americas

Table 4.2-4 below summarizes the engines on the Discoverer Americas that are subject to 

subpart IIII because they were ordered after July 11, 2005 and manufactured after April 1, 2006.

Table 4.2-4

Summary of Discoverer Americas Engines Subject to Subpart IIII

Emission 

Unit ID Model Year

Engine 

Rating

(hp)

Cylinder 

Displacement 

(L/cylinder) Engine Use

GEN-1 3/2008 9,387 32.2 Non-Emergency

GEN-2 3/2008 9,387 32.2 Non-Emergency

GEN-3 3/2008 9,387 32.2 Non-Emergency

GEN-4 3/2008 9,387 32.2 Non-Emergency

GEN-5 4/2008 9,387 32.2 Non-Emergency

GEN-6 4/2008 9,387 32.2 Non-Emergency

EGEN 2/2008 3,097 21.8 Emergency

ACOMP-1 1/2007 50 0.9 Emergency

ACOMP-2 1/2007 68 0.9 Emergency

Discoverer Americas Main Generator Engines

In accordance with § 60.4204(c)(1)(ii) of this subpart, because the six main engines (Emission 

Unit IDs GEN-1 through GEN-6) were installed prior to January 1, 2012 and are non-emergency 

CI engines with a displacement of greater than 30 L per cylinder and a maximum engine speed 

of 720 rpm, the engines must comply with a NOX emission standard of 12.1 g/kW-hr. 

Additionally, pursuant to § 60.4204(c)(4), PM emissions from the engines must be reduced by 

60% or more, or the engines must comply with a PM emission standard of 0.15 g/kW-hr.

In accordance with § 60.4207(d) of this subpart, because the main generator engines have a 

displacement equal to or greater than 30 L per cylinder, the engines must use diesel fuel that 

that meets a maximum per-gallon sulfur content of 1,000 ppm.

Discoverer Americas Emergency Generator Engine

In accordance with § 60.4205(b), because the emergency generator engine (Emission Unit ID 

EGEN) is a post-2007 non-fire pump emergency CI engine with a displacement of greater than 
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Regulatory Applicability 4-9 ENVIRON

or equal to 10 L per cylinder and less than 30 L per cylinder, the engine must comply with §

60.4202(e)(1) of subpart IIII, which requires the engine to meet the emission limitations for new 

marine CI engines in 40 CFR 94.8. Because the emergency generator engine is a post-2006 

model year CI engine having a displacement of greater than or equal to 20 L per cylinder and 

less than 25 L per cylinder, pursuant to § 94.8(a)(2)(i), the engine must comply with the 

following Tier 2 exhaust emission standards.

• CO – 5.0 g/kW-hr

• NOX – 9.8 g/kW-hr

• PM – 0.5 g/kW-hr

In accordance with § 60.4207(b) of this subpart, because the emergency generator engine has 

a displacement less than 30 L per cylinder, the engine must use diesel fuel that meets the 

requirements of 40 CFR 80.510(b) for nonroad diesel. The following is a summary of the 

nonroad diesel requirements under 40 CFR 80.510(b): 15 ppm maximum sulfur content, and a 

minimum cetane index of 40 or a maximum aromatic content of 35 volume percent.

Discoverer Americas Emergency Air Compressor Engines

In accordance with § 60.4205(b), because the emergency air compressor engines (Emission 

Unit IDs ACOMP-1 and ACOMP-2) are 2007 non-fire pump emergency CI engines with a 

displacement of less than 10 L per cylinder, the engines must comply with § 60.4202(a)(2) of 

subpart IIII, which requires the engines to meet the emission limitations for new nonroad CI 

engines in 40 CFR 89.112 and 40 CFR 89.113. Because the emergency air compressor 

engines are 2007 model year CI engines having a rated horsepower of greater than or equal to 

50 hp and less than 101 hp, table 1 in § 89.112(a) requires the engines to comply with the 

following Tier 2 exhaust emission standards.

• CO – 5.0 g/kW-hr

• NOX – 7.5 g/kW-hr

• PM – 0.40 g/kW-hr

Additionally, pursuant to § 89.113(a), the emergency air compressor engines are subject to the 

following exhaust opacity limits: <20% during the acceleration mode; <15% during the lugging 

mode; and <50% during the peaks in either the acceleration or lugging modes.

In accordance with § 60.4207(b) of this subpart, because the emergency air compressor 

engines have a displacement less than 30 L per cylinder, the engines must use diesel fuel that 

meets the requirements of 40 CFR 80.510(b) for nonroad diesel. The following is a summary of 

the nonroad diesel requirements under 40 CFR 80.510(b): 15 ppm maximum sulfur content, and 

a minimum cetane index of 40 or a maximum aromatic content of 35 volume percent.
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4.2.4 Subpart JJJJ – Standards of Performance for Stationary Spark Ignition 

Internal Combustion Engines

This subpart is applicable to manufacturers, owners, and operators of stationary spark ignition 

(SI) internal combustion engines. Specifically, this regulation applies to owners and operators 

of stationary SI engines that commence construction after June 12, 2006, where the engine is

manufactured:

• On or after July 1, 2007, for engines with a maximum engine power greater than or 

equal to 500 hp (except lean burn engines with a maximum engine power greater than 

or equal to 500 hp and less than 1,350 hp);

• On or after January 1, 2008, for lean burn engines with a maximum engine power 

greater than or equal to 500 hp and less than 1,350 hp;

• On or after July 1, 2008, for engines with a maximum engine power less than 500 hp; or

• On or after January 1, 2009, for emergency engines with a maximum engine power 

greater than 19 KW (25 hp).

For the purposes of this subpart, the date that construction commences is the date the engine is 

ordered by the owner or operator.

The Developer and the Discoverer Americas will not be equipped with any stationary SI

engines. Therefore, this subpart does not apply to any equipment on the vessels.

4.3 National Emission Standards for Hazardous Air Pollutants (40 CFR Part 61)

The regulations contained in 40 CFR part 61 establish emission standards for certain source

categories of HAP emissions. The emission standards under this part represent risk-based 

standards that are intended to provide an ample margin of safety to protect public health. The 

following are the HAPs regulated under this part: asbestos, benzene, beryllium, coke oven 

emissions, inorganic arsenic, mercury, radionuclides, and vinyl chloride.

4.3.1 Subpart J – National Emission Standard for Equipment Leaks (Fugitive 

Emission Sources) of Benzene

This subpart applies to each of the following sources that is intended to operate in benzene 

service: pumps, compressors, pressure relief devices, sampling connection systems, openended valves or lines, valves, connectors, surge control vessels, bottoms receivers, and control 

devices or systems required by this subpart. In benzene service means that a piece of 

equipment either contains or contacts a fluid (liquid or gas) that is at least 10 percent benzene 

by weight as determined according to the provisions of 40 CFR § 61.245(d). 

None of the types of fugitive component equipment listed above that will be located on the 

Developer or Discoverer Americas are intended to operate in benzene service. Therefore, none 

of the equipment is subject to this regulation on that basis. Additionally, note that the 

background information for this regulation indicates that the regulation applies to the petroleum 
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Regulatory Applicability 4-11 ENVIRON

refining and chemical manufacturing industries, not the activities that occur on an exploratory 

drilling vessel such as the Developer or Discoverer Americas.

4.3.2 Subpart V – National Emission Standard for Equipment Leaks (Fugitive 

Emission Sources)

This subpart applies to each of the following sources that is intended to operate in volatile 

hazardous air pollutant (VHAP) service: pumps, compressors, pressure relief devices, sampling 

connection systems, open-ended valves or lines, valves, connectors, surge control vessels, 

bottoms receivers, and control devices or systems required by this subpart. In VHAP service

means that a piece of equipment either contains or contacts a fluid (liquid or gas) that is at least 

10 percent by weight a VHAP as determined according to the provisions of § 61.245(d). A 

VHAP means a substance that is regulated under 40 CFR part 61 for which a standard for 

equipment leaks of the substance has been proposed and promulgated, such as benzene and 

vinyl chloride.

None of the types of fugitive component equipment listed above that will be located on the 

Developer or Discoverer Americas are intended to operate in VHAP service. Therefore, none of 

the equipment is subject to this regulation on that basis. Additionally, similar to the note above 

for 40 CFR part 61, subpart J, the background information for this regulation indicates that the 

regulation applies to the petroleum refining and chemical manufacturing industries, not the 

activities that occur on an exploratory drilling vessel such as the Developer or Discoverer 

Americas.

4.4 National Emission Standards for Hazardous Air Pollutants for Source 

Categories (40 CFR Part 63)

The regulations contained in 40 CFR part 63 establish emission standards for source categories 

of HAP emissions. A key component of regulatory applicability under this part is the distinction 

between a major source and an area source of HAPs. A major source is a stationary source 

that emits or has the potential to emit considering controls, in the aggregate, 10 tpy or more of 

any HAP or 25 tpy or more of any combination of HAPs. An area source is simply a source that 

is not a major source. The Developer and its associated support fleet will not have a combined 

potential to emit of 10 tpy or more of any HAP or 25 tpy or more of any combination of HAPs. 

Similarly, the Discoverer Americas and its associated support fleet will not have a combined 

potential to emit of 10 tpy or more of any HAP or 25 tpy or more of any combination of HAPs. 

Therefore, neither the Developer nor the Discoverer Americas will be a major source under this 

part. Instead, each of the drilling vessels will be an area source.

4.4.1 Subpart ZZZZ – National Emission Standards for Hazardous Air Pollutants

for Stationary Reciprocating Internal Combustion Engines

This subpart contains emission standards for stationary reciprocating internal combustion 

engines (RICE) located at major and area sources of HAP emissions.

Developer

The eight main generator engines (Emission Unit IDs GEN-1 through GEN-8), the emergency 

generator engine (Emission Unit ID EGEN), and the two cement unit engines (Emission Unit IDs 
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Regulatory Applicability 4-12 ENVIRON

CMU-1 and CMU-2) installed on the Developer are considered new RICE at an area source 

under this regulation because the engines were constructed after June 12, 2006. 

Pursuant to § 63.6590(c)(1) of this subpart, a new CI RICE located at an area source must 

comply with 40 CFR part 60, subpart IIII, and no further requirements apply for such engines 

under 40 CFR part 63. As discussed above, the noted CI engines located on the Developer are 

subject to the requirements of 40 CFR part 60, subpart IIII. Therefore, the engines will comply 

with 40 CFR part 60, subpart IIII, and they will not be subject to any further requirements under 

this subpart.

Discoverer Americas

The six main generator engines (Emission Unit IDs GEN-1 through GEN-6), the emergency 

generator engine (Emission Unit ID EGEN), and the two emergency air compressor engines

(Emission Unit IDs ACOMP-1 and ACOMP-2) installed on the Discoverer Americas are 

considered new RICE at an area source under this regulation because the engines were 

manufactured after June 12, 2006.

Pursuant to § 63.6590(c)(1) of this subpart, a new CI RICE located at an area source must 

comply with 40 CFR part 60, subpart IIII, and no further requirements apply for such engines 

under 40 CFR part 63. As discussed above, the noted CI engines located on the Discoverer 

Americas are subject to the requirements of 40 CFR part 60, subpart IIII. Therefore, the 

engines will comply with 40 CFR part 60, subpart IIII, and they will not be subject to any further 

requirements under this subpart.

4.4.2 Subpart JJJJJJ – National Emission Standards for Hazardous Air 

Pollutants for Industrial, Commercial, and Institutional Boilers Area 

Sources

This regulation establishes emission standards for HAPs emitted from boilers located at area 

sources of HAP emissions. A boiler is defined in § 63.11237 of this subpart as “an enclosed 

device using controlled flame combustion in which water is heated to recover thermal energy in 

the form of steam or hot water.”

The Hot Oil Heater (Emission Unit ID HTR) located on the Discoverer Americas does not heat 

water. Instead, the heat transfer medium used in this heater is an oil-based thermal fluid. 

Therefore, because the Hot Oil Heater (Emission Unit ID HTR) is not a “boiler” under this 

subpart, it is not subject to the subpart.

4.5 Control of Emissions from New and In-Use Nonroad Compression Ignition 

Engines (40 CFR Part 89)

40 CFR part 89 regulates emissions from all nonroad CI engines, except as specified in 40 CFR 

89.1(b). Marine engines5 subject to 40 CFR part 94 or marine engines with a rated power at or 

 5 Marine engine means a nonroad engine that is installed or intended to be installed on a marine vessel. This 

includes a portable auxiliary marine engine only if its fueling, cooling, or exhaust system is an integral part of the 

vessel. There are two kinds of marine engines: 
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Regulatory Applicability 4-13 ENVIRON

above 37 kW (50 hp) that are manufactured in calendar years in which the standards of 40 CFR 

part 94 are not yet applicable are specifically excluded from regulation under 40 CFR part 89 

per 40 CFR 89.1(b)(4)(i) and 40 CFR 89.1(b)(4)(iii), respectively.

Based on guidance provided by EPA in the preamble to 40 CFR 89,

6 whether or not a drilling rig 

is considered a marine vessel7 depends on the propulsion capabilities of the rig. The Developer

and Discoverer Americas have propulsion capabilities; therefore, these drilling vessels are 

considered marine vessels under this subpart. Furthermore, because the Developer and 

Discoverer Americas are marine vessels, the engines installed on these vessels are marine 

engines. 

The model year and engine rating information for the marine engines installed on the Developer

and Discoverer Americas and the fast rescue boats located on the Developer and Discoverer 

Americas indicate that these marine engines are subject to 40 CFR part 94. Therefore, 

pursuant to 40 CFR 89.1(b)(4)(i), the engines would not be subject to 40 CFR part 89. Based 

on a review of the engine rating information (< 37 kW) for the engines installed on the lifeboats 

located on the Developer and Discoverer Americas, these marine engines must comply with 

applicable requirements of 40 CFR part 89.

4.6 Control of Emissions from Marine Compression-Ignition Engines (40 CFR 

Part 94)

The provisions of this part apply to manufacturers (including post-manufacture marinizers and 

dressers), rebuilders, and owners and operators of CI marine engines that were manufactured 

(or that otherwise become new) on or after January 1, 2004 and that are rated at or above 37 

kW (50 hp).

The main generator, emergency generator, cement unit, and fact rescue boat engines located 

on the Developer and the main generator, emergency generator, emergency air compressor, 

and fast rescue boat engines located on the Discoverer Americas are marine engines subject to 

requirements under this part. However, in this permit application, we are addressing stationary 

source regulatory requirements only in detail. The noted main generator, emergency generator, 

cement unit, and emergency air compressor engines are considered part of a stationary source 

when the Developer and Discoverer Americas are anchored to the sea floor. The detailed 

stationary source regulatory requirements for these engines are documented in this permit 

application under the 40 CFR part 60, subpart IIII and 40 CFR part 63, subpart ZZZZ sections.

The life boat engines located on the Developer and Discoverer Americas are not subject to the 

requirements of this part because these marine engines are rated below 37 kW.

 

(1) Propulsion marine engine means a marine engine that moves a vessel through the water or directs the vessel’s 

movement.

(2) Auxiliary marine engine means a marine engine not used for propulsion. (40 CFR 94.2) 6 Control of Emissions of Air Pollution from New Marine Compression-Ignition Engines at or above 37kW; Final Rule 

(December 29, 1999)

7 Marine vessel has the meaning given in 1 U.S.C. 3, except that it does not include amphibious vehicles. The 

definition in 1 U.S.C. 3 very broadly includes every craft capable of being used as a means of transportation on water. 

(40 CFR 89.2)
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Statoil will comply with all requirements as they apply to owners and operators of engines 

regulated by 40 CFR part 94. This specifically includes the General Enforcement Provisions 

and Prohibited Acts codified in 40 CFR 94 Subpart L.

4.7 Compliance Assurance Monitoring (40 CFR Part 64)

The Compliance Assurance Monitoring (CAM) rule requires a stationary source to monitor the 

operation and maintenance of emissions control devices in order to evaluate device 

performance and to report whether a source meets established emission limitations or 

standards. The CAM rule applies to a pollutant-specific emissions unit that:

1. Is subject to an emission limitation or standard8 for an applicable regulated air pollutant 

and the emission limitation or standard is not exempt under § 64.2(b)(1) or (2);

2. Uses a control device9 to achieve compliance with the subject emission limitation or 

standard; and

3. Has pre-control device potential emissions of the applicable regulated air pollutant equal 

to or greater than 100% of the amount, in tpy, required for a source to be classified as a 

major source (e.g., 100 tpy for § 302 of the CAA, 10 or 25 tpy of HAPs for § 112 of the 

CAA).

None of the emissions units installed on the Developer or Discoverer Americas are equipped 

with a control device. Therefore, this regulation does not apply to the sources.

4.8 Chemical Accident Prevention Provisions (40 CFR Part 68)

The requirements of these regulations apply to the owners or operators of stationary sources 

that have more than a threshold quantity of a regulated substance, as determined under § 

68.115, in order to prevent the accidental release of such substances. The regulated 

substances and their associated thresholds are listed in § 68.130 of 40 CFR part 68. 

According to § 68.10(f), the provisions of this part do not apply to an “OCS source,” as this term 

is defined in 40 CFR § 55.2. Therefore, 40 CFR part 68 does not apply to the Developer or 

Discoverer Americas.

 8 Emission limitation or standard means any applicable requirement that constitutes an emission limitation, emission 

standard, standard of performance, or means of emission limitation as defined under the Act. An emission limitation 

or standard may be expressed in terms of the pollutant, expressed either as a specific quantity, rate or concentration

of emissions (e.g., lb of SO2 per hour, lb of SO2 per MMBtu of fuel input, kg of VOC per L of applied coating solids, or 

ppmv of SO2) or as the relationship of uncontrolled to controlled emissions (e.g., % capture and destruction efficiency 

of VOC or % reduction of SO2). [...] (See 40 CFR § 64.1).

9 Control device means equipment, other than inherent process equipment, that is used to destroy or remove air 

pollutant(s) prior to discharge to the atmosphere. Note that, for purposes of 40 CFR part 64, a control device does 

not include passive control measures that act to prevent pollutants from forming, such as the use of seals, lids, or 

roofs to prevent the release of pollutants, use of low-polluting fuel or feedstocks, or the use of combustion or other 

process design features or characteristics. (See 40 CFR § 64.1).
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Regulatory Applicability 4-15 ENVIRON

4.9 Protection of Stratospheric Ozone (40 CFR Part 82)

4.9.1 Subpart F – Recycling and Emissions Reduction

The purpose of this subpart is to reduce emissions of class I and class II refrigerants and their 

substitutes to the lowest achievable level by: (1) maximizing the recapture and recycling of such 

refrigerants during the service, maintenance, repair, and disposal of appliances and (2) 

restricting the sale of refrigerants consisting in whole or in part of a class I and class II ozone 

depleting substances in accordance with Title VI of the CAA. This subpart applies to any 

person servicing, maintaining, or repairing appliances, which includes air conditioners, 

refrigerators, chillers, and freezers.

Statoil will comply with all applicable provisions of this regulation as it relates to the servicing, 

maintenance, and repairing of appliances that are located on the Developer or Discoverer 

Americas and that use class I or II refrigerants.

4.10 Protection of Resources under the Endangered Species Act of 1973

The Endangered Species Act (ESA) of 1973, as amended, establishes a national policy 

designed to protect threatened and endangered species and the critical habitat upon which they 

depend. The ESA is administered by the United States Fish and Wildlife Service (FWS) and the 

National Oceanic and Atmospheric Administration’s National Marine Fisheries Service (NMFS). 

Section 7 of the ESA governs interagency cooperation and consultation. Under Section 7 of the 

ESA, federal permitting agencies consult with both the FWS and NMFS to ensure that activities 

permitted under their jurisdiction do not jeopardize the continued existence of threatened or 

endangered species and/or result in adverse modification or destruction of critical habitat.

Through a biological assessment or an informal consultation, the FWS and NMFS determine the 

effect of a proposed action on a listed species or critical habitat. If either agency determines 

that the proposed action would likely have an adverse effect on either a listed species or critical 

habitat, then a formal consultation is initiated. As a result of this process, the FWS and NMFS 

may make recommendations to revise the proposed activities in order to minimize adverse 

impacts, although it remains the responsibility of the federal permitting agency to ensure that 

proposed activities do not impact threatened and endangered species. 

In line with this process, the FWS and NMFS have been formally consulted in multiple instances 

by the United States Department of the Interior Bureau of Ocean Energy Management (BOEM), 

and historically the Minerals Management Service (MMS), for various actions in the Gulf of 

Mexico. The purpose of such consultations was to assist BOEM and MMS in the preparation of 

several EIS assessing the impacts of the Gulf of Mexico OCS Oil and Gas Leasing Program, 

which offers for lease those areas of the OCS in the Gulf of Mexico that may contain 

economically recoverable oil and gas resources. The lease sales provide qualified bidders the 

opportunity to bid upon and lease acreage in the Gulf of Mexico OCS in order to explore, 

develop, and produce oil and natural gas. The EIS that have been performed in relation to the 

Gulf of Mexico OCS Oil and Gas Leasing Program provide analysis of the potential impacts of 

the proposed actions on marine, coastal, and human environments. As such, reliance on the 

results of past FWS and NMFS consultation (as described in the EIS) for the same lease blocks 

that are covered by this permit application was deemed appropriate. The common lease blocks 
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Regulatory Applicability 4-16 ENVIRON

addressed in this permit application and the EIS referenced herein are Lease Sales 213 and 

222. Note that the EIS referenced in this section are available for review on the BOEM

webpage at:

http://www.boem.gov/Environmental-Stewardship/EnvironmentalAssessment/NEPA/nepaprocess.aspx.

4.10.1 Lease Sales 213 and 222 – Central Planning Area

The proposed exploratory drilling activities are planned to occur within Lease Sales 213 and 

222. The following two EIS document the impact reviews performed by MMS for actions within 

these areas.

• Gulf of Mexico OCS Oil and Gas Lease Sales: 2007-2012 (Western Planning Area Sales 

204, 207, 210, 215, and 218; Central Planning Area Sales 205, 206, 208, 213, 216, and 

222) Final Environmental Impact Statement, dated April 2007 (“April 2007 EIS”)

• Gulf of Mexico OCS Oil and Gas Lease Sales: 2009-2012 (Central Planning Area Sales 

208, 213, 216, and 222 Western Planning Area Sales 210, 215, and 218) Final 

Supplemental Environmental Impact Statement, dated September 2008 (“September 

2008 Supplemental EIS”)

A review of these two EIS found that the MMS consulted the NMFS and FWS on the proposed 

lease sales and associated activities to be undertaken in the Gulf of Mexico as part of the OCS

Oil and Gas Leasing Program: 2007-2012 5-Year Program (“2007-2012 OCS Leasing 

Program”). The NMFS Biological Opinion (Appendix C-1), signed on June 29, 2007, concludes 

that the proposed lease sales and associated activities related to the 2007-2012 OCS Leasing 

Program are not likely to jeopardize the continued existence of threatened and endangered

species under NMFS jurisdiction, or destroy or adversely modify designated critical habitat. The 

NMFS issued an Incidental Take Statement within the Biological Opinion, which contains 

reasonable and prudent measures with implementing terms and conditions to help minimize 

take. These terms and conditions are specifically relevant to seismic operations, airborne and 

waterborne vessel collisions, and exposure to spilled oil.

The MMS engaged in informal consultation with the FWS and prepared and submitted a

Biological Assessment (Appendix C-2) in relation to the 2007-2012 OCS Leasing Program. On 

September 14, 2007, the FWS submitted a Letter of Concurrence regarding the Biological 

Assessment (Appendix C-3). The FWS concurred with the MMS determination that proposed 

actions of the 2007-2012 OCS Leasing Program were not likely to adversely affect threatened 

or endangered species or designated critical habitat under FWS jurisdiction.

The Biological Assessment prepared by MMS analyzed a typical year of OCS activity rather 

than a typical lease sale (and, with regard to the Supplemental EIS included the 181 South 

Area, within which several proposed locations within this application lie). Therefore, MMS is to 

request concurrence letters annually from the NMFS and FWS to determine whether the 

information and analyses in the Biological Assessment and the associated consultations under 

the ESA are still valid. According to the September 2008 Supplemental EIS, the most recent 
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written concurrence with the previously submitted Biological Assessment was submitted by 

NMFS on July 24, 2008. Additionally, a copy of the July 30, 2008 concurrence is provided in 

Appendix C-4.

Following the Deepwater Horizon oil spill in 2010 and the subsequent reorganization of MMS, 

the NMFS reinitiated ESA consultation of the effects of the 2007-2012 OCS Leasing Program

on ESA-listed species and designated critical habitats. A January 24, 2011 letter from NMFS to 

EPA (Appendix C-5) confirms that air emissions from OCS oil and gas exploration activities

were included in the NMFS Biological Opinion and reinitiating the ESA consultation does not 

pertain to air emissions from lease sale activities.

Statoil contacted the BOEM to request a list of any additional listings of endangered species or 

critical habitats since the prior ESA consultations in 2007-2008. BOEM’s response (Appendix 

C-6) indicates that no new species or habitats have been listed.

4.11 Emissions Sampling Ports, Continuous Monitoring Systems, and Source 

Testing Plan 

EPA Region 4 indicates that a complete PSD permit application for an OCS source should 

provide a “description of all emission sampling ports, continuous monitoring systems, and 

proposed source testing plan.”

10 Statoil retains the Developer and Discoverer Americas and 

associated support fleet vessels on lease agreement. The drilling and support vessels are 

equipped with numerous diesel engines, and Statoil is not aware of specific emissions sampling 

ports or continuous emissions monitoring systems that may already be in place for these 

engines. Additionally, Statoil is not proposing to perform any source emissions testing on the 

Developer and Discoverer Americas, so we have not included a source testing plan with this 

permit application. 

 10 Prevention of Significant Deterioration Permit Application Requirements EPA Region 4, Updated February 2010. 

http://www.epa.gov/region4/air/permits/ocspermits/PSDApplicationGuidelinesR4.pdf